Report on Outages and Curtailments During the Southwest Cold 

Weather Event of February 1-5, 2011 

Prepared by the Staffs of the Federal Energy Regulatory 

Commission and the North American Electric Reliability 

Corporation 

Causes and Recommendations 

August 2011 

FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

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Table of Contents 

I. Introduction..................................................................1 

II. Executive Summary.....................................................7 

III. The Electric and Natural Gas Industries.................13 

IV. Preparations for the Storm.......................................49 

V. The Event: Load Shed and Curtailments................73 

VI. Causes of the Outages and Supply Disruptions....139 

VII. Prior Cold Weather Events.....................................169 

VIII. Electric and Natural Gas Interdependencies........189 

IX. Key Findings and Recommendations.....................195 
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ATTACHMENTS 

Acronyms 

Glossary 

Appendices

Task Force Members 

 Legislative and Regulatory Responses by the States 

Categories of NERC Registered Entities 

Electricity: How it is Generated and Distributed 

Power Plant Design for Ambient Weather Conditions 

Impact of Wind Chill 

Winterization for Generators 

Natural Gas: Production and Distribution 

Natural Gas Storage 

Natural Gas Transportation Contracting Practices 

GTI: Impact of Cold Weather on Gas Production 
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I. Introduction 

 The southwest region of the United States experienced unusually cold and 

windy weather during the first week of February 2011. Lows during the period 

were in the teens for five consecutive mornings and there were many sustained 

hours of below freezing temperatures throughout Texas and in New Mexico. Low 

temperatures in Albuquerque, New Mexico ranged from 7 degrees Fahrenheit to -7 

degrees over the period, compared to an average high of 51 degrees and a low of 

26 degrees. Dallas temperatures ranged from 14 degrees to 19 degrees, compared 

to an average high of 60 degrees or above and average lows in the mid-to-upper 

30s. Many cities in the region would not see temperatures above freezing until 

February 4. In addition, sustained high winds of over 20 mph produced severe 

wind chill factors. 

 Electric entities located within the Texas Reliability Entity, Inc. (TRE), the 

Western Electricity Coordinating Council (WECC), and the Southwest Power Pool 

(SPP) were affected by the extreme weather, as were gas entities in Texas, New 

Mexico and Arizona. 

 Between February 1 and February 4, a total of 210 individual generating 

units within the footprint of the Electric Reliability Council of Texas, Inc. 

(ERCOT), which covers most of Texas, experienced either an outage, a derate, or 

a failure to start. The loss of generation was severe enough on February 2 to 

trigger a controlled load shed of 4000 MW, which affected some 3.2 million 

customers. On February 3, local transmission constraints coupled with the loss of 

local generation triggered load shedding for another 180,000 customers in the Rio 

Grande Valley in south Texas. El Paso Electric Company (EPE), which is outside 

the ERCOT region, lost approximately 646 MW of local generation over the four 

days beginning on February 1. It implemented rotating load sheds on each of the 

days from February 2 through February 4, totaling over 1000 MW and affecting 

253,000 customers. The Salt River Project Agricultural Improvement and Power 

District (SRP), located in Arizona, lost 1050 MW of generation on February 1 

through February 2 and shed load of 300 MW, affecting approximately 65,000 

customers. The New Mexico communities of Alamogordo, Ruidoso, and Clayton 

lost approximately 26 MW of load, affecting a little over 21,000 customers, when 

Public Service Company of New Mexico (PNM) experienced localized 

transmission failures, although these were largely unrelated to the extreme 

weather. 

 In total, approximately 1.3 million electric customers were out of service at 

the peak of the event on February 2, and a total of 4.4 million were affected over 

the course of the event from February 2 through February 4. 
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 Natural gas customers also experienced extensive curtailments of service 

during the event. These curtailments were longer in duration than the electric 

outages, because relighting customers’ equipment has to be accomplished 

manually at each customer’s location. Local distribution companies (LDCs) 

interrupted gas service to more than 50,000 customers in New Mexico, Arizona 

and Texas; New Mexico was the hardest hit with outages of over 30,000 

customers in areas as widespread as Hobbs, Ruidoso, Alamogordo, Silver City, 

Tularosa, La Luz, Taos, Red River, Questa, Española, Bernalillo and Placitas. 

 In the wake of these events, the Arizona Corporation Commission, the 

Public Regulation Commission of New Mexico, the Public Utilities Commission 

of Texas (PUCT), the Texas Railroad Commission (TRC), the New Mexico state 

legislature and the Texas state legislature all initiated inquiries or investigations. 

The PUCT directed TRE, the regional entity authorized by the North American 

Electric Reliability Corporation (NERC) to cover the ERCOT region, to 

investigate the decisions and actions ERCOT took in initiating the rolling 

blackouts. 

 

On February 7, 2011, NERC announced that it would work with the 

affected Regional Entities to prepare an event analysis that would examine the 

adequacy of preparations for the event and identify potential improvements and 

lessons learned. NERC also stated it would review electric and natural gas 

interdependencies, in light of the shift toward a greater reliance on natural gas to 

produce electricity. 

 On February 14, the Federal Energy Regulatory Commission (FERC) 

initiated an inquiry into the Southwest outages and service disruptions. The 

inquiry had two objectives: to identify the causes of the disruptions, and to identify 

any appropriate actions for preventing a recurrence of the disruptions. FERC 

stated it was not at that time initiating an investigation into whether there may 

have been violations of applicable regulations, requirements or standards under 

FERC’s jurisdiction, and that any decisions on whether to initiate enforcement 

investigations would be made later. Consequently, while this report describes 

actions which in some cases appear to warrant further investigation, it does not 

reach any conclusions as to whether violations have occurred. 

 From the beginning of their inquiries into the causes of the outages and 

disruptions, the staffs of FERC and NERC have cooperated in their data gathering 

and analysis. On May 9, FERC and NERC announced their staffs would create a 

joint task force to combine their separate inquiries. This report is a product of that 

effort. 
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 The inquiry performed by the joint task force was far-reaching. Noted 

below in summary form are some of the steps taken by the task force to develop its 

understanding of the electric and natural gas disruptions that were experienced in 

the Southwest in early February. 

Scope of Data Reviewed 

The task force received approximately 54 GB of data through data requests 

issued to entities in both the electric and natural gas industries, conducted 

numerous follow-up calls and meetings, and issued follow-up requests to discuss 

questions raised by the data responses. 

For the electric industry, the task force issued 122 data requests to 

generator operators, transmission operators, balancing authorities, and a reliability 

coordinator. The task force also utilized event analysis information which NERC 

and the affected Regional Entities received from 79 registered entities (72 from 

TRE, four from WECC and three from SPP). Additional event information was 

received through a request for information issued by NERC and Regional Entities 

to those entities affected by the extreme weather event. For the gas industry, the 

task force issued 92 data requests to pipelines (interstate and intrastate), storage 

facilities, gas processing plants, producers, and public utilities. 

 The data compiled by the task force focused on the causes of the outages 

and curtailments during the February cold weather event, critical entities’ 

preparations for the forecasted cold weather and their performance in connection 

with the rolling blackouts and natural gas curtailments, and any lessons learned 

that could be applied in the future. As part of its analysis, the task force also 

reviewed historical data and recommendations compiled during past cold weather 

events in Texas and elsewhere in the Southwest, to determine whether the 2011 

event was unprecedented or whether entities might have been better prepared to 

deal with it. 

Electric Facility Site Visits 

Staff from FERC and NERC, together with representatives of TRE and 

WECC, conducted site visits with various entities involved in the outages, toured 

facilities and conducted interviews with operations personnel, compliance 

personnel and company executives. The task force visited ERCOT, four 

transmission operators in ERCOT, and 15 generators in ERCOT (including coal, 

natural gas, and wind units); two generators in WECC; and two balancing 

authorities in WECC. During the generator site visits the task force toured the 

units, viewing any equipment that led to trips, derates, or failures to start; viewed 

winterization measures; and discussed maintenance and winterization processes, 
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fuel supply and market participation. During visits to the balancing authorities 

and transmission operators, the task force toured control centers and discussed the 

progression of the events, including specifics on load forecasting, market 

mechanics, system operations, load shedding and load restoration. The task force 

also discussed transmission system winterization and load shedding procedures 

with the transmission operators. 

Natural Gas Meetings 

The task force conducted numerous meetings with various entities from the 

gas industry to discuss the curtailments and shortages experienced in early 

February and the specifics of the entities’ winter operations. These meetings 

included operations and regulatory personnel from two interstate pipelines doing 

business in Texas, New Mexico, Arizona, Colorado, and California; one 

LDC/intrastate pipeline located in New Mexico; one LDC from Arizona; and one 

intrastate pipeline located in Texas. The meetings focused on the companies’ 

preparations for the storm, communications among LDCs, pipelines, marketers, 

and producers about unfolding events, system operations, underlying causes of the 

gas supply problems, and lessons learned. In most instances, interviews led to 

supplemental data requests that provided additional information about the events. 

The task force also held numerous telephone conferences with companies in the 

pipeline, LDC, processing and production sectors, both to gather information and 

to clarify information received in response to data requests. 

Outreach Meetings 

Task force staff conducted outreach meetings with the following industry 

associations and groups: the Electric Power Supply Association, the American Gas 

Association, the Independent Petroleum Association of America, the Texas 

Pipeline Association, the Interstate Natural Gas Association of America, the 

Natural Gas Supply Association, the Edison Electric Institute, the National Rural 

Electric Cooperative Association, the American Public Power Association, and the 

(ERO) Southwest Outage Advisory Panel. The task force shared its preliminary 

findings and recommendations on a non-public basis with members of these 

organizations in order to obtain feedback and, with respect to the 

recommendations, input as to their practicality and feasibility. The feedback and 

input provided by these organizations was considered and in a number of instances 

reflected in the findings and recommendations included in this report. 

Coordination with State Inquiries 

The task force also reviewed materials acquired in the course of inquiries 

into the event conducted by legislative bodies and regulatory commissions. The 
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task force followed legislative and regulatory hearings in Arizona, New Mexico 

and Texas and reviewed transcripts, testimony and webcasts from the proceedings. 

 

Through contacts with state regulatory agencies, staff was able to review 

responses to data requests issued by those bodies to ensure that the task force was 

in possession of all potentially relevant materials. Task force staff also monitored 

legislative efforts taken in response to the February outage, including conferring 

with sponsors of pertinent legislation concerning, among other things, the 

anticipated impacts of their proposals. The task force tracked the bills throughout 

the legislative process. In addition, as regulatory agencies moved forward with 

their inquiries into the outage, task force staff reviewed draft and final copies of all 

relevant reports. 

The task force also collaborated with ERCOT’s Independent Market 

Monitor (IMM), which conducted an inquiry into potential market manipulation 

during the event at the request of the PUCT. Task force staff conducted calls with 

the IMM to discuss market conditions and reviewed its written assessment of the 

market impacts from the event. The task force also contacted the TRC regarding 

gas curtailment matters, submitted written questions about the TRC’s activities in 

connection with the event, and reviewed all information the TRC collected 

concerning the event. 

To assist in its analysis of the materials received, the task force 

commissioned one outside consultant’s study to examine impacts of the cold 

weather event on gas production, reviewed studies conducted on behalf of 

regulatory and other bodies, and prepared extensive in-house studies by staff 

analysts. 

This report documents the information received by the task force and 

presents the task force’s conclusions as to the causes of the electric outages and 

natural gas curtailments that occurred during the February 2011 event. It is 

divided into several sections, beginning with an overview of the electric and 

natural gas industries that provides background for the event, discusses the event 

itself and prior cold weather events in the region, and ends with a summary of key 

findings and recommendations. Also included are a list of acronyms, a glossary, 

and a number of appendices which treat in fuller detail many of the matters 

mentioned in the body of the report. 
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II. Executive Summary 

 The arctic cold front that descended on the Southwest during the first week 

of February 2011 was unusually severe in terms of temperature, wind, and 

duration of the event. In many cities in the Southwest, temperatures remained 

below freezing for four days, and winds gusted in places to 30 mph or more. The 

geographic area hit was also extensive, complicating efforts to obtain power and 

natural gas from neighboring regions. 

 The storm, however, was not without precedent. There were prior severe 

cold weather events in the Southwest in 1983, 1989, 2003, 2006, 2008, and 2010. 

The worst of these was in 1989, the prior event most comparable to 2011. That 

year marked the first time ERCOT resorted to system-wide rolling blackouts to 

prevent more widespread customer outages. In all of those prior years, the natural 

gas delivery system experienced production declines; however, curtailments to 

natural gas customers in the region were essentially limited to the years 1989 and 

2003. 

Electric

 Going into the February 2011 storm, neither ERCOT nor the other electric 

entities that initiated rolling blackouts during the event expected to have a problem 

meeting customer demand. They all had adequate reserve margins, based on 

anticipated generator availability. But those reserves proved insufficient for the 

extraordinary amount of capacity that was lost during the event from trips, derates, 

and failures to start. 

 

 In the case of ERCOT, where rolling blackouts affected the largest number 

of customers (3.2 million), there were 3100 MW of responsive reserves available 

on the first day of the event, compared to a minimum requirement of 2300 MW. 

But over the course of that day and the next, a total of 193 ERCOT generating 

units failed or were derated, representing a cumulative loss of 29,729 MW. 

Combining forced outages with scheduled outages, approximately one-third of the 

total ERCOT fleet was unavailable at the lowest point of the event. These 

extensive generator failures overwhelmed ERCOT’s reserves, which eventually 

dropped below the level of safe operation. Had ERCOT not acted promptly to 

shed load, it would very likely have suffered widespread, uncontrolled blackouts 

throughout the entire ERCOT Interconnection. 

 ERCOT also experienced generator outages in the Rio Grande Valley on 

February 3, again due to the cold weather. This area is transmission constrained, 
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and the loss of local generation led to voltage concerns that necessitated localized 

load shedding. 

 Spot prices in ERCOT hit the $3,000 per MWh cap on February 2, the 

worst day of the event. Given the high demand and the huge loss of generation, 

this was not a surprising development. In fact, very high prices are an expected 

response to scarcity conditions, one that is built into ERCOT’s energy-only 

market. ERCOT’s IMM reviewed market performance during the event and found 

no evidence of market manipulation. 

 EPE and SRP likewise suffered numerous generator outages, necessitating 

load shed of 1023 MW in EPE’s case, and 300 MW in SRP’s case. As with 

ERCOT, many of these generators failed because of weather-related reasons. 

 A number of entities within SPP also experienced outages during the event. 

In their case, however, load shedding was not required, principally because the 

utilities were able to purchase emergency energy from other SPP members. One 

other utility in the Southwest, PNM, experienced blackouts, but these were 

localized and the result of transmission outages that were mostly unrelated to the 

weather. 

 The actions of the entities in calling for and carrying out the rolling 

blackouts were largely effective and timely. However, the massive amount of 

generator failures that were experienced raises the question whether it would have 

been helpful to increase reserve levels going into the event. This action would 

have brought more units online earlier, might have prevented some of the freezing 

problems the generators experienced, and could have exposed operational 

problems in time to implement corrections before the units were needed to meet 

customer demand. 

 The February event underscores the need to have sufficient black start units 

available, particularly in the face of an anticipated severe weather event. In 

ERCOT’s case, for instance, nearly half of its black start units were either on 

scheduled outage at the time of the event or failed during the event itself, 

jeopardizing the utility’s ability to promptly restore the system had an 

uncontrolled, ERCOT-wide blackout occurred. 

 The majority of the problems experienced by the many generators that 

tripped, suffered derates, or failed to start during the event were attributable, either 

directly or indirectly, to the cold weather itself. For the Southwest as a whole, 67 

percent of the generator failures (by MWh) were due directly to weather-related 

causes, including frozen sensing lines, frozen equipment, frozen water lines, 

frozen valves, blade icing, low temperature cutoff limits, and the like. At least 
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another 12 percent were indirectly attributable to the weather (occasioned by 

natural gas curtailments to gas-fired generators and difficulties in fuel switching). 

 Low temperatures returned to the region on February 10. In fact, ERCOT 

set a new winter peak that day. But no load shedding proved necessary, largely 

because the temperatures were not quite as cold or sustained as those of the 

previous week, the winds were less severe, and many of the repairs and protective 

measures taken by the generators on February 2 remained in place. 

Natural Gas

 Problems on the natural gas side largely resulted from production declines 

in the five basins serving the Southwest. For the period February 1 through 

February 5, an estimated 14.8 Bcf of production was lost. These declines 

propagated downstream through the rest of the gas delivery chain, ultimately 

resulting in natural gas curtailments to more than 50,000 customers in New 

Mexico, Arizona, and Texas. 

 The production losses stemmed principally from three things: freeze-offs, 

icy roads, and rolling electric blackouts or customer curtailments. Freeze-offs 

occurred when the small amount of water produced alongside the natural gas 

crystallized or froze, completely blocking off the gas flow and shutting down the 

well. Freeze-offs routinely occur in very cold weather, and affected at least some 

of these basins in all of the six recent cold weather events in the Southwest with 

the possible exception of 1983, for which adequate records are not available. 

During the February event, icy roads prevented maintenance personnel and 

equipment from reaching the wells and hauling off produced water which, if left in 

holding tanks at the wellhead, causes the wells to shut down automatically. The 

ERCOT blackouts or customer curtailments affected primarily the Permian and 

Fort Worth Basins and caused or contributed to 29 percent (Permian) and 27 

percent (Fort Worth) of the production outages, principally as a result of shutting 

down electric pumping units or compressors on gathering lines. 

 Processing plants suffered some mechanical failures, although most of their 

shortfalls resulted from problems upstream at the wellhead. The production 

declines, coupled with increased customer demand, reduced gas volume and 

pressure in the pipelines and in those limited storage facilities serving the 

Southwest. These entities in turn were unable in some instances to deliver 

adequate gas supplies to LDCs. 

 When LDCs suffer declines in gas pressure on their systems, they must 

reduce the amount of gas being consumed to prevent pressures from falling so low 

that their entire systems might fail. As a result of the high gas demand and the 
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falling pressures on their systems, four LDCs in New Mexico, Arizona and Texas 

were forced to curtail retail service or were unable to supply gas to all customers. 

These curtailments or outages affected more than 50,000 customers in those states, 

including the cities of El Paso in Texas; Tucson and Sierra Vista in Arizona; and 

Hobbs, Ruidoso, Alamogordo, Silver City, Tularosa, La Luz, Taos, Red River, 

Questa, Española, Bernalillo, and Placitas in New Mexico. In contrast to the 

relative ease of restoring electric service, restoration of gas service was 

complicated by the necessity to have LDC crews manually shut off gas meters and 

then relight pilot lights on site. 

Winterization

 Generators and natural gas producers suffered severe losses of capacity 

despite having received accurate forecasts of the storm. Entities in both categories 

report having winterization procedures in place. However, the poor performance 

of many of these generating units and wells suggests that these procedures were 

either inadequate or were not adequately followed. 

The experiences of 1989 are instructive, particularly on the electric side. In 

that year, as in 2011, cold weather caused many generators to trip, derate, or fail to 

start. The PUCT investigated the occurrence and issued a number of 

recommendations aimed at improving winterization on the part of the generators. 

These recommendations were not mandatory, and over the course of time 

implementation lapsed. Many of the generators that experienced outages in 1989 

failed again in 2011. 

 On the gas side, producers experienced production declines in all of the 

recent prior cold weather events. While these declines rarely led to any significant 

curtailments, electric generators in 2003 did experience, as a result of gas 

shortages, widespread derates and in some cases outright unit failure. It is 

reasonable to assume from this pattern that the level of winterization put in place 

by producers is not capable of withstanding unusually cold temperatures. 

 While extreme cold weather events are obviously not as common in the 

Southwest as elsewhere, they do occur every few years. And when they do, the 

cost in terms of dollars and human hardship is considerable. The question of what 

to do about it is not an easy one to answer, as all preventative measures entail 

some cost. However, in many cases, the needed fixes would not be unduly 

expensive. Indeed, many utilities have already undertaken improvements in light 

of their experiences during the February event. This report makes a number of 

recommendations that the task force believes are both reasonable economically 

and which would substantially reduce the risk of blackouts and natural gas 

curtailments during the next extreme cold weather event that hits the Southwest. 
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Electric and Gas Interdependency

 The report also addresses the interdependency of the electric and natural 

gas industries. Utilities are becoming increasingly reliant on gas-fired generation, 

in large part because shale production has dramatically reduced the cost of gas. 

Likewise, compressors used in the gas industry are more likely than in the past to 

be powered with electricity, rather than gas. As a result, deficiencies in the supply 

of either electricity or natural gas affect not only consumers of that commodity, 

but of the other commodity as well. 

 Gas shortages were not a significant cause of the electric generator outages 

experienced during the February 2011 event, nor were rolling blackouts a primary 

cause of the production declines at the wellhead. Both, however, contributed to 

the problem, and in the case of natural gas shortfalls in the Permian and Fort 

Worth Basins, approximately a quarter of the decline was attributed to rolling 

blackouts or customer curtailments affecting producers. 

 The report explores some of the issues relating to the effects of shortages of 

one commodity on the other, including the question of whether gas production and 

processing facilities should be deemed “human needs” customers and thus 

exempted or given special consideration for purposes of electric load shedding. 

However, any resolution of the many issues arising from electric and natural gas 

interdependency must be informed by an examination of more than one cold 

weather event in one part of the country. For that reason, the report does not offer 

specific recommendations in this area, but urges regulatory and industry bodies to 

explore solutions to the many interdependency problems which are likely to 

remain of concern in the future. 
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III. The Electric and Natural Gas Industries 

 Electricity and natural gas are two of the most essential commodities for the 

conduct of modern life. However, the industries that produce electricity and 

natural gas and deliver these commodities from their points of production to 

consumers differ greatly from one another, as do the regulatory schemes 

governing them. This section provides an overview of the electric and natural gas 

industries, their market structures, and the regulatory authorities under which they 

operate, focusing particularly on the southwest region of the country. This 

background will be useful in understanding the causes of the outages and 

curtailments experienced during the first week of February 2011, the actions taken 

by the entities affected, and the recommendations the task force is suggesting to 

prevent a recurrence of the widespread service disruptions. 

A. The Electric Industry

 This subsection describes the structures under which electricity is generated 

and transmitted, the regulation of electric service providers, and the characteristics 

of the electricity markets found in the Southwest. A more detailed description of 

how electricity is produced, transmitted and delivered can be found in the 

appendix entitled “Electricity: How it is Generated and Distributed.” 

Overview of Electric Power Production and Delivery

The electric power industry is comprised of three separate functions: 

generation, transmission, and distribution. These are depicted in the figure below. 

Most of the power produced in the United States uses coal, natural gas, or 

nuclear fission as the energy source to produce steam or other hot combustion gas 

that turns a turbine and thereby creates electricity. The figure below shows the 

fuel source percentages for electricity produced in the US in 2009, with the 

majority of electricity coming from fossil fuels (coal and natural gas totaling a 68 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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percent share). While wind and solar energy have experienced fairly rapid growth 

over the past several years, renewable fuels (including hydroelectric generation’s 

seven percent share) accounted for about 11 percent of the electricity generated in 

the United States in that year. Wind generation is more common in the Southwest 

than in most other regions; its share of total generation is about 3.8 percent.1

 

Generating units typically fall into three categories: base load, intermediate, 

and peaking units. Base load units, usually coal-fired or nuclear, have a relatively 

low operating cost and have fairly slow or expensive ramping rates.2

 These units 

are seldom cycled on and off, and are instead scheduled to cover the base levels of 

projected load. Peaking units, which are generally gas-fired, can be started up 

very quickly and have relatively expensive operating costs. Accordingly, they are 

generally last in the dispatch order and are used to cover seasonal (and sometimes 

daily) peak load levels. Intermediate plants fall somewhere in between base load 

and peaking with respect to operating characteristics, start-up times, and capacity 

factors.3

 

Generating plants produce power at a relatively low voltage level, so the 

power must be “stepped up” to a higher voltage in order to be more efficiently 

 1

 United States Energy Information Administration (EIA), Electric Power Monthly, Table 

6 - Total Renewable Net Generation by Energy Source and State, 2009 (released August 2010) 

and Electric Power Annual, Figure 2.1 – U.S. Electric Industry Net Generation by State, 2009 

(released November 2010, revised January and April 2011). 

2

 “Ramping” refers to the generator’s ability to produce more or less power on request. 

3

 “Capacity factor” refers to the ratio of average generation to the capacity rating of an 

electric generating unit for a specified period (expressed as a percentage). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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transmitted to its ultimate point of use. Energy is carried at these higher voltages 

over transmission lines (usually between 138 kV and 765 kV) to load centers, 

where voltage is then stepped back down to a distribution level for delivery to enduse customers. While distribution lines are generally considered to be those 

operating at 69 kV and below,4

 some industrial end-use customers may take 

service at transmission-level or intermediate-level voltages. 

Virtually all of the transmission system in the continental United States is 

operated as an alternating current (AC) system, although the West and a few other 

areas make use of some direct current (DC) lines for long-haul transportation of 

power or for system stability. DC ties are also used to provide limited 

connectivity between the three electrically independent grids currently found in 

the United States: (1) the Eastern Interconnection, which covers the eastern twothirds of the United States and contiguous parts of Canada; (2) the Western 

Interconnection, which covers the western third of the United States, the Canadian 

provinces of Alberta and British Columbia, and a small portion of Baja California 

Norte, Mexico; and (3) ERCOT, which covers most of the state of Texas. (A 

fourth interconnection, the Quebec Interconnection, is located wholly in Canada.) 

 4

 The bulk electric system, which constitutes transmission as opposed to distribution, has 

been described by FERC as those facilities operating at 100 kV or above except for defined radial 

facilities, with exemptions for those facilities not necessary for operating the interconnected 

transmission network. Revision to Electric Reliability Organization Definition of Bulk Electric 

System, Order No. 743, 75 Fed. Reg. 72,910 (Nov. 26, 2010), 133 FERC ¶ 61,150 (2010), order 

on reh’g, Order No. 743-A, 134 FERC ¶ 61,210 (2011). 
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 Within each interconnection, power generally flows freely across the entire 

grid. An imbalance of generation versus demand that is significant enough to 

cause instability on one utility’s system can ultimately affect the stability of all 

systems operating in that interconnection.5

Evolution and Regulation of the Electric Industry 

Under part II of the Federal Power Act,6

 FERC has jurisdiction over the 

rates, terms and conditions of wholesale sales of electric energy and transmission 

services in interstate commerce that are provided by jurisdictional entities (which 

generally excludes electric cooperatives and federal or state entities, including 

municipal utilities). Notably, wholesale electric energy sales and transmission 

services provided wholly within ERCOT are not considered to be interstate under 

the Federal Power Act, and are therefore not subject to FERC jurisdiction. States 

generally regulate retail sales of electric energy and distribution services, although 

publicly-owned and member-owned entities (such as electric cooperatives and 

municipal utilities) may be exempt from direct state regulatory oversight. In 

Texas, the PUCT exercises jurisdiction over wholesale sales of energy and the 

provision of transmission services wholly within the ERCOT footprint. 

Historically, all three of the electric sector functions (generation, 

transmission, and distribution) were provided by one vertically-integrated utility, 

which was typically granted a monopoly franchise by states to serve retail 

customers within a given geographic area. While wholesale sales or exchanges of 

electric energy did occur between utilities, utilities historically planned their 

systems, both generation and transmission, to serve their own native peak load 

requirements. 

Entities Providing Electric Services in the United States 

The electric sector in the United States is made up of a variety 

of entities, including investor-owned utilities, publicly-owned 

utilities (including municipal utilities, public utility districts, 

and irrigation districts), member-owned utilities (generally 

rural electric cooperatives), Federal electric utilities, and 

(cont’d) 

 5

 See generally 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 at 5-

10 (April 2004) (2003 Blackout Report), available at http://www.ferc.gov/industries/electric/ 

indus-act/reliability/blackout.asp#skipnav (last visited Aug. 2, 2011). 

 6

 16 U.S.C. § 824 et seq. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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independent power producers. Investor-owned utilities 

(IOUs) are private entities that were historically verticallyintegrated, i.e., owning generation, transmission and 

distribution assets. However, in states with restructured 

electric markets, many IOUs were required or strongly 

incentivized to divest or spin-off their generation assets, and 

now own only transmission and distribution assets as part of 

the utility company. Based on 2007 data from the United 

States Energy Information Administration, IOUs serve about 

71 percent of the retail customers in the country. Publiclyowned electric utilities and electric cooperatives have 

generally been exempted from state restructuring initiatives, 

and have not been required to offer customer choice or to 

divest generation assets. There are approximately 2,000 

publicly-owned utilities in the United States (which own 

about 9 percent of the installed generating capacity) and over 

880 electric cooperatives (which own approximately 4 

percent of the installed capacity). 

Since the 1970s, a number of changes occurred to alter this traditional, 

vertically-integrated model. In 1978, Congress created a class of non-utility 

generators called qualifying facilities (QFs), and in 1992 created a class of 

independent generators called Exempt Wholesale Generators. This legislation 

opened the door not only for independent owners to develop generating plants in 

multiple regions, but also for utilities to develop generating plants in regions 

outside their service territory.7

FERC took a number of steps to further encourage the development of a 

competitive wholesale market for generation, including by (1) authorizing 

generation owners to sell wholesale power at market rates if they can demonstrate 

that they lacked market power in the relevant market; and (2) requiring 

transmitting utilities to provide open access transmission service for the delivery 

of power to wholesale customers on terms and conditions comparable to the 

transmission service the utilities provided themselves in serving their native load 

customers.8

 7 Energy Policy Act of 1992, Pub. L. No. 102, 486. 

8

 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and 

Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), order on reh’g, 

Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 

61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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FERC also encouraged the formation of Independent System Operators 

(ISOs)9

 and Regional Transmission Organizations (RTOs).10 ISOs/RTOs serve a 

number of functions critical to operation of the wholesale market within a given 

region, including control and operation of the transmission grid, operation of realtime and day-ahead markets, and transmission system planning.11 Not all regions 

in the United States have adopted an ISO/RTO structure, although they may rely 

on other power pool structures. The map below shows the footprint of the nine 

ISOs or RTOs currently operating in the US and Canada. 

 

sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), 

aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002) (Order No. 888). 

9 ISOs grew out of Order No. 888, issued in 1996, as a means of satisfying FERC’s 

requirement that jurisdictional utilities provide non-discriminatory access to transmission 

services. Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,730; and Regional Transmission 

Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 

2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 of 

Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 

10 In 1999, as part of Order No. 2000, FERC created and sought to encourage the 

voluntary formation of Regional Transmission Organizations to oversee electric transmission and 

ancillary services and transmission planning services across a broader territory. ISOs and RTOs 

perform similar functions, but RTOs are only recognized as such if they meet FERC’s minimum 

characteristics and minimum functions as set out in Order No. 2000. In addition, ISOs tend to be 

smaller in geographic size, or are not subject to FERC jurisdiction. See “The Value of 

Independent Regional Grid Operators: A Report by the ISO/RTO Council,” available at

<http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/ 

Value_of_Independent_Regional_Grid_Operators.pdf>. Order 2000: Regional Transmission 

Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 

2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 of 

Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 

11 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,730 (1996). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Regional Transmission Organizations/Independent System Operators

In markets where an ISO/RTO has been approved, the ISO/RTO is 

generally responsible for dispatching generating units based on hourly energy 

prices offered by the generation owner or other energy marketer. Initially, these 

competitive wholesale markets were structured to reflect only energy products and 

ancillary services,12 with no compensation for the provision of capacity13 and no 

corresponding obligation on the part of generators to offer into a specific market.14 

Many of the markets have undergone modifications over time, including 

 12 Ancillary services support the reliable operation of the transmission system as it moves 

electricity from generating sources to retail customers, and in RTO or ISO-based markets are 

generally procured through a mechanism or market separate from the energy market. Ancillary 

services typically include regulation, synchronized or spinning reserves, non-spinning reserves, 

and black-start services. Among ERCOT’s various categories of ancillary services are responsive 

reserve service (RRS) and non-spinning reserve service (NSRS). RRS are operating reserves 

intended to help control the frequency of the system. NSRS are reserves intended to cover the 

uncertainties in forecasting load and wind power output. 

13 Capacity (or installed capacity) refers in this context to the maximum kW or MW of 

output offered into a capacity market and required to be available except as otherwise provided 

by the relevant market rules. Payments by load serving entities for capacity are made regardless 

of whether energy is actually provided, as long as the relevant availability requirements are met. 

Penalties are generally imposed if a supplier fails to meet the availability requirements or 

otherwise provide energy when called upon. 

14 After an offer is accepted in a given energy or ancillary services market, the generator 

or its marketer has the obligation to deliver the energy or to cover the real-time cost of 

replacement if the generator experiences a forced outage or derate. In addition, even in an 

energy-only market, certain generators that are deemed essential for reliability (often referred to 

as reliability must-run generators or RMRs), are paid an amount above the base energy payments 

to ensure that the unit remains operational and available; these generators are subject to some 

form of penalty if the unit is not available as provided for under the market rules or specific RMR 

contract. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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implementation of day-ahead markets, virtual bidding,15 nodal pricing,16 and 

separate capacity markets. 

Energy-Only Markets versus Capacity Markets

In an energy-only market, load serving entities purchase 

energy on an hourly basis (even if secured or scheduled on a 

day-ahead or forward basis), and are generally also required 

to cover minimum ancillary services requirements, including 

voltage support, regulation, and spinning or non-spinning 

reserves. These load-serving entities are not obligated to 

secure capacity to cover their projected peak loads going 

forward, and generators can only recover their capital costs 

through payments for hourly energy and ancillary services. 

In markets with capacity-based payments, load serving 

entities are responsible for procuring capacity (including 

adequate reserves) to cover their peak loads. In the 

Northeast, capacity prices are set through forward capacity 

markets, and while generators receive the benefit of a more 

predictable revenue stream, they must also accept certain 

obligations to ensure that their unit is available and offered 

into the energy market when needed, or face penalties for 

failure to do so. 

Reliability Oversight by FERC, NERC and Regional Entities 

In 1968, following the extensive 1965 blackout in the Eastern United States 

and Canada, members of the electric utility industry formed a voluntary council 

(NERC)17 to coordinate regional planning for the industry and develop operating 

 15 A form of transaction where buyers and sellers place trades based on differences 

between day-ahead prices and real-time prices. Virtual bidding is intended to improve market 

efficiency as real-time and day-ahead prices converge. 

16 Nodal pricing uses the locational marginal price (LMP, or the cost of supplying the 

next megawatt of load) at each specific electric location or bus. In a completely unconstrained 

system, the nodal price will be the same at each node on the system. When transmission 

constraints occur, the nodal price will reflect the cost of dispatching generating units out of 

economic merit order in order to serve load within the constrained area. Nodal pricing allows for 

separate energy prices at each bus, while zonal pricing sets a locational price for much larger, preestablished zones. 

17 The council was originally named the National Electric Reliability Council, but the 

name was later changed to North American Electric Reliability Council to reflect Canadian 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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guides and voluntary standards and practices to protect the reliability of the 

interconnected system.18 While efforts were undertaken in the 1990s to require 

adherence to NERC reliability policies and guidelines, mandatory reliability 

standards were not adopted in the United States until Congress passed the Energy 

Policy Act of 2005 (EPAct 2005). That act required FERC to certify an 

independent Electric Reliability Organization (ERO) tasked with developing and 

enforcing such mandatory reliability standards.19 

Pursuant to EPAct 2005, FERC certified NERC as the ERO on July 20, 

2006.20 Under implementation procedures adopted by FERC, NERC is permitted 

to delegate a portion of its responsibilities for enforcement and for regional 

standards development to Regional Entities, which NERC in turn oversees. 

NERC has provided such delegated authority to eight Regional Entities in the 

United States and Canada, each of which has primary authority for enforcement in 

the regions shown below.21 

 

member participation, and changed again to North American Electric Reliability Corporation in 

2007 to reflect its new role as the independent Electric Reliability Organization. See NERC 

Company Overview: History, http://www.nerc.com/page.php?cid=1|7|11. 

18 Responsibility for the voluntary standards and operating guidelines was originally 

given to the North American Power Systems Interconnection Committee (NAPSIC, formed 

earlier in the 1960s). NAPSIC later became part of NERC. Id. 

19 See Energy Policy Act of 2005, Pub. L. No. 109-58. The renewed efforts to adopt 

mandatory reliability standards that prompted this section of the Energy Policy Act came in 

response to the Northeastern blackout of August 14, 2003, and to the recommendations made in a 

report prepared by a joint US-Canada task force that reviewed the causes of the blackout. 2003 

Blackout Report at 3 (adopting as its first recommendation: “Make reliability standards 

mandatory and enforceable, with penalties for noncompliance.”) 

20 N. Am. Elec. Reliability Corp. 116 FERC ¶ 61,062 (2006). 

21 The eight Regional Entities operating under delegated authority from NERC are 

Florida Reliability Coordinating Council, Midwest Reliability Organization, Northeast Power 

Coordinating Council, ReliabilityFirst Corporation, SERC Reliability Corporation, Southwest 

Power Pool Regional Entity, Texas Reliability Entity, and Western Electric Coordinating 

Council. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 Under Section 215 of the Federal Power Act, NERC must submit its 

proposed Reliability Standards to FERC for approval before they may become 

mandatory and enforceable. In order to approve a Reliability Standard, FERC 

must find that it is just, reasonable, not unduly discriminatory or preferential, and 

in the public interest, after giving due weight to the technical expertise of the 

ERO.22 In addition, while the ERO has the authority to propose a penalty for 

violation of a Reliability Standard following notice and opportunity for a hearing, 

that penalty may only take effect after it has been filed with FERC. FERC can 

exercise the option to review, set aside, or modify the penalty, on its own motion 

or on application by the entity subject to the proposed penalty.23 FERC also has 

the authority, on its own motion or on complaint, to order compliance with a 

Reliability Standard or to impose a penalty for violation of a Reliability 

Standard.24

 In Order No. 693, FERC approved the first set of 83 Reliability Standards, 

which became enforceable on June 18, 2007.25 NERC maintains a Compliance 

 22 16 U.S.C. § 824o(d)(1) and (2). 

23 Id. at § 824o(e)(1) and (2). 

24 Id. at § 824o(e)(3). 

25 NERC and the Regional Entities may assess penalties for non-compliance with the 

Reliability Standards. In order for such a penalty to take effect, NERC must file a notice of 

penalty with FERC. Each penalty determination is subject to FERC review. In the absence of an 

application for review or action by FERC, each penalty filed by NERC is affirmed by operation 

of law after 30 days. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Registry that identifies all entities subject to compliance with the approved 

Reliability Standards. Users, owners and operators of the bulk power system are 

required to register with NERC under the appropriate functional categories, and 

each Reliability Standard designates each category of entity to which it applies. 

Currently, there are over 1900 registered entities subject to the Reliability 

Standards (a number of entities are counted more than once as they are registered 

under more than one category). The categories of registered entities are set out in 

the appendix entitled “Categories of NERC Registered Entities.” 

 Registered entities are required to report the occurrence of defined bulk 

power system disturbances and unusual occurrences to the appropriate Regional 

Entity and to NERC. The Regional Entity and/or NERC in turn undertakes 

various levels of analysis to determine the causes of the events, assure tracking of 

corrective actions to prevent recurrence, gather information needed to assess 

compliance, and provide lessons learned to the industry. The event analysis 

process also provides input for training and education, reliability trend analysis 

efforts and Reliability Standards development, all of which support continued 

reliability improvement. Under NERC’s field trial of its event analysis program, 

the February 2 and February 3 event was classified as a category 4 event due to the 

overall significance and impact of the event (loss of over 5,000 MW but less than 

10,000 MW of load or generation). Based on the scope of the needed analysis, 

and the fact that it impacted multiple regions, NERC determined that the event 

review should be coordinated at the NERC level. 

Southwest Electricity Markets, Pools and Reserve Sharing Groups 

 The Southwest contains two ISO/RTOs (ERCOT and SPP), and a number 

of vertically integrated utilities that are located within the WECC region. These 

are described below. 

 ERCOT 

The Electric Reliability Council of Texas (ERCOT) is an ISO that covers 

approximately seventy-five percent of the landmass within Texas, excluding the El 

Paso area, part of the northern panhandle, and part of the region east of Houston. 

ERCOT manages access to the transmission system within its footprint and 

operates the Texas energy and ancillary services markets (it does not have a 

capacity market). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 ERCOT schedules power over 40,500 miles of transmission lines and is 

responsible for the dispatch of more than 550 generating units.26 It was founded in 

1970 as one of the NERC regional reliability coordination councils, and is 

currently the registered balancing authority for 85 percent of the electric load in 

Texas.27 When it became an ISO in 1996 it undertook a number of new 

responsibilities, including operation of the wholesale competitive electricity 

market. When Texas restructured its electric industry in 2002, implementing 

customer choice for most retail customers and requiring divestiture of generation 

by IOUs, ERCOT also undertook administration of customer switching for those 

retail customers in Texas that can choose their electric service provider. 

ERCOT is a summer-peaking region, and experienced its highest peak 

demand to date (68,294 MW) on August 3, 2011. Generation in ERCOT is fairly 

diverse in terms of fuel sources. Natural gas represented the highest percentage of 

installed capacity in 2009 (at 59 percent), but coal and nuclear power combined to 

provide over 50 percent of the energy produced for that year. 28

ERCOT operates as a functionally separate interconnection, although it has 

five asynchronous ties with other interconnections.29 Three of the ties allow 

 26 For ERCOT background, see generally ERCOT 2009 Annual Report, available at

http://www.ercot.com/content/news/presentations/2010/2009%20ERCOT%20Annual%20Report.

pdf. 

27 ERCOT is also registered in NERC’s Compliance Registry as an interchange authority, 

planning authority, reliability coordinator, resource planner, and transmission service provider. 

In addition, it also partners with other transmission operators in Texas and in that capacity is 

listed as a “coordinated functional registration.”
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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exchanges with Mexico (through the Comisión Federal de Electricidad, or CFE): 

the Laredo Variable Frequency Tie, the South Tie (also called Eagle Pass), and the 

Railroad Tie, the latter located near McAllen, Texas. Two of the ties allow 

exchanges with the Eastern Interconnection through SPP: the North Tie, located 

near Oklaunion, Texas, and the East Tie, located near Mt. Pleasant, Texas. The 

maximum amount of energy that can be imported on all the ties is 1090 MW 

(approximately 2.3 percent of ERCOT’s 2010/2011 forecasted winter peak), with 

most of that attributable to the ties to the Eastern Interconnection.30 

ERCOT originally employed a zonal market design, under which the region 

was divided into pricing zones and all generators within a zone received the same 

price for the power they provided. It shifted to a nodal market design in December 

2010, under which prices are assessed at points (nodes) where electricity enters or 

leaves the grid. The settlement price at each node is referred to as the locational 

marginal price (LMP). A nodal market design allows for more precise price 

signals and greater dispatch efficiencies than a zonal market design, and permits 

direct assignment of congestion costs through the more granular locational 

marginal prices. 

Under its previous zonal market, ERCOT had no day-ahead energy market 

(although ancillary services were procured on a day-ahead basis to ensure 

sufficient capacity would be available). Under its current nodal market, ERCOT 

has a day-ahead energy market, which is co-optimized with ancillary services. 

ERCOT has an energy-only market, as opposed to both an energy market 

and a capacity market. Capacity markets are used to address resource adequacy 

concerns; typically, a planning reserve margin is established to maintain reliability 

goals, and the ISO/RTO imposes capacity obligations on load-serving entities that 

are met through bilateral contracting or a centralized capacity market. In contrast, 

an energy-only market relies on energy price signals to spur investment in new 

generation. Thus, by design, ERCOT’s energy-only market would be expected to 

 28 ERCOT reported the following percentage fuel mix of installed capacity in 2009, in 

declining order: (1) natural gas, 59 percent; (2) coal, 22 percent; (3) wind, 11 percent; (4) nuclear, 

6 percent; and (5) hydroelectric and biomass, 2 percent. ERCOT reported the following 

percentages for energy produced for 2009: (1) natural gas, 42 percent; (2) coal, 37 percent; (3) 

nuclear, 14 percent (4) wind, 6 percent; and (5) hydroelectric and biomass, 1 percent. ERCOT 

2009 Annual Report at 2. 

29 Four are DC interties and one is a variable frequency transformer (VFT) inter-tie. 

30 The maximum MW that can be imported on each of the ties (actual limits may vary 

based on real-time conditions) is as follows: North, 210 MW; East, 600 MW; South/Eagle 

Pass, 30 MW; Railroad, 150 MW; and Laredo, 100 MW. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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result in higher prices during times of scarcity and produce more volatile prices in 

general than do dual energy and capacity markets. These price signals are 

intended to encourage investment in energy resources, such as new generation 

plants, demand response, and energy efficiency, to meet growing demand. 

NERC’s regional assessment summary for TRE, which includes the 

ERCOT control area, for the winter of 2010/2011 is presented in the following 

chart.31 

 WECC Region and Southwest Reserve Sharing Group 

WECC is the largest geographically of the eight NERC Regional Entities, 

with responsibility for coordinating and promoting system reliability throughout 

the Western Interconnection. WECC’s service territory covers Alberta and British 

Columbia, the northern part of Baja California in Mexico, and all the states in 

between, constituting an area of about 1.8 million square miles. 

 WECC’s bulk power system generally transfers energy over long 

transmission lines from remotely located generators to load centers. The lack of 

redundant transmission facilities demands a high level of operational scrutiny in 

order to maintain correct voltages and power flows on the many stability limited 

transmission paths that exist in the Western Interconnection. 

 31 NERC 2010/2011 Winter Reliability Assessment, available at http://www.nerc.com/ 

files/2010_Winter_Assessment_Final_Posted.pdf. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 WECC has registered 34 balancing authorities;32 52 transmission operators, 

and 3 reserve sharing groups. The California Independent System Operator 

(CAISO) is the only balancing authority in the Western Interconnection that 

operates as an ISO or RTO. 

 NERC’s regional assessment summary for WECC for the winter of 

2010/2011 is presented in the following chart.33 

 Two of the entities that experienced rolling blackouts during the February 

event, SRP and EPE, are located in the WECC region. SRP, one of Arizona’s 

largest utilities, is vertically integrated and a subdivision of the State of Arizona. 

Serving over 933,500 retail customers, SRP’s eleven main generating stations, 

combined with numerous smaller facilities, have a peak retail load of over 6400 

MW, and serve a 2,900 square mile area. SRP is registered with NERC for all 

bulk power system functions except interchange authority, reliability coordinator, 

and reserve sharing group. 

 32 NERC defines “balancing authority” as the responsible entity that integrates resource 

plans ahead of time, maintains load-interchange-generation balance within the BA area, and 

supports interconnection frequency in real-time. 

33 NERC 2010/2011 Winter Reliability Assessment. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 EPE is a vertically integrated electric utility providing generation, 

transmission, and distribution service in west Texas and southern New Mexico. 

EPE serves approximately 372,000 customers over a 10,000 square mile service 

territory via five major generating stations, including three stations local to El 

Paso, Texas. It has a native peak load of 1616 MW. Like SRP, EPE is registered 

with NERC for all bulk power system functions except interchange authority, 

reliability coordinator, and reserve sharing group. 

 

Both SRP and EPE participate in the Southwest Reserve Sharing Group 

(SRSG), which provides for the sharing of contingency reserves among its 

participants pursuant to a Participation Agreement. SRSG was formed in 1998 as 

the successor to an earlier pool, and has participants in Arizona, New Mexico, 

southern Nevada, part of southern California and El Paso, Texas. SRSG is a 

NERC Registered Entity, and administers certain requirements related to 

disturbance control and emergency operations standards. Its participants are 

obligated to carry reserves in accordance with a contractual formula, and to 

provide power within a certain time frame to other participants experiencing a 

disturbance on their systems. 

 Southwest Power Pool

SPP is both an RTO and a NERC Regional Entity responsible for the 

enforcement of Reliability Standards within its region. SPP had its origins in 

1941, when eleven regional power companies formed the pool in order to ensure 

sufficient electric service to aluminum plants needed for the war effort. The pool 

remained intact after the war and was a founding member of NERC in 1968. SPP 

implemented operating reserve sharing arrangements among its members in 1991, 

and became a FERC-approved RTO in 2004. 

SPP covers a 370,000 mile area that includes all or portions of nine states: 

Nebraska, Kansas, Oklahoma, Missouri, Arkansas, Louisiana, Texas, New 

Mexico, and Mississippi.34 SPP operates 48,930 miles of transmission lines, and 

has a coincident peak demand within its reliability coordinator35 footprint of 

approximately 55,000 MW. 

 34 SPP actually has five “footprints,” with differing membership and oversight functions, 

as (1) a NERC Regional Entity; (2) a reserve sharing group; (3) a reliability coordinator area (29 

balancing authorities and transmission owners, including certain balancing authorities in SERC 

and the Midwest Reliability Organization); (4) an RTO (with 15 balancing authorities); and (5) an 

energy imbalance services (EIS) market region (with 15 balancing authorities). See

http://www.spp.org/section.asp?pageID=28 (last visited Aug. 2, 2011). 

35 NERC defines “reliability coordinator” as the entity that is the highest level of 

authority responsible for the reliable operation of the bulk power system, has the wide area view 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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At present, SPP’s market operations are relatively limited, currently 

allowing participants to buy and sell energy in real time and to settle out any 

energy scheduling imbalances based on the real-time market price. SPP does not 

currently operate a separate market for reserves but is working to implement a new 

integrated marketplace that includes a day-ahead energy and operating reserves 

market.36 

NERC’s regional assessment summary for SPP for the winter of 2010/2011 

is presented in the following chart.37

 

 

of the bulk power 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 RC 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. 

36 Unlike California, Texas, and the Northeast, most of the states SPP covers have not 

undertaken a broad restructuring of the electric industry through retail access and/or mandatory 

unbundling of generation from transmission and distribution. Accordingly, most utilities 

operating within SPP’s footprint still supply a large portion of their customers’ electricity needs 

through their own generation and do not need to access the market to do so. 

37 NERC 2010/2011 Winter Reliability Assessment. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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B. The Natural Gas Industry

 This subsection provides an overview of the manner in which natural gas is 

produced and delivered, the jurisdictional structures applicable to the industry, and 

the various producers and pipelines located in the Southwest. A detailed 

description of the geology and physics of natural gas production and delivery can 

be found in the appendix entitled “Natural Gas: Production and Distribution.” 

Overview of Natural Gas Production and Delivery

 Natural gas is a fossil fuel, formed through the decomposition of organic 

matter found in underground geological formations. It is a significant source of 

energy representing 25 percent of the United States energy consumption. In 2010, 

approximately 22 percent of gas consumption was used for residential heating and 

cooking, 14 percent for commercial use, 30 percent for industrial processes, 34 

percent for electric generation, and less than one percent for transportation.38 

The delivery framework for natural gas includes production, separation of 

fluids at or near producing wells, natural gas liquids (NGL) processing, pipeline 

transmission, storage, and finally distribution by an LDC. The following chart is a 

simplified schematic of this framework. 

 38 EIA, Natural Gas Consumption by End Use, http://www.eia. gov/dnav/ng/ng_ 

cons_sum_dcu_nus_a.htm (last visited Aug.27, 2011). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Natural gas is often produced in locations distant from demand centers. 

The Energy Information Agency estimates that in 2009 there were 493,100 gas 

wells in the United States. The majority of these wells were located in the Gulf 

Coast, Southwest and the Appalachian Basin. The five states with the largest 

number of wells that year were Texas, 93,507; Pennsylvania, 57,356, West 

Virginia, 50,602; New Mexico, 44,784, and Oklahoma, 43,600.39 The following 

chart shows production basins and the concentration of reported natural gas 

production.40 

 39 EIA, Natural Gas, Number of Producing Wells, http://www.eia.doe.gov/dnav/ 

ng/ng_prod_wells_s1_a.htm (last visited Aug.2, 2011). 

40 EIA, Gas Production in Conventional Fields, 

http://www.eia.gov/oil_gas/rpd/conventional_gas.pdf (last visited Aug. 2, 2011). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 32 - 

Major oil companies and large independent companies account for a 

substantial portion of the gas production in the United States. In the first half of 

2009, the five largest producers and their daily production were as follows: BP, 

Inc, 2.33 Bcf per day; Anadarko Petroleum Corporation, 2.33 Bcf per day; XTO 

Energy, Inc., 2.29 Bcf per day (acquired by ExxonMobil in 2010); Chesapeake 

Energy Corporation, 2.21 Bcf per day; and Devon Energy Corporation, 2.13 Bcf 

per day. These producers together accounted for approximately 20 percent of 

United States production.41 

In the Southwest, production takes place at the many thousands of 

wellheads located throughout the basins. The wellhead consists of equipment on 

top of the well that is used to manage flows of oil and gas, often produced 

together, arising from the underground formations. The high pressure gas in 

formations is lighter than air and will often rise on its own through the wellhead to 

surface pipes. In other gas wells, as well as oil wells with associated natural gas, 

flow requires lifting equipment. Typical lifting equipment consists of the “horse 

head” or conventional beam pump. The pumps are recognizable by the distinctive 

shape of the cable feeding fixture, which resembles a horse's head.

42 They are 

 41 Reuters, http://www.reuters.com/article/2009/12/14/xto-exxon-natgas-producersidUSN1420089920091214; and EIA, http://www.eia.gov/dnav/ng/ng_prod_sum_a_ 

EPG0_FPD_mmcf_a.htm. “Bcf” refers to a billion cubic feet. 

42Well Completion, NATURALGAS.ORG, http://www.naturalgas.org/naturalgas/ 

well_completion.asp (last visited Aug. 2, 2011). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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often called “pumpjacks” and are seen throughout west Texas and southeastern 

New Mexico. The following two photographs are of a wellhead and a pumpjack. 

Wells and lift equipment are monitored on a daily basis and maintained by 

oil and gas company employees, who are often referred to as “pumpers” or 

“gaugers.” Their responsibilities include reporting malfunctions and spills, and 

ensuring that field processing equipment is operational and that production is 

correctly measured. Onshore gaugers may drive many miles per day to monitor 

dozens of wells. 

Processing Natural Gas

The natural gas used by consumers consists almost entirely of methane. 

However, produced gas often contains other hydrocarbons such as 

ethane, propane, butane, pentanes and liquids such as condensates. It 

may also include water vapor, hydrogen sulfide (H2S), carbon dioxide, 

helium, nitrogen, and other compounds. Some field processing occurs 

near production wells to remove the water and condensates, but 

complete processing usually occurs at a gas processing plant. Natural 

gas processing plants remove other hydrocarbons to produce what is 

known as “pipeline quality” dry natural gas that meets the heating 

content and other restrictions necessary for the safe operation of 

pipeline and distribution company facilities. The removed hydrocarbon 

NGLs are sold separately. 

 Natural gas is transported to processing plants43 typically through smalldiameter and low-pressure gathering pipelines. There were an estimated 20,552 

 43 More than 500 processing plants operated in the United States in 2004 with 166, or 

over 31 percent, in the state of Texas. EIA, Natural Gas Processing: The Crucial Link Between 

Natural Gas Production and Its Transportation to Market, (Jan. 2006), http://dnr.louisiana.gov/ 

assets/docs/oilgas/productiondata/ngprocess_20060131.pdf. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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miles of gathering system pipelines in the United States in 2009.44 

After gathering and processing, interstate and intrastate transmission 

pipelines transport gas to LDCs (as well as to directly attached users such as 

power plants). Within the United States, the pipeline network delivers gas to 65 

million residential, commercial, industrial, and power generation customers. It 

includes at least 210 gas pipeline systems with a total of more than 300,000 miles 

of transmission pipelines.45 The pipeline system also includes more than 1,400 

compressor stations, 11,000 delivery points, 5,000 receipt points, and 1,400 

interconnection points.46 

Pipeline companies monitor and control gas flow with computerized 

supervisory control and data acquisition (SCADA) systems, which provide 

operating status, volume, pressure, and temperature information. In addition to 

real-time monitoring, the SCADA system may enable a pipeline to start and stop 

some facilities remotely.47

 The following map shows the breadth and integrated nature of the natural 

gas transmission grid.48

 44 U.S. Dep’t of Transp. Pipeline & Hazardous Materials Safety Admin., Natural Gas 

Transmission, Gas Distribution, and Hazardous Liquid Pipeline Annual Mileage, (Jun. 30, 2011), 

http://www.phmsa.dot.gov/portal/site/PHMSA/menuitem.ebdc7a8a7e39f2e55cf2031050248a0c/?

vgnextoid=036b52edc3c3e110VgnVCM1000001ecb7898RCRD&vgnextchannel=3430fb649a2d

c110VgnVCM1000009ed07898RCRD&vgnextfmt=print. 

45 Am. Gas Assn., About Natural Gas, http://www.aga.org/Kc/aboutnaturalgas/Pages/ 

default.aspx (last visited Aug. 2, 2011). These pipelines are high pressure systems and operate at 

500 to 1,800 psi. The lines are usually 20 inches to 42 inches in diameter. 

http://www.naturalgas.org/naturalgas/transport.asp. 

46 EIA, About U.S. Natural Gas Pipelines-Transporting Natural Gas (June 2007), 

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/fullversion.pdf 

(EIA: About U.S. Natural Gas Pipelines). 

47 INGAA, Supervisory and Data Acquisition (SCADA), http://www.ingaa.org/cms/ 

33/1339/109/134.aspx (last visited Aug. 2, 2011). 

48 EIA: About U.S. Natural Gas Pipelines. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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To meet higher gas demand at various times of the year, gas is stored 

underground in depleted oil and gas reservoirs, aquifers or caverns formed in salt 

beds.49 Storage facilities may be interstate and regulated by FERC, or intrastate 

and non-jurisdictional. There are over 390 underground storage facilities in the 

United States,50 of which approximately 205 are under FERC jurisdiction.51 

Depleted oil and gas reservoirs account for 87 percent of the total FERC 

jurisdictional storage capacity, with salt caverns (3 percent) and aquifers (10 

percent) accounting for the rest.52 A detailed discussion of the types of storage 

facilities and their characteristics is included in the appendix entitled “Natural Gas 

Storage.” 

 

 49 EIA, Natural Gas Explained: Delivery and Storage of Natural Gas, 

http://www.eia.doe.gov/energyexplained/index.cfm?page=natural_gas_delivery (last updated 

June 8, 2011). 

50 EIA, The Basics of Underground Storage, http://www.eia.gov/pub/oil_gas/natural_gas/ 

analysis_publications/storagebasics/storagebasics.html (last updated Aug. 2004). 

51 http://www.ferc.gov/EventCalendar/Files/20060615103625-A-3-TALKING-PTS.pdf. 

52 http://www.ferc.gov/industries/gas/indus-act/storage/fields.asp. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Gas Storage Facilities

 Depleted reservoirs consist of porous and permeable underground 

formations (average of 1,000 to 5,000 feet deep). The gas is divided into 

two categories, working or top gas, which can be withdrawn, and cushion 

or base gas, needed as permanent inventory to maintain adequate reservoir 

pressure and deliverability rates. Gas is generally withdrawn in the winter 

heating season and injected during the summer, although the demand for 

gas in summer months is increasing due to an increase in gas-fired 

generating plants. This type of storage facility can be used for both system 

supply and peak day demand.

 

 Aquifer storage fields are bounded partly or completely by water-bearing 

rocks. They have a high cushion gas requirement, generally between 50 to 

80 percent. They also have high deliverability rates and, similar to depleted 

reservoirs, gas is generally withdrawn in the winter season and injected in 

the summer season. 

 Salt cavern facilities use solution mining to recover minerals in 

underground salt deposits (salt domes or salt formations). Salt caverns 

usually operate with only about 20 to 30 percent cushion gas. Working gas 

can be recycled multiple times per year. Salt cavern storage has high 

deliverability and injection capabilities and is used for short peak day 

deliveries. Salt caverns are more expensive to construct due to the 

increased capital cost associated with leaching and mining the salt.
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The following figure shows the location of United States storage 

facilities.53 

Natural Gas Regulation 

Natural gas production is not comprehensively regulated, and no 

government agency monitors daily production activity. However, some aspects of 

production are subject to regulation; gas-producing states monitor well drilling and 

permitting, and in Texas, for instance, the TRC has jurisdiction over oil and gas 

wells located in the state and over persons owning or engaged in drilling oil and 

gas wells located in the state.54 Congress deregulated the price on natural gas at 

the wellhead.55 FERC does not regulate natural gas producers, but does provide 

 53 EIA, The Basics of Underground Storage, http://www.eia.gov/pub/oil_gas/natural_gas/ 

analysis_publications/storagebasics/storagebasics.html. 

54 Among the matters covered by the TRC are space and density of drilling; prevention of 

waste; approval of water flood permits; location exceptions; intrastate pipelines; environmental 

and safety aspects of production, including well plugging; regulation of the injection of carbon 

dioxide into reservoirs; and maintenance of well records including logs, maps and production 

reporting. Jack M. Wilhelm, Texas Land Institute, What Every Landman Should Know about 

the Railroad Commission of Texas (2005), available at http://blumtexas.tripod.com/ 

sitebuildercontent/sitebuilderfiles/wilhelm.pdf. 

55 Natural Gas Wellhead Decontrol Act, Pub L. No. 101-60, 103 Stat. 157 (1989). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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that producers have not unduly preferential or discriminatory access to 

transportation on jurisdictional pipelines, and that no undue treatment bias is 

exercised with respect to transportation services and gas quality standards. Retail 

natural gas sales to consumers are regulated by state public utility commissions, 

not by FERC. 

FERC’s jurisdiction over the transportation of natural gas,56 which also 

includes the provision of natural gas storage services, begins when the gas is 

delivered to an interstate pipeline and continues until the gas is delivered to the 

wholesale purchaser, absent some intervening transaction which renders the 

activity exempt from federal jurisdiction under the Natural Gas Act (NGA) or the 

Natural Gas Policy Act of 1978 (NGPA). While generally the activities of 

intrastate pipelines and LDCs are exempt from FERC jurisdiction, when those 

entities engage in the transportation of natural gas in interstate commerce or the 

wholesale sales for resale of natural gas, their activities are subject to FERC 

jurisdiction. 

FERC’s responsibilities include: 

 Issuance of certificates of public convenience and necessity to construct 

and operate interstate pipeline and storage facilities, and oversight of the 

construction and operation of pipeline facilities at United States points of 

entry for the import or export of natural gas. 

 Regulation of transportation and sales for resale in interstate commerce that 

are not first sales. 

 Regulation of the transportation of natural gas as authorized by the NGPA 

and the OCSLA (Outer Continental Shelf Lands Act). 

 Regulation of liquefied natural gas facility siting. 

 Regulation of the abandonment of jurisdictional facilities and services. 

 Establishment of rates and terms and conditions for jurisdictional services. 

Pipelines publish FERC-approved tariffs that pertain to services, terms of 

conditions and rates for gas transportation. The North American Energy Standards 

Board (NAESB) provides business standards for the pipelines in areas such as the 

scheduling of pipeline transportation. 

 56 FERC also has NGA jurisdiction over sales for resale of natural gas that are not 

deemed first sales. A first sale does not include the sale by an interstate pipeline, intrastate 

pipeline, or LDC, or affiliate thereof, unless such sale is attributable to volumes of their own 

production. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Most interstate pipelines no longer offer sales services. The two broad 

categories of transportation service on an interstate pipeline are firm and 

interruptible transportation, subject to specified exceptions such as force majeure 

clauses. (The pipeline companies sell transportation, not the gas itself, which 

almost always is purchased separately from the producer by the shipper.) Firm 

transportation is characterized by a reservation of capacity. Shippers customarily 

pay a charge for the reservation of guaranteed capacity rights on the pipeline and a 

separate usage charge; pipeline firm rates thus include cost recovery of pipeline 

facilities in addition to recovery of variable transportation costs such as fuel. 

Interruptible service rates are usage charges that are derived from the firm service 

rates. There is no reservation of capacity under interruptible service, and capacity 

is provided to a shipper only to the extent it is available.57

 

Prior to the deregulation of wellhead gas prices and open access 

transportation established under Commission Order No. 436 in 1985 and Order 

No. 636 in 1992, producers typically sold gas to both intrastate and interstate 

pipelines; these entities in turn sold the gas to LDCs that delivered the gas to end 

users. With the issuance in 1992 of Order No. 636, the Commission required 

interstate pipelines to unbundle their services to separate the transportation of gas 

from the sale of gas. Thus, today most interstate pipelines do not engage in the 

buying and selling of natural gas except for operational purposes. 

Order No. 636 further required interstate pipelines to set up informational 

postings to show available pipeline capacity and to ensure that all participants 

have access to available capacity. Additionally, holders of the firm capacity can, 

through capacity release, resell those rights on a temporary or permanent basis. 

 

Natural Gas Marketing

 

Natural gas marketing mushroomed after the opening of access to pipeline 

capacity. Producers and marketers, in conjunction with the deregulation of 

wellhead gas, were granted blanket authorization to make sales at market rates. 

Marketers may now be affiliates of producers, pipeline companies, or local 

utilities, or be separate business entities unaffiliated with any other industry 

players. Marketers may also be associated with financial institutions. Marketing 

natural gas typically includes ensuring secure supplies and arranging for pipeline 

 57 Pipeline Knowledge and Development, The Interstate Natural Gas Transmission 

System: Scale, Physical Complexity and Business Model (August 2010), available at

www.ingaa.org/File.aspx?id=10751. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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transportation, storage and accounting. Marketers also trade financial instruments 

to hedge commodity price risk and to speculate.58 

For illustrative purposes, the following map depicts the February 2011 price for 

some regional gas trading hubs.59 Waha and El Paso San Juan, shown on the map, 

are trading prices respectively applicable to the San Juan and Permian Basins. 

These two basins are important Southwest supply areas and figured prominently in 

the weather event of February 1-5. 

LDCs often make the final sale and transfer of gas to retail consumers. 

Unlike the interstate pipeline companies, many LDCs provide bundled sales and 

delivery services, although some may provide delivery services only. Many 

commercial and industrial customers contract for their own supply and purchase 

only transportation service from the LDC. There are more than 1,200 LDCs in the 

United States. LDCs can be stand-alone gas utilities, combination electric-gas 

utilities, or parts of integrated energy companies. The largest LDC is Southern 

California Gas Company (SoCalGas) with more than 20 million customers, 

followed by Pacific Gas and Electric Company and Atmos Energy Corporation. 

 58 Natural Gas Distribution, NATURALGAS.ORG., http://www.naturalgas.org/ 

naturalgas/marketing.asp (last visited Aug. 2, 2011). 

59 PLATTS INSIDE FERC’S GAS MARKET REPORT (Feb. 2011). Reprinted with permission 

of Platts. 
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Natural gas distribution companies typically deliver smaller volumes 

through smaller diameter pipes and at lower pressures than pipeline companies 

with systems that end at an individual household or place of business. Compressor 

stations are generally smaller than those found on the larger pipeline systems. 

Natural gas traveling through distribution pipelines will often be at a pressure as 

low as 3 psi to 0.25 psi at the customer’s meter.60 

Natural Gas Production in the Southwest

Texas and New Mexico are both prolific producers of natural gas, while 

Arizona has negligible production. In January 2011, Texas produced 31 percent of 

total United States production and New Mexico produced 6.2 percent.61 

 Texas and New Mexico contain a number of natural gas basins. The most 

significant of these with respect to the outages and curtailments experienced 

during the February cold weather event are the Permian, San Juan, and Fort Worth 

Basins.62 Together, these three basins are responsible for almost 18 percent of 

total United States natural gas production. 

The San Juan Basin straddles the Colorado and New Mexico border in the 

Four Corners region, and is a leading coal bed methane producing area. The basin 

is approximately 270 miles wide and covers over 4,000,000 acres.63 Production is 

approximately 2.99 Bcf per day. The Permian Basin is located in West Texas and 

Southeastern New Mexico. It underlies an area approximately 250 miles wide and 

300 miles long,64 and produces on average 2.52 Bcf per day. The Fort Worth 

Basin contains the Barnett Shale Formation, with one of the largest producible 

 60 Natural Gas Distribution, NATURALGAS.ORG, http://www.naturalgas.org/naturalgas/ 

distribution.asp (last visited Aug. 2, 2011). 

61 In 2009, U.S. dry gas production was 20,580 billion cubic feet (Bcf) or 56.4 Bcf per 

day. Texas produced 17.5 Bcf per day on and off shore, and New Mexico produced 3.5 Bcf per 

day. EIA, Natural Gas Withdrawals and Production, http://www.eia.gov/dnav/ng/ng_prod_ 

sum_a_EPG0_VGM_mmcf_m.htm (last visited Aug. 15, 2011). 

62 Other onshore basins in the region include East Texas, the Gulf Coast and South Texas. 

63 La Plata Cnty. Energy Council, Gas Facts: San Juan Basin Map, http://www. 

energycouncil.org/gasfacts/sjbmap.htm (last visited Aug. 2, 2011). 

64 Charles D. Vertrees, Handbook of Texas Online: The Permian Basin, TEX. STATE 

HISTORICAL ASSN., http://www.tshaonline.org/handbook/online/articles/ryp02\ (last visited Aug. 

2, 2011). 
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reserves of any natural gas field in the United States.65 The basin produces 4.83 

Bcf per day.66 

Gas processing companies in the San Juan, Permian and Fort Worth Basins 

include DCP Midstream Partners, L.P., Enterprise Products Partners L.P., 

Williams Partners, L.P., Southern Union Gas Services, and Frontier Energy, 

L.L.C. 

Natural Gas Pipelines in the Southwest 

Intrastate gas pipelines in Texas comprise 45,000 miles out of the 58,600 

total miles of gas pipeline in the state. This intrastate network delivers much of 

the region’s natural gas, including deliveries to many large refining and 

petrochemical facilities, numerous electric generating facilities, and pipeline 

interconnects.67 The largest intrastate pipelines in Texas are Enterprise Texas 

Pipeline LLC (8,750 miles) and the Energy Transfer Partners L.P. (8,800 miles). 

Other large systems include Atmos Pipeline – Texas (6,162 miles) and the Kinder 

Morgan Pipeline’s Texas Intrastate Natural Gas Group (5,900 miles). Together 

these pipelines provide for transmission from west Texas supply and market hubs 

such as Waha, and for gas production in south Texas to the Houston Ship Channel, 

Katy Hub, the Dallas-Forth Worth area and other markets. Intrastate pipelines 

have expanded significantly due to increased demand for capacity to transport 

natural gas from the Barnett Shale Formation in the Fort Worth Basin south to the 

Katy area or out of the state. The following map shows the Texas intrastate 

pipeline grid.68 

 65 The Perryman Group, Bounty from Below: The Impact of Developing Natural Gas 

Resources Associated with the Barnett Shale on Business Activity in Fort Worth and the 

Surrounding 14-County Area, at 5 (May 2007), available at http://www.barnettshaleexpo.com/ 

docs/Barnett_Shale_Impact_Study.pdf. The Barnett Shale is one of the most significant onshore 

natural gas fields in North America, with thousands of wells producing hundreds of billions of 

cubic feet of natural gas each year. Production has risen sharply over the past several years as a 

result of improvements in recovery techniques. 

66 Staff’s analysis based on supporting data, display reports and data warehouse on file 

with Bentek Energy LLC (unpublished); See also Market Alert: Deep Freeze Disrupts U.S. Gas, 

Power, Processing, Bentek Energy LLC, Feb. 8, 2011, at 2-6; additional materials were also 

obtained from natural gas pipelines. 

67 EIA, Natural Gas Pipelines in the Southwest Region, http://www.eia.doe.gov/pub/oil_ 

gas/natural_gas/analysis_publications/ngpipeline/southwest.html (last visited Aug. 2, 2011). 

68 EIA, About U.S. Natural Gas Pipelines - Transporting Natural Gas: Intrastate Natural 

Gas Pipeline Segment, http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ 

ngpipeline/intrastate.html (last visited Aug. 2, 2011). 
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New Mexico and Arizona are supplied largely by two interstate 

transmission pipelines, Transwestern Pipeline Company, LLC (Transwestern) and 

El Paso Natural Gas Company (El Paso). These pipelines transport natural gas 

primarily from the San Juan and Permian Basins to the western regions of the 

United States. (The many other interstate pipelines that operate in Texas tend to 

transport gas to the Midwest and Northeast.) 

A brief description of these two interstate pipeline systems follows. 

El Paso owns a transmission delivery system consisting of approximately 

10,200 miles of pipeline. It is a complex, highly networked pipeline system with 

many laterals and interconnections, operating at a variety of flows and pressures. 

It includes 62 compressor stations and more than 700 meter sites where gas is 

delivered. It has 53 delivery meters to New Mexico Gas Company (NMGC), 216 

meters to Southwest Gas Corporation (Southwest Gas), and 28 meters to Texas 

Gas Service. The system also includes the Washington Ranch Storage Field, one 

of the two storage facilities in the area between west Texas and the ArizonaCalifornia border. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Transwestern has approximately 2,700 miles of pipeline and 26 

compressor stations. Its mainline capacity flowing west is 1,225 MMcf/day, and 

its San Juan Lateral capacity is 1,610 MMcf/day.69 

Transwestern has at least ten delivery points with NMGC.70 In terms of 

flow volumes, the most significant of these during the February cold weather 

event was the NMG Rio Puerco, as shown in the following map. 

 69 Throughout the report, MMcf refers to a million cubic feet, and Mcf to a thousand 

cubic feet. 

70 http://www.energytransfer.com/ops_interstate.aspx, and materials provided by 

Transwestern Pipeline Company, LLC to the task force. 
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These two pipeline companies, Transwestern and El Paso, are the interstate 

providers to those LDCs that experienced customer curtailments or outages in 

February 2011. Those LDCs are: 

 New Mexico Gas Company, headquartered in Albuquerque. It 

provides gas service to more than 500,000 customers and maintains 

approximately 12,000 miles of natural gas pipelines.71 

 Southwest Gas Corporation, providing gas service to more than 1.8 

million residential, commercial and industrial customers in Arizona, 

Nevada and portions of California.72 

 Texas Gas Service, the third largest natural gas distribution company 

in Texas. It provides gas to more than 603,000 customers in Austin, 

El Paso, and Rio Grande Valley areas as well as Galveston, Port 

 71 New Mexico Gas Company, About Us, http://www.nmgco.com/about_us.aspx (last 

visited Aug. 2, 2011). 

72 Southwest Gas Corporation, Profile of Southwest Gas, http://www.swgas.com/about/ 

aboutus/index.php (last visited Aug. 2, 2011). 
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Arthur, Weatherford and several communities in the Permian Basin 

and the Texas panhandle. 73

 Zia Natural Gas Company, which provides gas service to over 

35,000 customers in five New Mexico counties, serving primarily 

residential and small commercial users. In Lincoln County, where 

the city of Ruidoso experienced gas outages during the February 

event, Zia obtains gas from a direct interconnection to the El Paso 

Natural Gas pipeline. 

Natural Gas Storage Facilities in the Southwest

 There are two major natural gas storage facilities in the Southwest: 

 Washington Ranch Storage Field, part of the El Paso system, is located in 

Eddy County, New Mexico, approximately nine miles southwest of Whites 

City. This facility has a working storage capacity of slightly more than 

47.6 bcf and a maximum daily withdrawal capacity of 250,000 Mcf. 

 Chevron Keystone Storage Facility, owned by Chevron Corporation, is 

located in Winkler County, in west Texas near Midland. This is a salt 

cavern facility with 6.38 Bcf of working gas. Its maximum daily injection 

capability is 200,000 Mcf and its maximum daily withdrawal capacity is 

400,000 Mcf. It has interconnects to Transwestern, El Paso and the 

Northern Natural Gas Company’s pipeline systems. 

 73 Texas Gas Service, Profile, http://www.texasgasservice.com/en/About.aspx (last 

visited Aug. 2, 2011). 
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IV. Preparations for the Storm 

A severe arctic cold front hit the central and northeastern United States and 

southern Canada on February 1, 2011, and lasted for several days. It was dubbed 

the “Groundhog’s Day Blizzard of 2011.”74 The front was not unexpected. About 

a week prior to the event, long-range forecasts predicted an outbreak of very cold 

temperatures for the first week of February, with wind, ice, and snow from Texas 

to Mississippi. Arctic air was expected to extend southward to the Gulf Coast by 

February 2, bringing daytime highs to as low as 30 degrees below normal. 

Sustained winds of 20-25 mph, with higher gusts, were also anticipated.75

[Color legend: N is normal, B is below normal, MB is much below normal, 

and SB is strong below normal.]76

 74 National Oceanic and Atmospheric Administration National Climatic Data Center 

(NCDC), State of the Climate: Global Hazards for February 2011(March 2011), 

http://www.ncdc.noaa.gov/sotc/hazards/2011/2#winter. 

75 Weather data used in this section is drawn from NCDC data. Raw land-based 

observation data was obtained at http://www.ncdc.noaa.gov/oa/land.html. Quality controlled 

local climatological data was obtained at http://cdo.ncdc.noaa.gov/qclcd/QCLCD?prior=N. 

Additional data, unless otherwise noted, is drawn from materials provided to the task force by 

BAs, transmission operators, generators, producers, processing plants, pipelines and LDCs. 

76 EarthSat is a private forecasting service used by many entities in the energy industry 

and by the Commission in connection with its market monitoring efforts.
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A. Weather Conditions During the Event

Actual weather conditions between February 1 and 5, 2011 turned out to be 

largely as predicted by the National Weather Service’s long-range forecasts. 

However, actual temperatures were a few degrees lower than forecasted, 

especially in west Texas and New Mexico. In some places, temperatures did not 

rise above freezing until February 4. Low temperatures in Albuquerque ranged 

from -7 degrees to 7 degrees over the four-day period, in Midland from 6 degrees 

to 12 degrees, and in Dallas from 13 degrees to 19 degrees.77

 

As the storm hit during the early morning hours of Tuesday, February 1, 

temperatures in the western-most cities of the Southwest plummeted dramatically. 

Daily highs at Albuquerque and Dallas fell 20 degrees (to 28 degrees and 39 

degrees respectively) from the previous day, while at Midland the recorded high 

was 30 degrees, which was 43 degrees below that of the previous day. Houston’s 

temperatures started out on February 1 at 70 degrees, but by 7:00 AM had dropped 

to 45 degrees. 

 

The wind profile was also changing dramatically. Wind speeds had rarely 

exceeded 10 mph the preceding day, but by the morning of February 1 

Albuquerque was experiencing sustained wind speeds of 20 mph (representing a 

wind chill index of 4 degrees), with gusts to 27 mph. Winds in Midland hovered 

around 20 mph and gusted to over 30 mph. Light snow began falling in both cities 

around midnight. It was also windy in Dallas on February 1, with speeds of up to 

25 mph and gusts between 20 and 40 mph. 

Conditions worsened at all locations through the day, and by midnight 

temperatures were extremely low. Albuquerque was at 4 degrees, with continuing 

high winds and snow. Temperatures at Midland were 14 degrees and at Dallas 16 

degrees. The cold air finally hit Houston late in the day, with temperatures of 27 

degrees and winds of 14 mph, although without precipitation. 

By Wednesday, February 2, early morning conditions had become severe. 

In Albuquerque, the temperature at 8:00 AM was 1 degree, almost 40 degrees 

below the average for that date, and the wind was blowing at 26 mph. 

Temperatures in El Paso and Midland hovered around 10 degrees for much of the 

day, with wind speeds of 15 mph. El Paso set a record low for the day of 6 

degrees at 5:00 AM, and recorded the third coldest day in 38 years. In fact, 

February 2 turned out to be one of the coldest days on record in the last 25 years 

across the state of Texas, with average temperatures well below freezing and only 

 77 All temperatures in this report are in degrees Fahrenheit. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Brownsville escaping severe conditions (with average temperatures of about 35 

degrees). Significant winds accompanied the frigid temperatures, with wind chill 

factors dropping the perceived temperatures to -6 degrees in Dallas and 6 degrees 

in Austin. 

On Thursday, February 3, weather conditions began to marginally improve 

in some areas, although in Albuquerque and El Paso it would rank as the coldest 

day in 38 years. Albuquerque, Midland and El Paso were still experiencing highs 

near 15 to 20 degrees, but the winds had begun to diminish. From Dallas to San 

Antonio, temperatures moderated about 5 to 10 degrees, but wind speeds remained 

high. 

On Friday, February 4, conditions improved across the region. 

Temperatures in the western cities finally rose above freezing, and in a few of the 

eastern-most cities rose above 40 degrees. Nonetheless, during the early morning 

hours, El Paso hit a low of 3 degrees before reaching a high of 37 degrees, ranking 

the day as the city’s second coldest in 38 years. Four to six inches of snow fell in 

the Dallas Metropolitan area, causing cancellation of more than 300 flights at 

Dallas airports just as fans were arriving for the Super Bowl. 

 

Cold weather hit the region again on February 9 and February 10. The 

coldest temperatures were seen on February 9, when El Paso recorded a low of -2 

degrees, and Midland a low of 7 degrees. Daily highs, however, were in the 30s 

and 40s. Other cities saw lows dip into the 20s and teens, with high temperatures 

rising into the 40s and 50s. 

There is no question that the cold and windy weather during this first week 

of February was both sustained and severe. Just how severe, when compared to 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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prior storms, is examined in the section of this report entitled “Prior Cold Weather 

Events.” 

 

B. Preparations for the Storm: Electric

Three balancing authorities in the Southwest shed load during the cold 

weather event: ERCOT, SRP and EPE. (PNM lost some 26 MW of load as well, 

although this was the result of localized transmission issues largely unrelated to 

the storm). Customers in ERCOT were affected the most, by a large margin. 

ERCOT shed 4000 MW of load, affecting 3.2 million customers, on February 2. It 

shed another 300 MW on February 3, affecting 180,000 customers. In 

comparison, SRP shed 300 MW of load, affecting 65,000 customers, and EPE 

shed a little over 1000 MW of load, affecting 253,000 customers.78 

The preparations for the storm taken by these three entities are discussed 

below. 

 ERCOT

Going into the winter season of 2010/2011, ERCOT had substantial reason 

to believe it could meet its projected demand with available generation and 

imports. ERCOT’s peak demand for the winter of 2010/2011 was forecasted to be 

47,824 MW, with the peak anticipated to occur in January.79 (This forecasted 

peak was 11 percent higher than the forecasted peak for the previous winter.80) To 

meet that peak demand, ERCOT had projected generation capacity plus imports of 

72,881 MW.81 Thus, for planning purposes, ERCOT could anticipate a 

 78 In the case of ERCOT, these numbers represent the amount of load the transmission 

providers were directed to shed. Actual load shed was somewhat higher (5411.6 MW on 

February 2 and 459.5 MW on February 3), for reasons discussed in the section of this report 

entitled “The Event: Load Shed and Curtailments.” 

79 NERC, 2010/2011 Winter Reliability Assessment, at 16 (Nov. 2010), available at

http://www.nerc.com/files/2010_Winter_Assessment_Final_Posted.pdf. NERC prepares its 

reliability assessments based on data and information submitted by the applicable Regional 

Entity, which in ERCOT’s case is TRE. 

80 ERCOT modified the forecasting models because it had experienced extreme cold 

weather in January of 2010, with load tracking notably higher than forecasted. 

81 Resources listed in the NERC 2010-2011 Winter Reliability Assessment consisted of 

available generation (72,500 MW) and net firm imports (381 MW), and did not include 

generating units which were known well in advance to have scheduled maintenance outages 

spanning the expected peak load period. Demand was calculated based on a 50/50 load forecast 

(47,824 MW), meaning the forecast is expected to be exceeded five years out of every ten. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 53 - 

comfortable reserve margin of 57 percent. This percentage compares favorably 

with NERC’s reference reserve margin for ERCOT of 13 percent, considered by 

NERC to be the base level required for reliability.82 

The estimated demand for the season included only firm load, and therefore 

did not include ERCOT’s two categories of contractually curtailable load: Load 

Resources (formerly designated as Load Acting as a Resource, or LaaR), which 

may be automatically disconnected when system frequency drops below a 

prescribed threshold (totaling 1062 MW as of February 2); and Emergency 

Interruptible Load Service (EILS), which permits curtailment prior to firm load 

shedding (totaling 331 MW as of February 2). 

Although ERCOT seemingly had a generous reserve margin going into the 

winter of 2010/2011, the reserve margin cited did not take into account planned 

outages that were not yet known at the time of the forecast. ERCOT is a summerpeaking system, and the high summer temperatures and demand often extend into 

what would be considered shoulder seasons in more northerly regions. For that 

reason, it is not unusual for generators in ERCOT to schedule maintenance 

outages in February. ERCOT does not have the authority to prohibit generators 

from scheduling such outages or from taking them as scheduled, unless the outage 

is scheduled eight days or less before the outage date, or the outage would keep 

ERCOT from meeting applicable Reliability Standards or its own Protocol 

requirements.83 At most, pursuant to its Protocols, ERCOT can ask generators to 

refrain from taking a scheduled outage if it believes it may need the generator’s 

output. ERCOT also does not have authority under its Protocols to require 

generators that are on planned outage to come back into service early (assuming 

the generator is even in a condition to do so). Nor are there any market 

mechanisms to compensate generators for any costs associated with delaying or 

coming back early from a scheduled outage. 

Despite these potential limitations, ERCOT was far from being generation 

deficient for winter 2010/2011 seasonal planning purposes. Nor, as will be seen, 

did it appear to be deficient going into the storm itself. A little background is 

needed to put in context the generation that ERCOT thought it would be able to 

call upon during the storm. 

 82 NERC 2010/2011 Winter Reliability Assessment at 16. 

83 ERCOT Nodal Protocols § 3.1 (Nov. 20, 2010), available at

http://www.ercot.org/mktrules/nprotocols/2010/index. ERCOT is considering revising this 

provision to permit it to deny an outage request if it is scheduled 90 days or less from the outage 

date. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 54 - 

ERCOT uses proprietary forecasts (performed both on a seasonal and daily 

basis) to predict its load.84 ERCOT used those weather forecasts, coupled with 

historical and other information, to gauge expected customer demand during the 

approaching event. A task force review of ERCOT’s forecasts determined that 

they accurately predicted the February storm conditions, and in some cases their 

weather estimates were even slightly more accurate than those of the National 

Weather Service. 

ERCOT then compared the anticipated demand85 against its generation 

capacity, both for purposes of scheduling power in the day-ahead market and for 

determining whether it would meet reliability and reserve requirements. For 

operating purposes, ERCOT’s Protocols include a responsive reserve requirement 

(also referred to as Physical Response Capability, or PRC) of 2300 MW. The 

primary purpose of the responsive reserves is to restore system frequency to 60 Hz 

within the first few minutes after the system experiences a significant frequency 

deviation. The 2300 MW amount is based on a 1988 study that determined the 

reserves that would be needed to prevent the shedding of firm load upon the 

simultaneous loss of the two largest generation resources in the ERCOT region.86 

(Actual online responsive reserves at any given time typically exceed the 2300 

MW requirement.87) 

ERCOT Protocols

The ERCOT protocols set forth the procedures and processes 

used by ERCOT and its market participants for the orderly 

functioning of the ERCOT system and market. They contain 

(cont’d) 

 84 ERCOT relies on Telvent DTN and Pattern Recognition Technologies (PRT) for the 

weather data used in its load forecasts. 

85 ERCOT’s load forecast projected loads of 52,673 for February 1 and 57,436 for 

February 2. 

86 This is a more conservative measurement than that required by NERC Reliability 

Standard BAL-002-0 R3, which sets a “contingency reserve” requirement to cover the loss of the 

single largest contingency on a Balancing Authority’s or Reserve Sharing Group’s system (N-1), 

not the loss of the two largest contingencies. Because ERCOT is not synchronously linked with 

other interconnections, a larger reserve amount than N-1 is required to maintain proper frequency 

response. 

87 ERCOT’s daily morning report listed responsive reserves of 4196 MW for February 1 

and 5944 MW for February 2, projected for the peak hours of those days. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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policies for scheduling, operations, planning, reliability, and 

settlements, as well as ERCOT’s rules, guidelines, procedures, 

and standards. The protocols are developed and amended 

through stakeholder committees for approval by the ERCOT 

Board of Directors. Once approved at ERCOT, the protocols 

are submitted to the PUCT for final approval. In addition to 

its task of enforcing the FERC-approved Reliability Standards, 

TRE is responsible for compliance monitoring and 

enforcement of the ERCOT Protocols. 

In addition to the responsive reserve requirement, ERCOT must meet a 

non-spinning reserve requirement.88 These reserves are intended to address the 

risks of load uncertainty and wind power output variability. For February 2011, 

the non-spinning reserve requirement was set at 2000 MW. (The sources counted 

for non-spinning reserves are not included in the calculation of available resources 

for purposes of meeting the responsive reserve requirement of 2300 MW.89) 

Notwithstanding the fact that 11,566 MW of generation were on scheduled 

outage as of February 1,90 ERCOT had more than 3100 MW of responsive 

 88 Non-spinning reserves in ERCOT are generation resources capable of being ramped to 

a specified output level within thirty minutes and running at that level for at least one hour, or 

Load Resources that are capable of being interrupted within thirty minutes after being asked for 

interruption and remaining de-energized for at least one hour. 

89 Wind resources, which are forecasted on an hourly basis, are also not included in the 

calculation of available resources for purposes of meeting the responsive reserve requirement. 

One of the most significant differences between the NERC Winter Assessment and ERCOT 

operations is how wind power is handled. The NERC Winter Assessment assigns a fixed average 

output of 8.7 percent of nameplate rating as “existing-certain” generation capacity. For the 9317 

MW of installed wind capacity (aggregate nameplate rating) in ERCOT, this amounts to 811 

MW. Operations, on the other hand, utilizes wind power forecasts derived from highly localized 

wind speed forecasts, which provide wind power output values for each of the upcoming 48 

hours. The forecasts are re-run hourly and the results updated accordingly, yielding a “rolling” 

48 hour look-ahead. ERCOT’s Current Operating Plan (COP) for wind power uses a 

conservative estimate which has an 80 percent chance of being met or exceeded, and already 

takes into account any equipment outages, either scheduled or forced. On the morning of 

February 2, the aggregate COP for wind power peaked at about 5200 MW at 3:00 AM and 

decreased steadily each hour down to 3500 MW at 8:00 AM. The actual wind power output 

followed the same downward trend, but fell short off the COP numbers anywhere from 400 MW 

to 1000 MW, depending on the specific hour. (This snapshot picture exhibits the variability of 

wind power.) 

90 This number grew to 12,413 MW on February 2; however, the additional units might 

have been ones that experienced forced outages on February 1 and then transitioned into 

scheduled outages. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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reserves available throughout the entire 24 hours of that day, running as high as 

5600 MW in the early morning and again during the mid-afternoon hours. This 

exceeded the responsive reserve requirement of 2300 MW by a comfortable 

amount.91 

Thus, on paper, ERCOT had reason to believe it had ample generation 

going into the storm.92 As it turned out, the large number of generator outages, 

derates and failures to start that occurred on February 1 and February 2 would 

reduce that margin below acceptable levels. 

Aside from determining it had sufficient operating reserves listed as 

available, ERCOT took other steps to prepare for the storm. On January 31, 

ERCOT issued an Operating Condition Notice (OCN) to its market participants, 

advising them of the expected cold front. On February 1, it issued another OCN at 

2:45 AM and an Advisory at 9:05 AM. ERCOT also reported to the PUCT that it 

was expecting temperatures in the teens to the low 20s and maximum temperatures 

near or below freezing, with anticipated impacts on 50 percent or more of its 

major metropolitan areas.93 

Notices and Emergency Declarations

The ERCOT Protocols set out three types of preliminary notices to be 

issued by ERCOT to inform market participants of a potentially adverse operating 

condition, including extreme weather conditions such as hurricanes and protracted 

periods of below-freezing temperatures. The type of notice is determined based 

on the time available for the market to respond before an emergency condition 

may occur. 

(cont’d)

 91 On February 2, responsive reserves would hover in the range of 2700 MW to 3300 

MW in the early morning hours, dropping to around 3000 MW at 4:30 AM and then plummeting 

rapidly. 

92 In addition to the outages already underway, three planned generation outages were 

scheduled to begin during the time period covered by the anticipated storm. ERCOT requested 

one of these generators to delay the outage, as discussed later in the report. 

93 ERCOT did not provide any further market notices or indications of projected capacity 

shortages until 3:00 AM on February 2, when it issued an OCN and an Advisory reporting that 

reserves were below 3000 MW. These notices, as well as the other actions that took place on 

February 2, are discussed in the following section of this report entitled “The Event: Load Shed 

and Curtailments.” 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 Operating Condition Notice -- issued to inform participants of a possible 

future need for more resources due to conditions that could affect 

system reliability; allows ERCOT to confer with transmission providers 

and participants regarding the potential for adverse reliability impacts 

and contingency preparedness when adverse weather conditions are 

expected. 

 Advisory -- issued when conditions are developing or have changed 

such that more ancillary services will be needed, or when weather or 

conditions require more lead-time than the normal day-ahead market 

allows; allows ERCOT to increase ancillary services requirements 

above the quantities originally specified in the day-ahead market, and to 

require information from participants regarding their fuel capabilities 

for the next seven day period. 

 Watch -- issued when additional ancillary services are needed in the 

current operating period, or when forced outages or abnormal operating 

conditions have occurred or may occur that require operating with 

transmission security violations; allows ERCOT to instruct transmission 

owners to reconfigure ERCOT system elements to improve reliability in 

ERCOT; and allows ERCOT to take steps to procure additional 

regulation services, RRS services, and non-spinning services. 

ERCOT issues the fourth level of Notice, an Emergency Notice, when it 

cannot maintain minimum Reliability Standards or meet its Protocol requirements 

during the operating period or is otherwise in an unreliable condition. Depending 

on the severity level, ERCOT may take additional steps to resolve the system 

emergency, including relaxing transmission constraints, issuing public appeals for 

conservation, deploying Load Resources and EILS resources, and requiring firm 

load shedding. 

Between January 28 and January 31, ERCOT cancelled, withdrew, or 

delayed planned outages on ten 345 kV transmission lines, 27 138 kV 

transmission lines, two 345/138 kV auto-transformers and one 138/69 kV 

transformer (outage cancellation rules differ as between transmission and 

generation). On January 31, ERCOT requested one generating unit (Mountain 

Creek SES Unit 8 at 568 MW) to begin start-up due to its long start-up lead time, 

and requested another unit (Lake Hubbard SES Unit at 397 MW) to convert from 

natural gas to fuel oil in anticipation of possible gas curtailments.94 ERCOT 

reports that it did not request any generators to return early from scheduled 

 94 Texas Reliability Entity, Event Analysis Report – Feb.2, 2011 EEA-3 Event at 16 (Apr. 

15, 2011) (TRE Report). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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outages, nor did it request any generators to defer scheduled outages that were 

slated to start during the cold weather event.95 

In the afternoon of January 31, ERCOT decided to adjust its load forecast 

to factor in the potential effect of the high winds that had been predicted 

(ERCOT’s forecasts do not normally factor in wind chill effects). ERCOT made a 

manual adjustment to its load forecast for the remainder of February 1 and for 

February 2, adding 4000 MW. 

 

The storm hit on February 1. Beginning at approximately 12:00 PM on that 

day, power plants across Texas experienced problems due to the cold weather. 

These included freezing instrumentation, freezing pipes, freezing drain lines, 

natural gas curtailments, and natural gas pressure reductions due to high usage.96 

Between noon and midnight on February 1, two large coal units and 18 natural gas 

units tripped or failed to start for varying periods of time. Another six natural gas 

units and 13 wind plants were derated during this period. As of midnight on 

February 1, unavailable generation capacity in ERCOT (not counting scheduled 

outages) reached 6022 MW.97

In addition to the generation scheduled for February 2 by its economic 

dispatch model, ERCOT committed 24 additional generating units, totaling 3400 

MW, through its reliability unit commitment (RUC) process.98 By midnight, all 

available generation had been instructed to run on February 2. 

 

 95 ERCOT did discuss with generators deferring scheduled outages planned for the 

February 10 period, when cold weather was again anticipated. Some of those scheduled outages 

were postponed. 

96 TRE Report at 7. The details of the types and causes of the forced outages experienced 

during the February 1-5 weather event are discussed in detail in the section of this report entitled 

“Causes of the Outages and Supply Disruptions.” 

97 This is a net cumulative number; that is, if a failed unit came back online, it is not 

counted as unavailable. 

98 ERCOT initially committed 13 units through the RUC process on February 1, to be 

deployed on February 2; it later cancelled six of those unit commitments, leaving a net value of 

2049 MW in additional generation as of midnight on February 1. At 3:03 AM on February 2, 

ERCOT committed 19 units through its RUC process, totaling 1351 MW. Unit generation added 

on both days through the RUC process for February 2 deployment totaled 3400 MW. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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ERCOT’s RUC Process

After ERCOT completes the run of its day-ahead market, which matches buy and 

sell offers for energy and ancillary services for the following operating day, 

ERCOT runs a Day-Ahead Reliability Unit Commitment (DRUC) study to ensure 

that sufficient capacity is available to serve load. For each hour of the following 

day, the DRUC examines whether sufficient resources have been committed, 

through Day-Ahead awards or as otherwise reflected in each resource’s Current 

Operating Plan (COP), to meet the forecasted load for each hour. If ERCOT 

determines that any additional resources are needed, it can physically commit 

those resources for the hours needed, with certain payment levels guaranteed to 

the resources when ordered to run. 

ERCOT runs the DRUC study in the afternoon prior to the operating day studied. 

Hourly RUC (HRUC) studies are run thereafter, comparing resources and load for 

each hour remaining in the DRUC period and reflecting any changes in resource 

commitments (such as forced outages or modified COPs) or other changes in 

system conditions since the DRUC was run. 

The RUC process takes into account resources committed in the Day-Ahead 

market, resources self-committed in the COPs, and resources committed to 

provide ancillary services. The RUC process can also recommend decommitment 

of resources where transmission constraints are not otherwise resolvable. ERCOT 

can order any available resource to come online as part of the RUC process. 

If a resource is selected by the RUC, the resource will at a minimum be made 

whole for its startup and minimum-energy costs. However, if the energy revenues 

received during the RUC-commitment period are greater than these guaranteed 

costs, the resource may be subject to a “clawback” under certain conditions. 

 

Could or should ERCOT have done more to prepare for the event? ERCOT 

procedures specifically include provisions for severe cold weather operations.99 In 

anticipation of severe cold weather, ERCOT may issue an OCN, Advisory, Watch, 

or Emergency Notice. These various alerts allow ERCOT to react to potential 

operating conditions by: reviewing planned and existing outages; determining if 

more lead-time is needed for generating resources to meet their commitments than 

the normal day-ahead market allows; determining if additional ancillary services 

are required; ordering on additional units; and increasing staffing. Under the 

 99 ERCOT Operating Procedure Manual: Shift Supervisor Desk § 7.5 (July 18, 2011), 

available at http://www.ercot.org/mktrules/guides/procedures/. Severe cold weather is defined 

by expected temperatures in the mid to low 20 degree range with expected maximum 

temperatures near or below freezing, impacting 50 percent or more of major metropolitan areas. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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various alerts, ERCOT’s RUC Operator may also confer with transmission 

operators and QSEs100 regarding preparedness, fuel capabilities, the need to 

reconfigure system elements, or to vary from market timing deadlines.101 

In anticipation of the event, ERCOT arguably could have better utilized 

these tools to prepare for the severe cold weather, particularly by increasing 

ERCOT’s responsive reserves well in advance of its decision late on February 1 to 

schedule all available units for the next day.102 As events proved, the extensive 

generator outages substantially exceeded ERCOT’s reserves, and would have done 

so even if the reserves had been substantially larger in number. But this was not 

known by ERCOT going into the event. Furthermore, if generating units had been 

online and running, they would have been better able to withstand freezing 

temperatures,103 a consideration ERCOT might have factored into its decisionmaking process. 

Another strategy that might have improved generator response would have 

been the use of pre-warming techniques.104 ERCOT does not currently have the 

authority to require generators to engage in these actions, but if generators had 

done so, they might have prevented some of the extensive freezing problems that 

developed. Running quick start units prior to their scheduled start time could also 

 100 A “Qualified Scheduling Entity” (QSE) is a market participant qualified by ERCOT as 

a resource entity or a load serving entity, for purposes of communications with ERCOT and the 

settling of payments and charges. 

101 ERCOT Operating Procedure Manual, Reliability Unit Commitment Desk, Section 6.1 

(July 20, 2011), available at http://www.ercot.com/mktrules/guides/procedures/. 

102 ERCOT Protocols formerly required it to increase its spinning reserves by an amount 

at least equal to its responsive reserves during cold weather alerts. See Elec. Reliability Council 

of Tx., ERCOT Operating Guide No. 12 ( May 1989). ERCOT advised the task force that this 

protocol had been changed to account for the variability of wind power. ERCOT now carries 

non-spinning reserves continuously rather than only during peak hours, as was its former practice. 

ERCOT stated its belief that the continuous availability of non-spinning reserves serves virtually 

the same purpose as the former practice of doubling the spinning reserves. 

103 The use of a generating unit’s own radiant heat to prevent freezing is discussed in the 

section of the report entitled “Key Findings and Recommendations.” 

104 For conventional gas steam units, pre-warming can be accomplished by establishing a 

fire in the boiler to produce warming steam for the turbine while it is on turning gear. This keeps 

metal temperatures warm enough to prevent freezing in piping and instrumentation lines and 

helps bring lubricating and hydraulic oils up to proper operational temperatures. Combustion 

turbines can run at full speed no-load operation for short periods of time prior to start up, in order 

to warm vital parts, instrumentation, and lubricating oils. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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have identified problems before the output of the units was needed, giving them 

time to make corrections.105 

Had ERCOT and the generators undertaken these additional measures, it is 

possible that fewer generating units might have failed. ERCOT might still have 

been forced to shed load, but the extent of the load shed might well have been 

reduced. Every generator that could have escaped failure on February 1 and 

February 2 would have improved the situation for Texas consumers. 

 ERCOT Generators 

 

Most generators in ERCOT’s footprint reported having employed freeze 

protection measures to protect their facilities. These measures generally fell into 

two categories: physical readiness and operational readiness. 

 

 To prepare physical facilities for the cold weather, generators variously 

reported that they installed portable heaters to maintain ambient air temperature, 

added extra insulation to exposed components, installed temporary windbreaks to 

exposed areas, drained non-essential water systems, and determined that the water 

in essential water systems was circulating. 

 Some generators also reported adjusting their operations to adapt to the 

cold weather. They called in more operating and maintenance staff, increased the 

frequency of operator rounds, performed checks of freeze protection panels and 

heat tracing circuits, and added windbreaks. Plant staff also tested emergency 

equipment, added fuel to heaters and emergency generators, stocked extra supplies 

of fuels as well as food and other emergency items in case deliveries were 

disrupted, and prepared sleeping arrangements for employees if roads became 

impassable. Some generators utilized pre-operational warming during the 

event.106 

 Despite these reports of having taken steps to prepare for the cold weather 

event, many generating units in ERCOT failed to perform or suffered derates after 

 105 On February 1 and 2, approximately 19 simple cycle and combined cycle units in 

ERCOT tripped for non-weather related causes and were restored within two hours. Many of the 

simple cycle and combined cycle unit trips occurred immediately during start-up sequences or 

very soon after synchronization. 

106 On February 10 as well, some generators utilized pre-operational warming for that 

day’s cold weather snap. At least five generators kept their units running, started units earlier or 

took other measures to keep from having a “cold start.” These generators credited these strategies 

for their improved performance on that date. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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the storm hit. And they failed, in the majority of cases, because of weather-related 

problems. The various generator outages and their causes are examined in the 

section of this report entitled “Causes of the Outages and Supply Disruptions.” 

 Salt River Project

 SRP is a vertically integrated utility and owns its own generation, 

transmission, and distribution facilities. Its preparations for inclement weather 

therefore needed to encompass all three functions. In terms of its forecasting, SRP 

uses an Artificial Neural Network Short-Term Load Forecaster model, which 

projects control area loads. This model incorporates SRP’s own meteorologist’s 

weather forecast as well as hourly historical load data. SRP reported that while 

weather on February 2 matched its weather forecasts, its load forecast was lower 

than actual load demands. The disparity, however, was within five percent. 

 SRP has generating facilities located throughout central and northern 

Arizona. Winter temperatures tend to be mild in and around the Phoenix Valley 

but can be noticeably colder in the more remote areas where the company’s two 

coal burning facilities are located. SRP reports that it carries out preventative 

maintenance for facilities that have winterization equipment, which generally 

consists of heat tracing107 and insulation. Gas-fired generating plants in and 

around the Phoenix valley use winterization equipment to protect against expected 

conditions, while hydro generating facilities are almost exclusively contained 

inside protected buildings. SRP’s coal generating facilities at the Coronado and 

Navajo stations have winterization systems that consist mostly of heat tracing and 

insulation. SRP advised the task force that every year in the fall, planners for the 

Coronado and Navajo stations develop work orders to inspect and test these 

winterization systems to verify they are working properly, and that during the 

winter months, staff conduct weekly winterization and freeze protection 

equipment checks. 

 SRP’s immediate preparations for the February event were limited. It did 

not issue a cold weather alert in advance of the storm.108 SRP reports that 

management at the Navajo Generating Station did inform its operators at the 

beginning of shifts that cold weather was approaching, and inquired if there was 

anything the employees needed to help them do their job. SRP does not employ a 

 107 Heat tracing refers to the application of a heat source to pipes, lines, and other 

equipment. 

108 Indeed, the only alert the SRP Balancing Authority provided to generators was a 

“Capacity Alert,” indicating that maintenance and operations activities on all operating generating 

units were to be stopped. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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formal checklist of activities that should be carried out prior to a winter storm, and 

the company reported that the Operations and Maintenance Group at the Navajo 

Generating Station did not take any formal actions to prepare the station for the 

anticipated severe weather. However, SRP informed the task force that the group 

did hold meetings at which the need for staff to frequently check the generating 

equipment for potential weather-related problems was emphasized. 

 El Paso Electric

Like SRP, EPE is a vertically integrated utility. It reported to the task force 

that at the beginning of the winter of 2010/2011, as at the beginning of every 

winter, it took steps to winterize its generating facilities. This winterization 

included verifying that heat tracing was properly functioning, as well as making 

sure insulation was properly installed. 

EPE also reported that it verified that the equipment in its substations, the 

part of the transmission and distribution system most susceptible to cold 

temperature extremes, could withstand the expected cold temperatures. 

On January 31, 2011, EPE initiated preparations for the anticipated severe 

weather, which included verifying winterization of generation, transmission and 

distribution facilities, reviewing system operations plans, checking on the 

availability of fuel, preparing for potential pipeline constraints, and placing 

employees on call as needed during the weather event. The Systems Operations 

group requested EPE’s Power Marketing and Fuels group to keep additional 

generation online. In response, the Power Marketing and Fuels group made 

arrangements to leave on Rio Grande Unit 6, to continue with the start-up of 

Newman Units GT-3 and GT-4, and verified the ability of Newman Unit 3 to 

operate on fuel oil. 

In contrast to some other areas in the region, EPE reported that actual 

weather during the event was more severe than forecasted (and significantly colder 

than historical temperatures). For February 2, EPE reported that the actual high 

temperature in El Paso was 15 degrees compared to a forecasted high of 37 

degrees, and the actual low temperature was 6 degrees compared to a forecasted 

low of 14 degrees. The forecasted high for February 3 was 30 degrees, compared 

to an actual high of 18 degrees, and the forecasted low was 14 degrees, compared 

to an actual low of 1 degree. For February 4, the last day of the freeze event in 

EPE’s service territory, the forecasted high of 43 degrees compared to an actual 

high of 37 degrees, and a forecasted low of 21 degrees compared to an actual low 

of 3 degrees. EPE did not report the exact location for its temperature statistics, 

but presumably they occurred in the west Texas and New Mexico regions. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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C. Preparations for the Storm: Natural Gas

Varying levels of preparation for the February cold front were employed by 

the producers, processing plants, interstate pipelines, intrastate pipelines, and 

LDCs that together make up the natural gas delivery chain. Depending on the 

type of facility, preparations included at least one, if not several of the following 

items: monitoring the weather, increasing staffing, methanol injection, pigging, 

insulation, tarps, heat tracing, building line pack109 in pipelines by injecting more 

gas, over-purchasing gas supplies and enhancing winterization equipment. For the 

most part, facilities began their preparations by either Sunday, January 30 or 

Monday, January 31. 

This section describes the preparations taken by individual companies in 

west Texas, the Texas panhandle, north Texas and New Mexico and by the LDCs 

in Arizona and New Mexico. 

Producers 

As discussed in detail in the section of this report entitled “Causes of the 

Outages and Supply Disruptions,” the difficulties encountered by LDCs in trying 

to meet customer demand stemmed principally from supply declines in the basins, 

and secondarily from problems encountered at processing plants. The 

preparations for the cold weather event taken by producers is therefore of special 

interest. 

Of the 15 producers who provided information to the task force on this 

issue, all reported that they had used winterization techniques of one sort or 

another. The following table shows by basin the numbers of producers that used 

one of or more of the listed methods. 

 109 Line pack refers to the volume of gas in the system at any given point in time. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 PERMIAN SAN 

JUAN 

FORT 

WORTH 

EAST 

TEXAS 

TEXAS 

GULF 

Methanol 

Injection 

or Drip 

    

Increased 

Pigging or 

Clearing 

of Liquids 

    

Tarps or 

Cold 

Weather 

Barriers 

   

Increased 

Hauling of 

Fluid 

    

Heated 

AntiFreeze 

 

Heat 

Trace 

    

Hot Oil 

Trucks 

 

Insulation    

Burial of 

Lines 

 

Heat 

Lamps or 

heaters 

  

A short description of some of these techniques gives a fuller picture of the 

actions the producers reported having taken: 

 Methanol (an anti-freeze type solution) injection or drip is a 

common practice for freeze protection of wellbores and pipelines. 

The methanol is injected into the gas stream by chemical injection 

pumps or enters the pipeline by methanol drips and effectively 

lowers the freeze point of the gas. Also, separators (used to separate 

liquids such as oil from the natural gas) may be filled with heated 

antifreeze to prevent freezing. 

 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 Pigging refers to the practice of using pipeline inspection gauges or 

“pigs” inside a pipeline to perform various operations without 

stopping the flow of gas. Pigging operations are conducted on a 

year-round basis as needed to keep pipelines in working flow 

conditions. During cold weather their deployment can be increased 

to remove liquids that might be prone to freezing. 

 Cold weather barriers are a relatively simple weather precaution 

involving the erection of wind walls around certain compressors to 

block cold winds that exacerbate freezing conditions. Wrapping and 

insulating surface equipment, injection lines, supply valves, water 

lines and other locations may also help prevent freezing and the 

stoppage of fluid flow. 

 Hauling oil and produced water from storage tanks is a necessary 

part of the production process, since tanks that are not emptied can 

trigger fail safe shut-in devices that will automatically shut down the 

well. Prior to cold weather, and in anticipation of trucks not being 

able to reach the facilities, the tanks may be emptied to reduce the 

likelihood of automatic shut-off. 

 Heat can prevent freezing problems; if the gas is never allowed to 

reach freezing temperatures, ice cannot form. However, heat 

application involves expensive equipment and requires additional 

fuel. Heat is also a potential hazard as it can provide an ignition 

point for the gas. Nonetheless, heat systems can be very effective 

for a localized freezing problem, and include heating blankets, 

catalytic heaters, fuel line heaters, or steam systems. Coupling heat 

systems with insulation is a common technique for protecting flow 

lines in northern climates. 

 Hot oil trucks may be utilized to thaw out flow lines. Typically the 

hot oil truck will be filled with water, which is then heated and 

directly sprayed onto lines at risk of freezing. 

As it turned out, the various measures producers described as having 

employed to prepare for the projected cold weather proved inadequate; a 

substantial number of wells in the affected basins suffered freeze-offs, which had a 

significant effect on production during the February cold weather event. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Processing Plants 

Individual processing plants reported making anywhere from minimal to 

extensive preparations. Their winterization included: 

 Making equipment checks; 

 Adding 24-hour staff and adding to nighttime crews; 

 Installing insulation; 

 Confirming that heat trace equipment was operational; 

 Placing tarps as wind breaks and to capture heat; 

 Draining water from cooling systems and fluids from piping low 

points; 

 Coordinating with upstream gathering; 

 Reviewing past winter events; and 

 Installing hot oil heaters. 

A representative sampling of processing plant preparations follows. 

The Crosstex Energy-affiliated Silver Creek natural gas processing plant in 

Weatherford, Texas processes Barnett Shale production from the Fort Worth 

Basin. In preparation for the weather event, operating personnel reportedly 

performed checks on all equipment, confirmed that all heat trace equipment was 

turned on prior to the storm, installed tarps on critical equipment, and drained all 

air supply low points. (Despite these precautions, the plant did experience a shut 

down of a steam boiler due to a freezing amine/water mixture.) 

Enbridge Energy Company, Inc. operates processing plants in east Texas 

and in north Texas. Generally speaking, operations in both the east Texas and 

north Texas plants continued in a routine manner prior to the storm. 

Energy Transfer Corporation (Energy Transfer) owns and operates the La 

Grange processing plant in east Texas and the Godley processing plant in north 

Texas. As part of its general preparation for cold weather at the La Grange plant, 

Energy Transfer wrapped air regulators and hung tarps around vessels. In late 

January, an extra operator was placed on duty. With regard to the Godley plant, 

Energy Transfer had previously installed louvers on all amine still overhead 

condensers110 to assist in cold weather operations. A hot oil heater had also been 

installed in a still condenser to prevent freezing. In addition, prior to the February 

weather event, Energy Transfer insulated condenser piping at two plants. 

 110 The term “amine still overhead condensers” refers to a piece of equipment used to 

remove the acid gases from the natural gas stream. 
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MarkWest Energy Partners has two processing plants in Texas. The 

company reported that both processing facilities are equipped to run during 

extreme cold weather and that no additional maintenance, insulation or heat 

tracing was performed prior to the February cold weather event. 

Williams Midstream has four processing facilities, the Markham Cryogenic 

processing plant in Matagorda County, Texas; the Milagro treating plant in San 

Juan County, New Mexico; the William FS Kutz (Kutz) processing plant in San 

Juan County, New Mexico; and the Lybrook processing plant in Rio Arriba 

County, New Mexico. The company reported that the Milagro plant and related 

facilities are designed to operate in cold weather. Nevertheless, it is standard 

practice at the plant to check heat tracing controls and piping insulation in the fall 

months. For the February event, preparations consisted of round-the-clock 

staffing for certain facilities and adding staffing for the night crew. Standard 

winter preparation at the Kutz plant reportedly includes coordination with 

upstream gathering, draining of water cooling systems, placing catalytic heaters 

into service, installation of wind barriers and group review of past events. In 

January and February 2011, additional contractor personnel were provided for 

night operations and additional heat wagons were placed based on needs. The 

Lybrook plant had also addressed winter preparation prior to 2011 by upgrading 

and inspecting piping, tracing, and insulation, and by making repairs to hot oil 

pumps. 

 

Pipelines 

Pipelines also prepared for the anticipated cold snap. Typical preparations 

for both interstate and most intrastate pipelines included: 

 Maintaining higher than normal line pack; 

 Optimizing compressor operations; 

 Enhancing internal communication such as cold weather operational 

meetings; 

 Increasing availability of personnel; 

 Cancelling scheduled maintenance where possible; and 

 Communicating with customers. 

 

 Interstate Pipelines 

Individual interstate pipelines reportedly took the following preparations: 

EL Paso prepared for the forecasted colder weather by maintaining higher 

than normal line pack throughout the weekend of January 29 and January 30. (El 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Paso considers line pack volumes between 7,200 MMcf and 7,800 MMcf at any 

given point in time to be in the normal range; at line pack quantities below 7,200 

MMcf or above 7,900 MMcf, El Paso generally considers its system to be at or 

approaching stressed operational conditions.) On Monday afternoon, January 31, 

El Paso began gas withdrawals from its Washington Ranch Storage Facility, 

reaching the field’s maximum withdrawal rate by the morning of February 1. This 

was done to compensate for gas supply underperformance in the San Juan and 

Permian Basins. 

Natural Gas Pipeline Company of America (NGPL) uses its Texas facilities 

to receive gas in Texas and redeliver that gas to markets in the upper Midwest. 

For February 1 through February 3, NGPL put in place a severe weather operating 

procedure that provided for management of cold, high winds, ice and snow. This 

procedure included conferences and communications involving the managers of 

the gas control and commercial groups of impacted NGPL facilities. Additional 

actions reportedly taken by the gas control group included adjusting pipeline 

pressures to meet anticipated load increases, manning facilities on an around-theclock basis, and carrying out operating procedures designed to keep facilities from 

freezing. 

Transwestern began operating its compression stations to maximize 

pressures in New Mexico in advance of the cold weather event. 

ANR Pipeline Company (ANR) has no facilities in New Mexico, Arizona 

or California, and only limited facilities in Texas, which are located in the 

northeast corner of the Texas panhandle (this is the southern-most part of ANR’s 

Southwest Area). To prepare for and respond to operating concerns and ongoing 

and expected weather events, ANR conducted daily morning operations meetings. 

An additional “cold weather” operational meeting specifically addressed the week 

of February 1. ANR reported reduced horsepower at all its Southwest Mainline 

compressor stations to help flow gas south into the Texas area if scheduled supply 

decreased, with the aim of maintaining adequate line pack and constant pressures 

in Texas and Oklahoma. 

 Intrastate Pipelines 

 Intrastate pipelines in general employed many of the same preparations as 

did the interstate pipelines. Reported examples are provided below. 

 Atmos Pipeline –Texas began building line pack on January 31, and 

advised shippers to be in hourly and daily balance effective 9:00 AM on February 

1. This action assisted with maintaining line pack. Electric generation customers 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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were advised that deliveries would be limited to Tier 3111 beginning at 9:00 AM 

on February 1. Third-party interruptible storage customers were advised that they 

would be limited to 50 percent withdrawals effective February 1 at 9:00 AM. 

 Energy Transfer Partners reported ensuring that critical stations were 

staffed, spare compressors were placed on standby, line pack was increased, and 

all scheduled maintenance was postponed. 

 Enterprise Products Partners reported closely monitoring nominations. 

Staffing coverage was extended in addition to employees' normal schedules. 

Operations were also reviewed for potential service adjustments that might be 

required, although none were anticipated. 

 The Kinder Morgan Texas Pipes’ natural gas pipeline operations and gas 

control group initiated the Kinder Morgan Gas Pipelines’ severe weather operating 

procedure, designed to manage facilities in the event of severe cold, high winds 

and frozen precipitation. The procedure prescribes conferences and 

communications among managers and the gas control and commercial groups, and 

these communications began several days prior to the cold weather event. The gas 

control group also adjusted pipeline pressures in anticipation of increased load. In 

the field, some facilities were reportedly staffed around-the-clock, and procedures 

were put in place to keep facilities from freezing. 

Local Distribution Companies 

 Each of the four LDCs that curtailed customers during the February 

weather event reported making preparations. They monitored weather forecasts 

before the event and revised their load forecasts upward. They also increased their 

purchases of gas to accommodate increased demand and to compensate for freezeoffs, and communicated with suppliers and the pipelines about pending conditions. 

As conditions worsened, these communications became more frequent. 

 New Mexico Gas Company packed transmission lines with extra gas, and 

confirmed that the storage facility it accesses was positioned for withdrawals. 

Additional gas was purchased for the expected increased demand and in 

anticipation of freeze-offs. From February 1 through February 3, NMGC had, for 

each respective day, pre-purchased 36 percent, 55 percent, and 62 percent more 

gas than its forecasted need. NMGC issued an Alert to all transportation 

customers concerning the weather forecasts. Given the severity of the anticipated 

 111 Tier 3 restrictions applying to electric generating units limit the amount of natural gas 

the units can take. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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storm, at 9:00 AM on February 2, NMGC began requesting that large industrial 

and commercial customers throughout the state voluntarily reduce or curtail their 

gas usage. In total, NMGC reported contacting 39 customers, asking for voluntary 

curtailment.

 The following is a chart of NMGC’s line pack, juxtaposed with its 

preparation events. 

 Source: New Mexico Gas Company 

Southwest Gas monitored current weather forecasts on January 30 and 

January 31, which indicated colder temperatures were expected for southern 

Arizona. On February 1, a scheduled meeting of engineering and technical 

services personnel was expanded to include discussions concerning cold weather 

preparations and system monitoring.

 Zia Natural Gas Company (Zia), after observing the dramatically dropping 

temperatures forecasted for February 1 through February 4 for the state of New 

Mexico, contacted its primary supplier on January 30 to discuss its supply and 

receipt options. On February 1, Zia discussed maximum volumes that could be 

nominated on its pipeline transportation contract. 
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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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V. The Event: Load Shed and Curtailments 

 When the storm hit the Southwest on February 1, both electric and natural 

gas facilities began experiencing outages and other production difficulties. These 

difficulties escalated and ultimately led to load shedding by three electric 

balancing authorities and service curtailments by four gas LDCs, beginning on 

February 2. The unfolding events that led to these disruptions, and the conduct of 

the load shedding and curtailments, are described in this section. 

A. Electric

 ERCOT, SRP and EPE all engaged in load shedding during the cold 

weather event. Other electric entities in the area, although they experienced 

generation losses, were able to avoid load shedding (with the exception of PNM, 

which experienced some small, localized load loss from transmission issues). 

Each affected utility’s actions are discussed separately below. (All times 

referenced are expressed in local time.) 

ERCOT 

ERCOT’s required responsive reserve level is 2300 MW.112 This is the 

amount that ERCOT has determined to be necessary on its system to ensure that 

the system will maintain frequency and voltage stability; that thermal and voltage 

limits will remain within applicable ratings; and that there will be no loss of 

demand, curtailment of firm transfers, or cascading outages.113 If reserves drop 

below specified amounts, ERCOT is required by its Protocols to take actions to 

bring them up again, including the shedding of load. 

ERCOT has specified in its Protocols certain triggering events that require 

taking action to prevent the uncontrolled loss of firm load. In doing so, it has 

patterned its emergency alert protocol on the Reliability Standard that prescribes 

 112 As discussed in the section of this report entitled “Preparations for the Storm,” this 

amount was based on a 1988 study designed to determine the amount of reserves needed to 

prevent shedding of firm load if ERCOT’s two largest contingencies occurred. 

113 This minimum level of reserves is based on an N-2 criterion, a more conservative 

requirement than that required by the FERC-approved Reliability Standard BAL-002-0 R3.1, 

which requires that “as a minimum, the Balancing Authority or Reserve Sharing Group shall 

carry at least enough Contingency Reserve to cover the most severe single contingency.” 

ERCOT’s N-1 largest single contingency would be the loss of a nuclear-powered generating unit 

at the South Texas Nuclear Project, rated at 1354 MW. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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an energy emergency alert procedure.114 Both the Reliability Standard and the 

ERCOT Protocol categorize these triggering events into three levels, Levels 1, 2, 

and 3; ERCOT further subdivides Level 2 into 2A and 2B. 

ERCOT had to make decisions throughout the morning of February 2 

regarding the declaration of these various emergency alert levels and actions. That 

was particularly so with respect to Level 3, which requires the shedding of firm 

load. 

Energy Emergency Alerts

Reliability Standard EOP-002-2.1 prescribes the use of an energy emergency alert 

(EEA) procedure when a load serving entity is unable to meet its customers’ 

expected energy requirements. These energy emergencies are declared by the load 

serving entity’s reliability coordinator, and are categorized by level of severity: 

 EEA 1 - For conditions where all available resources are committed to meet 

firm load and reserves, all non-firm sales have been curtailed, and the entity 

is still concerned about sustaining its operating reserves. 

 EEA 2 - For conditions when the entity is no longer able to meet expected 

energy requirements, and is designated an Energy Deficient Entity. 

 

The entity is to do the following, as time permits: 

 Public appeals to reduce demand, 

 Voltage reduction, 

 Interruption of non-firm loads, 

 Demand-side management, and 

 Utility load conservation measures. 

Other entities are to provide emergency assistance as appropriate 

and available. 

 EEA 3 - For conditions when the energy available to the Energy Deficient 

Entity is only accessible with actions taken to increase transmission transfer 

capabilities. 

 At this point, firm load interruption is imminent or in progress. 

(cont’d)

 114 See Reliability Standard EOP-002-2.1 (Capacity and Energy Emergencies). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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ERCOT:

ERCOT has particularized this emergency energy alert system to the requirements 

of its own system. It is required under its Protocols to perform certain actions 

upon the occurrence of distinct triggering events. These are as follows: 

Level / Triggering Event / System Operations Actions

 EEA 1 Less than 2300 MW of Reserves: 

 Use capacity available from DC ties, dispatch 

 uncommitted units. 

 EEA 2A Less than 1750 MW of Reserves: 

 Deploy Load Resources (LR); begin block-load 

 transfers of load to neighboring grids. 

 EEA 2B To maintain system frequency at 60 Hz or reserves trending 

downward or not available: 

 Deploy Emergency Interruptible Loads (EILS) if 

 available. 

 EEA 3 To maintain system frequency at 59.8 Hz or greater: 

 Instruct transmission operators to shed load via 

 rotating outages in blocks of 100 MW. 

As discussed in the preceding section of this report, “Preparations for the 

Storm,” severe weather conditions on February 1 precipitated numerous forced 

generator outages within ERCOT’s footprint. By midnight on February 1, 6022 

MW of generation capacity was unavailable due to weather-related forced outages 

and derates, and conditions worsened overnight. 

 Generation Shortfalls on February 2 

By 3:00 AM on February 2, responsive reserves had dropped below 3000 

MW. ERCOT issued both an OCN and an Advisory to market participants, 

notifying them of the severe weather and the falling reserve level.115 It followed 

this communication with an emailed report to the PUCT about the falling reserves. 

 115 The communication steps taken by ERCOT appear to be consistent with its Operating 

Guidelines and Protocols. However, a number of transmission providers have stated they could 

have been better prepared to implement their required load shed if they had had more information 

about ERCOT’s deteriorating system status much earlier during the overnight period of February 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 At 4:30 AM, ERCOT operators instructed deployment of 1840 MW of nonspinning reserves, principally combustion turbines. (Non-spinning reserves 

require 30 minutes or longer to come on-line or to ramp up to their next block of 

power output.) Ten of the units, or a total of 669 MW of capacity, were unable to 

respond, many because they failed to start. By 5:08 AM, reserves had dropped 

below 2500 MW, and ERCOT issued a Watch. 

 ` 

 ERCOT calculates its operating reserves on a real-time basis by comparing 

metered demand with its available generation resources. At the same time 

generation was dropping off during the morning of February 2, demand was rising. 

The cold weather and winds were placing extraordinary demands for power on the 

system, and load was running consistently higher than had been forecasted for the 

day. In fact, at 5:20 AM the demand was 2760 MW higher than on any other day 

in the history of the ERCOT region at that hour, and was rapidly climbing.116 The 

following chart, prepared by TRE, compares actual demand with forecasted 

demand. 

 The actual peak demand for the day, which typically occurs in the morning 

around 8:00 AM, was artificially skewed downward because of the load shed. The 

 

1 to February 2. They would have liked to have received such information as soon as ERCOT 

began seeing a high number of forced generator outages. 

116 Potomac Economics, Ltd., Investigation of the ERCOT Energy Emergency Alert Level 

3 on February 2, 2011, at 3 (April 21, 2011) (Potomac Report), available at

http://www.puc.state.tx.us/files/IMM_Report_Events_020211.pdf. 
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IMM (Potomac Economics, Ltd.), the market monitor for ERCOT, estimated that 

the demand that would have materialized absent any load reductions or 

curtailments would have peaked at 59,000 MW, just after 7:00 AM.117 This 

estimate suggests that the high demands already being placed on the system in the 

early morning hours would likely have continued to escalate. 

 At 5:09 AM, reserves dropped below 2300 MW, the triggering event for 

ERCOT’s declaration of an EEA 1 (although it was not declared, presumably 

because events were moving so swiftly). At 5:20 AM, responsive reserves had 

dropped below 1750 MW, and ERCOT issued an EEA 2A. It also deployed 888.5 

MW of Load Resources, with 881.7 MW responding. Load Resources are counted 

as responsive reserves and, as such, their deployment reduces ERCOT’s 

responsive capability. In this case, however, two factors worked to offset this 

reduction: 

 

o The dropping of 881.7 MW of load increased the margin between 

generation and load, and ERCOT allowed a fraction of this increase to 

be allocated to responsive reserves. (The fraction ERCOT allots is 

typically 20 percent, but varies based on the specific generation online 

at any given time.) 

o The Load Resources were being deployed over a 10-minute interval 

during which some additional generation was actually coming online, 

despite all the problems on the system.

 As a result of these factors, for a short time while Load Resources were 

being deployed, responsive reserves actually increased by about 200 MW. It was 

not long, however, before additional forced outages and derates of generation, 

combined with the normal pick-up of morning demand, again decreased the level 

of responsive reserves.118 

 At 5:26 AM, ERCOT deployed RRS reserves, a form of interruptible load, 

which briefly raised the reserve level to above 1400 MW. 

 

 117 Potomac Report at 3-5. The estimate was based on several factors, including the 

actual load and rate of load increase prior to the implementation of the first load curtailments, the 

load shape on similar days, and ERCOT load forecasts produced just after 3:00 AM on the 

morning of February 2. 

118 Responsive reserves would ultimately fall to a low point of 447 MW at 6:25 AM, after 

the load shed had already begun. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 More units, however, continued to trip off-line. Responsive reserves 

briefly dipped below 1354 MW (the N-1 contingency reserve level required for 

safe operation of the system) twice before 5:40 AM. At that time, the responsive 

reserves dropped below the N-1 contingency level for an extended 73 minute 

period.119 

 At 5:43 AM, ERCOT declared an EEA 3 and began the process of shedding 

load. 

 The following graph120 indicates the relationship between ERCOT’s 

available capacity, loads and reserves throughout the day. 

 Counting both February 1 and February 2, a total of 193 generating units in 

ERCOT tripped, had derates, or failed to start, representing a loss of 29,729 MW 

of capacity.121 At the lowest point of available generation, which occurred at 6:12 

 119 There were six times during the morning of February 2 when ERCOT’s response 

reserves fell below 1354 MW. Those times are: 5:23-5:29 AM, 5:31-5:32 AM, 5:40-6:52 AM, 

7:11-7:30 AM, 8:39-8:52 AM, and 10:58-11:15 AM, for a total of two hours and 14 minutes, 

with the longest interval 73 minutes. (Calculation of the time periods includes the beginning and 

ending minutes.) 

120 Potomac Report at 6. 

121 This is a gross cumulative number; a unit is counted as having failed regardless of 

whether it came back online at some point during the event. This measurement gives an 
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AM, there were 14,702 MW of generation offline from such trips, derates, or 

failures to start. Adding that number to the scheduled outages for the day of 

12,413 MW, means that 27,115 MW, or approximately one-third of the total 

ERCOT fleet, was unavailable to provide power. 

 The following two charts depict the net and gross cumulative capacity 

reduction resulting from forced outages, derates, and failures to start, as added to 

the scheduled outages, for these two days.122 Comparing these numbers to total 

ERCOT generation of approximately 79,700 MW123 gives a picture of the 

magnitude of the generation loss, as well as of the difficulties that confronted 

ERCOT’s operators on those two days. 

 

indication of the total amount of capacity that failed during the event (rather than the amount 

offline at any given point in time). 

122 The first chart depicts net outages after subtracting out units that came back online. 

The second chart shows cumulative outages with no adjustment for units that came back online. 

123 The 79,700 MW number represents total ERCOT fleet capacity, online and offline, 

measured at 8:00 AM on February 2 (it does not include imports over the DC ties). The wind 

power capacity embedded in that number, as well as in the capacity reductions for the outages, 

derates, and failures to start, has been adjusted to reflect the actual hourly wind speed conditions 

(in lieu of using straight “nameplate” values which pertain only to optimum wind speeds that 

produce full rated output). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 The task force has also prepared charts for February 1 and February 2 that 

depict, hour by hour, the MWs that failed and the MWs that were restored, both by 

fuel type and by type of failure (trip, derate, or failure to start). These charts give 

a running picture of the fluctuations in available capacity, by fuel type, at any 

given point in time throughout the event. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Capacity Fluctuations by Fuel Type on Feb. 1, 2011

Capacity Fluctuations by Fuel Type on Feb. 2, 2011

 The various reasons for the outages, derates and failures to start that 

occurred during the event (the majority of which were weather-related, either 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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directly or indirectly) are discussed in the following section of this report entitled 

“Causes of the Outages and Supply Disruptions.” 

 

Adjusted Wind Power Capacity

The capacity of a wind power installation is typically reported on a “nameplate” 

basis, with the nameplate value representing what the facility can produce when 

the actual wind speed is optimum for the particular turbine design. When a wind 

farm is offline on a scheduled or forced outage, the capacity unavailable to the 

system is also typically reported on a nameplate basis; the same is true for partial 

outages, which are reported as derates (collectively, nameplate outage value). 

The actual wind speed, however, is seldom sufficient to produce full nameplate 

output simultaneously throughout ERCOT. Therefore, the nameplate outage 

values must be adjusted downward to realistically represent the impact of outages 

and derates of individual wind facilities. 

Adjusted Outages and Derates

The total installed wind power nameplate capacity in ERCOT is 9321 MW. If the 

aggregate nameplate outage values reported during February 1 and February 2 are 

subtracted from this 9321 MW total, nameplate available values are obtained on 

an hourly basis. Dividing the actual measured aggregate wind power output for 

any given hour by the nameplate available value for the same hour produces a 

percentage output that reflects how strongly the wind is blowing compared to fulloutput levels. Over the course of February 1 through February 2, that percentage 

varied from 40 to 75 percent (which is atypically high). To determine adjusted 

outage values, the percentage for any given hour is applied to the nameplate 

outage value for that same hour. For example, if the reported nameplate outage 

value for the 5:00 AM hour was 3200 MW, and the percentage output was 50 

percent, the adjusted outage value is 1600 MW. This value more realistically 

represents the additional wind power that would have been supplied to the ERCOT 

grid had it not been for the wind farm outages and derates. 

Although this method does not take into account the fact that the wind speed at a 

specific location where a forced outage has occurred may or may not correlate 

with the average value, any errors at individual locations should tend to offset one 

another. The method also assumes that the reports of forced outages and derates 

were made on a timely basis, which may or may not have been the case. 

(cont’d)
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Adjusted Capacity

NERC used 8.7 percent of nameplate capacity in calculating the contribution of 

wind power to existing generation in its 2010-2011 Winter Assessment of the TRE 

region. This is a planning number that has merit for the seasonal overview, but is 

not applicable to the high wind conditions of February 1through February 2. 

Therefore, in determining the wind power capacity in ERCOT for purposes of this 

inquiry, the task force multiplied the total installed capacity of 9321 MW by the 

percentage of output actually achieved by those facilities that remained in service, 

compared to nameplate capacity. The resulting adjusted capacity represents what 

the total wind power output would have been in ERCOT had there not been any 

outages or derates during February 1 through February 2. Since the percentage 

varies with the wind speed, adjusted capacity values were calculated hourly. At 

8:00 AM on February 2, the percentage of output vs. nameplate was 57 percent, 

yielding an adjusted capacity of 5313 MW (0.57 x 9321 MW). This number was 

then used as wind power’s contribution to the total generation fleet. Counting all 

units, both online and off, that total came to 79,658 MW for the 8:00 AM hour. 

(Since the adjusted capacity value changes hourly based on wind speed, so too will 

the numerical size, in MWs, of the total generation fleet.)

 The Load Shed Decision

 Load shedding is implemented to correct an electrical power imbalance if 

load exceeds supply and system operators cannot bring the system back into 

balance through other measures. Load shedding may be used to reduce an 

overload condition (such as when thermal limits on a transmission line are 

exceeded), to recover from an under-frequency condition, or to return voltage to a 

normal level. The operation can be manual (operator-initiated) or automatic 

(relay- initiated), depending on how quickly the frequency is decaying or the 

voltage is falling. For slowly declining frequency or voltage issues, the manual 

option is usually chosen. For rapidly declining frequency or voltage, the 

automatic option will respond without operator intervention. 

 ERCOT utilized operator-initiated load shedding on February 2, which 

preserved the system’s ability to implement automatic load shedding had system 

conditions continued to deteriorate. Had ERCOT not instituted manual load 

shedding, automatic under-frequency load shedding would have been a last resort 

before a possible system collapse. Manual load shedding also helped raise the 

frequency levels, preventing damage to generator turbines. 

 

The task force considered the question of whether ERCOT’s decision to 

manually shed load prevented more extensive blackouts than were experienced as 

a result of the load shed itself. While a definitive answer would require extensive 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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modeling and data inputs, the task force concluded, based on the information 

available, that ERCOT’s declaration of an EEA 3 probably prevented widespread, 

uncontrolled blackouts throughout the ERCOT Interconnection. Because ERCOT 

operates as a functionally separate interconnection from its neighboring Eastern 

and Western Interconnections and is linked only by asynchronous ties, the 

blackouts would not have propagated further.124 

Frequency Response and Automatic Under-Frequency Load Shedding

Frequency as a measure of the reliability status of a power system can be 

likened to pulse or heart rate as a measure of human health. It provides a key 

indicator of the overall integrity of operations. Maintaining frequency requires 

balancing a system’s aggregate generation output to load moment-to-moment. It 

also requires having sufficient reserves available at all times to withstand the 

sudden loss of the largest generator on the system, in order to instantaneously 

make up for the loss of power and thus reestablish balance. 

In spite of the enormous amount of generation that was forced off line in 

successive waves in ERCOT on February 1 and February 2, especially during the 

overnight and early morning hours between the two days, the overall frequency 

response of the system was not problematic during the event. Nonetheless, the 

need to maintain frequency to prevent a collapse of the system was the 

fundamental driving force behind ERCOT’s decision to shed firm load. 

Because ERCOT is not synchronously connected to either the Eastern or 

Western Interconnections, all frequency response must come from internal 

resources. And because ERCOT is smaller than the other interconnections, the 

loss of a generator results in a steeper frequency decline, necessitating a more 

robust frequency response. For this reason, in 1988 ERCOT established a 

minimum responsive reserve requirement of 2300 MW, based on an N-2 criterion 

covering the loss of the two largest generators in ERCOT (one nuclear-powered 

unit and the next largest unit on the system). This is a larger reserve than the N-1 

criterion required by Reliability Standard BAL-002-0 R3.1. On the morning of 

(cont’d)

 124 NERC has prepared a study on the reliability implications of the February cold 

weather event entitled “Analyses of Reliability Impacts on the Bulk Power System.” The study 

discusses the impacts on the WECC Interconnection of the events in SRP, EPE, and PNM, and 

presents an analysis of frequency response performance during the event by the Eastern 

Interconnection and the ERCOT Interconnection. NERC plans to make the study publicly 

available. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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February 2, 2011, the largest single contingency was an online nuclear-powered 

generating unit with a capability of 1354 MW. 

ERCOT maintains and closely monitors its responsive reserve levels (also 

referred to by ERCOT as its Physical Response Capability, or PRC), to comply 

both with its own 2300 MW criterion and with the 1354 MW minimum criterion. 

ERCOT relies on demand side load resources to provide up to 50 percent 

(1150 MW) of its 2300 MW responsive reserve requirement. These resources 

automatically disconnect when the frequency declines to 59.7 Hz. The purpose of 

the responsive reserves, both generation and load, is to arrest frequency declines 

before they reach 59.3 Hz (the trigger threshold for the first block of automatic 

under-frequency load shedding (UFLS)), and to restore frequency to 60 Hz within 

a few minutes following an event. Should either generation or load resources be 

deployed manually by system operators, they are no longer available to provide 

frequency response. 

Between 5:15 AM and 1:20 PM on February 2, responsive reserves 

dropped below the 2300 MW N-2 criterion three separate times, of varying 

durations. Ultimately, responsive reserves dropped below the 1354 MW N-1 

criterion. This occurred six separate times between 5:23 AM and 11:15 AM, for a 

combined total of 134 minutes, with the longest interval being 73 minutes. During 

the times when responsive reserves were below 1354 MW, had the largest 

generator tripped, reserves would have been insufficient to reestablish the balance 

between generation and load. The result would have been an inexorable decline in 

frequency which, when it reached 59.3 Hz per second, would have triggered the 

first block of automatic under-frequency load shedding, which would have 

dropped five percent of the system load, or roughly 2600 MW. 

 Even though the under-frequency load shedding would have tripped 

automatically, this response would have taken out firm load and would be in 

addition to any firm load that operators may have already shed, starting with the 

first directive ERCOT issued at 5:43 AM. Depending on the particular 

circumstances surrounding the moment of activation of the automatic underfrequency load shedding, it is possible that an overvoltage condition could have 

occurred in one or more localized areas, that frequency could have significantly 

overshot the 60 Hz norm, or that other electrical perturbations could have 

developed that would have resulted in the tripping of even more generation. Only 

a detailed dynamic simulation could answer the question as to how widespread the 

February 2 blackout would have been had the automatic under-frequency load 

shedding been triggered.

 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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ERCOT’s Black Start Capability

If the load shed had not prevented an ERCOT-wide blackout, the outages 

would not only have been more widespread, they might have been of a much 

longer duration. The task force reviewed the state of ERCOT’s black start units to 

determine whether they could have promptly brought the system back had a 

collapse occurred. “Black start” refers to restarting the system after a major 

portion of the electrical network has been de-energized, and generators that have 

black start capability are those that can be started independently and without 

external power. 

ERCOT has 15 primary and six alternate black start generators. During the 

event, roughly half of these generators were unavailable: two (totaling 97 MW of 

capacity) were on planned outage; four (totaling 141 MW) failed to start due to the 

extreme cold weather; three (totaling 423 MW) tripped offline after starting due to 

freezing equipment; and one (26 MW) tripped offline due to natural gas fuel 

curtailment. Had a total blackout of the ERCOT system occurred, the 

unavailability of 10 of ERCOT’s 21 (primary and alternate) black start resources, 

comprising 687 MW out of a total 1150 MW of black start capacity, could have 

jeopardized ERCOT’s ability to promptly restore the system. 

The Load Shed Process

 ERCOT accomplishes a controlled load shed by issuing directives to its 

transmission providers,125 ordering the load shed to proceed in defined blocks of 

power (each transmission provider being responsible for its allocated share of the 

total). On February 2, ERCOT issued its first load shed directive at 5:43 AM and 

its third and last at 6:23 AM. In total, it directed that 4000 MW be shed. 

ERCOT began load restoration at 7:57 AM, and firm load was fully 

restored at 1:07 PM. 

 125 “Transmission provider” is a generic term. ERCOT uses “transmission service 

provider” to mean an entity that owns or operates transmission facilities to transmit electricity and 

provide transmission service on the ERCOT grid. NERC uses different terminology to describe 

the various types of transmission providers, including “transmission service provider,” 

“transmission operator,” and “transmission owner.” (The definitions of these terms can be found 

in the appendix entitled “Categories of NERC Registered Entities.”) Under NERC terminology, 

ERCOT is the only “transmission service provider” for its Interconnection. To avoid confusion, 

the term “transmission provider” will be generally used in the narrative portions of this report to 

refer to any of those various categories of entities who provide transmission service and who 

were directed to shed load and took the necessary actions to do so ( including load shedding both 

within and outside of ERCOT). 
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 The actual load shed process and eventual restoration of the system to an 

EEA 0 state126 proceeded as follows: 

 ERCOT issued its first instruction at 5:43 AM, ordering a load shed of 1000 

MW. Shortly thereafter, ERCOT also deployed 384.2 MW of Emergency 

Interruptible Load Service, ERCOT’s form of demand response.127 

 At 6:04 AM ERCOT directed the transmission providers to shed an 

additional 1000 MW of load. In the next second, 6:05 AM, ERCOT’s frequency 

dropped to 59.576 Hz, its lowest point during the event. 

 At 6:23 AM ERCOT issued its third and last load shed directive, directing 

the transmission providers to shed an additional 2000 MW. This resulted in a total 

load shed directive of 4000 MW. 

 As the transmission providers were implementing ERCOT’s directives to 

shed load, additional generation became unavailable; between 5:45 and 6:30 AM, 

18 generating units tripped offline, were derated, or failed to start, totaling 1643 

MW of output. (During this same time, 12 units came back online, totaling 774 

MW.) 

 At 6:25 AM, ERCOT’s reserve level dipped to 447 MW, its lowest point of 

the day. 

 At 6:59 AM, ERCOT issued a media appeal for energy conservation. This 

was the first notification to the public of the problems ERCOT was experiencing 

on its system.128

 At 7:57 AM, ERCOT issued its first load restoration directive, beginning 

with a 500 MW block. Three seconds later, a combined cycle unit loaded at 77 

 126 “EEA 0” signifies a normal state of operation. 

127 While some EILS customers failed to reduce load as contracted (thus exposing 

themselves to potential penalties), others responded with a load reduction in excess of their 

contracted amount. The net result was that total EILS load reduction fell short of obligated levels 

on February 2 in only one fifteen-minute interval. 

128 ERCOT has acknowledged that it could improve its communications with the general 

public, which it suggests could be accomplished through use of an automated system for 

contacting the media, deployment of representatives to meet with the media, and through 

designation of supplemental communications staff to answer phone inquiries during a period of 

emergency. 
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MW tripped offline, causing reserve levels to again fall below 1354 MW. 

However, ERCOT did not shed any additional load. 

 At 8:22 AM, ERCOT directed the transmission providers to restore another 

500 MW block of shed load. ERCOT would issue six more load restoration 

directives over the course of the next several hours, completing the process at 1:07 

PM.129 

 At 8:53 AM, ERCOT deployed an additional 83.5 MW of EILS, at which 

point reserves increased above the 1354 MW limit. 

 

 At 9:25 AM, ERCOT called all QSEs and instructed them not to take any 

resources offline unless so instructed. 

 

 Additional units, including an 849 MW coal unit, continued to trip offline. 

At 10:58 AM, reserves again dropped below the 1354 MW limit. This situation 

lasted until 11:15 AM. 

 At 12:12 PM, ERCOT reported to the QSEs that the Texas Commission 

on Environmental Quality (TCEQ) had issued a waiver for certain air permitting 

requirements that might otherwise have prevented generators from producing 

power during the emergency. (The TCEQ’s actual communication did not 

mention a waiver, but rather indicated it would exercise its “enforcement 

discretion.”) 

 At 1:57 PM, ERCOT recalled RRS Block 2 Load Resources (463 MW). 

 At 2:01 PM, ERCOT returned to a state of EEA 2B. 

 At 2:55 PM, ERCOT recalled RRS Block 1 Load Resources (437 MW). 

 At 3:14 PM, ERCOT returned to a state of EEA 2A. Reserve levels rose to 

approximately 2900 MW. 

At 7:15 PM, ERCOT set a record winter peak demand of 56,480 MW. 

 On February 3, at 10:00 AM, ERCOT declared a state of EEA 0 and 

recalled all EILS loads. 

 129 Directives were issued in 500 MW blocks at 9:25 AM, 11:39 AM, 12:04 PM, 12:25 

PM, 12:49 PM, and 1:07 PM. 
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 Summing every transmission provider’s peak load shed amount (which did 

not occur at the same time), the cumulative load shed on February 2 was 5411.6 

MW. The largest amount of load shed at one point in time (8:02 AM) was 4947.9 

MW.130 

 The load shed process by ERCOT’s transmission providers is discussed 

below. 

 Conduct of the Load Shed by ERCOT’s Transmission Providers

 

ERCOT communicated its oral dispatch instructions to shed load via 

hotline calls. The percentage of the total requirement that is to be shed by each 

transmission provider is based on the transmission provider’s previous year peak 

load, as reported to ERCOT.131 Under ERCOT’s Nodal Operating Guides, 

transmission providers have 30 minutes to shed their required share of load if the 

curtailment is implemented remotely by SCADA system, and one hour if 

implemented by dispatch of personnel into the field to manually disconnect 

feeders.132 

Load Shed Program Design 

Each transmission provider in ERCOT is responsible for determining how 

load will be shed in order to meet its load shed obligation.133 The larger 

transmission providers interviewed by the task force make use of automated 

systems for shedding load. All transmission providers interviewed pre-designated 

feeders or blocks that are available for manual load shed. Transmission providers 

generally take into account the following factors in setting up their load shed 

system: 

 130 Based on TRE data supplied to the task force. (This number does not include 

Greenville, for which comparable data was not available. Adding 8.8 MW for Greenville would 

bring the total to 4956.7 MW). 

131 See ERCOT Nodal Operating Guides: Emergency Operation § 4.5.3(5) (July 1, 

2011), available at http://www.ercot.com/mktrules/guides/noperating/cur. 

132 Id. at § 4.5.3(7)(a)-(b). These time frames do not apply if the load shed directive 

exceeds 1000 MW, as was the case for ERCOT’s last load shed instruction on Feb. 2, 2011. Id. at 

§ 4.5.3(7)(c). 

133 Actual implementation of load shedding is carried out at the distribution level, which 

may be done through a separate division of the transmission provider or through a separate, 

affiliated entity (e.g., a member distribution cooperative of a generation and transmission 

cooperative). This extra layer of communication appears to have caused some delay in the 

initiation of the load shed process in at least some cases. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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1. Minimizing customer disruptions through target outage rotation 

periods. Transmission providers interviewed utilize a load-shed 

scheme with a targeted rotation period between 15 minutes at the 

low end and 30-45 minutes at the high end. During the February 2 

event, transmission providers reported difficulties maintaining a 

short (15-minute) rotation period over the course of the morning, as 

ERCOT raised their load shed obligation to the highest levels most 

transmission providers had experienced. Transmission providers 

reported having to go through their rotation schedule multiple times, 

and some transmission providers expressed concern that a limited 

number of customer groups had to carry a disproportionate amount 

of the load-shed burden.134

2. Avoidance of feeders or lines reserved for under-frequency load 

shedding (UFLS) requirements. All transmission providers 

interviewed indicated that UFLS blocks135 are not generally included 

as available feeders for manual load shedding under their load shed 

procedures. However, one transmission provider discovered during 

the February 2 load shed event that some lines designated as 

available for manual load shed were also designated for UFLS. 

Except for this one overlap in blocks, the transmission providers 

interviewed were able to fully meet their load-shedding obligations 

while maintaining the required 25 percent of load reserved for 

UFLS. There were no reported instances of automatic underfrequency trips during the February 2 event. 

3. Exemptions for critical customers. Transmission providers utilize a 

variety of approaches for identifying critical customers or loads that 

are either exempt from rolling outages or are given a higher priority 

for preservation of service. Customers that typically receive some 

form of exemption or higher priority include hospitals, airports, and 

 134 TRE Report at 41; materials provided to the task force by transmission operators. 

135 Distribution service providers in ERCOT are required to set up relays to automatically 

trip load as frequency falls, as follows: (1) at 59.3 Hz, a minimum of 5 percent of load must trip; 

(2) at 58.9 Hz, an additional 10 percent of load must trip; and (3) at 58.5 HZ, an additional 10 

percent of load must trip, i.e., the distribution service providers must have at least 25 percent of 

its load available for UFLS. (This is independent of any manual load shedding directives.) 

ERCOT Nodal Operating Guides Section 2: System operations and Control Requirements at 

2.6.1(1) and (2). Some transmission providers use these same blocks of load for automatic undervoltage protection. (Note that NERC uses the term “distribution provider” to describe this type 

of entity. This report will use the term “distribution service provider” throughout to avoid 

confusion.) 
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other facilities that may affect public safety, such as police 

stations.136 Some transmission providers interviewed indicated that 

they have a process for checking with gas customers for possible 

critical loads, such as gas compressor facilities without backup 

generation. But most acknowledged that the process for identifying 

“critical” gas facilities could be better standardized or otherwise 

improved. 

4. Exemption of large loads and networks needed for system stability. 

Major downtown areas are generally exempted from the load shed 

plan, as cutting off service to these heavily networked systems could 

affect system stability. Large, high-voltage industrial loads are also 

generally not available for manual load shedding due to system 

stability concerns.137 

 

 After taking into account UFLS blocks, critical/exempt customers, and 

other load that is not appropriate for manual load shedding, the interviewed 

transmission providers indicated that they had between 30 percent and 70 percent 

of their total load available for manual load shedding. 

Experience on February 2, 2011 

The transmission providers’ overall load shed response (in MW) was 

beyond the minimum required by ERCOT and was adequate to protect system 

frequency. 

Most of the larger transmission providers interviewed were able to shed 

load within a few minutes of receiving each ERCOT directive, and utilized some 

form of automated system for shedding load. These systems were designed to 

 136 The State of Texas also requires transmission providers and distribution service 

providers to provide notification of interruptions or suspensions of service under certain 

conditions (set out in their retail delivery tariffs) to customers that meet the criteria for 

designation as a Critical Load Public Safety Customer (hospitals, police stations, fire stations, and 

critical water and wastewater facilities), Critical Load Industrial Customer, Chronic Condition 

Residential Customer, or Critical Care Residential Customer. 16 TEX. ADMIN. CODE § 25.497 

(2011). 

137 Some of these high-voltage industrial loads may be under contract as Emergency 

Interruptible Load Service (EILS) or providing ancillary services (RRS) as Non-Controllable 

Load Resources (NCLR). See TRE Report at 42-44. In such case, those resources would be (and 

were) called upon by ERCOT through the relevant QSE (at 5:49 for EILS and at 5:20 for NCLR), 

something that is not communicated to or controlled by the transmission providers or distribution 

service providers. 
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look at actual load on the feeders in real time, and were designed to rotate 

customer blocks by restoring service feeder-by-feeder as the pre-determined 

rotation period expired. These systems were also designed to ensure that the total 

curtailment obligation is maintained or exceeded at all times, by restoring a given 

feeder only after another feeder or feeders with off-setting load have been dropped 

in the next block. At least one of the automated systems in use during the event 

was designed to take into account cold load pickup prior to restoration of 

feeders,138 and therefore may have generated a greater reported level of overshedding for limited periods of time during the rotation process.139 

Other transmission and distribution service providers used less 

sophisticated methods for shedding load during the event, including having a 

dispatcher record load amounts prior to dropping a given block to calculate the 

total amount to be reported to ERCOT as having been shed, and using color-coded 

circuit maps to select lines to be shed. 

All but four transmission providers were able to meet or exceed their load 

shed obligations within 30 minutes of each oral dispatch instruction from ERCOT. 

Three of the four transmission providers did meet their full load shed obligations 

at a later point in time. The fourth transmission provider contended that it had not 

received the dispatch instruction.

Effect of Load Shed on Gas Delivery or Supply 

At approximately 8:00 AM on February 2, ERCOT notified all 

transmission providers that gas companies were reporting low gas pressures, and 

requested that they confirm that no gas company feeds were included in their 

 138 Cold load pickup is a phenomenon that takes place when a distribution circuit is reenergized following an extended outage of that circuit. Cold load pickup is a composite of two 

conditions: inrush and loss of load diversity. Cold Load Pickup Issues: A Report to the Line 

Protection Subcommittee of the Power System Relay Committee of the IEEE Power Engineering 

Society, May 16, 2008, § 2.1, at 3, available at http://www.pespsrc.org/Reports/Cold_Load_Pickup_Issues_Report.pdf . 

139 One transmission provider’s automated system includes an expectation of a 60 

percent increase in load on any feeder coming off of its pre-determined outage period, and 

therefore requires that feeders in the next block must cover the expected increase before the first 

feeder can be restored. That transmission provider did report peak load shed amounts well above 

its requirement (about 49 percent over the required amount at one point), but attributed the 

reported over-shedding to several factors in addition to the cold load pickup assumptions used, 

including (1) restoration failure of a certain percentage of breakers; and (2) loads that did not 

come back on-line until manually re-set, including certain gas compressors. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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outage rotation feeders.140 At 9:25 AM, as part of its third directive to restore 500 

MW of load, ERCOT requested that transmission providers serving west Texas 

concentrate their restoration efforts in that region due to concerns about the impact 

of the outages on gas compressor facilities. At 10:45 AM, ERCOT notified some 

transmission providers that gas compressor stations in two west Texas counties 

were still without power, and requested that service be restored to those counties 

as soon as possible.141 In addition, some transmission providers reported 

additional requests from ERCOT about restoring power to specific gas facilities or 

regions, but noted that ERCOT did not appear to have reliable or current 

information as to which transmission or distribution service provider was 

providing electric service to those facilities. 

The task force found that transmission providers currently have only 

limited information on overall system conditions in ERCOT, and in real-time can 

typically see nothing more than ERCOT’s responsive reserve (PRC) levels and the 

status of generators connected to the transmission provider’s own system. Many 

transmission providers indicated that they could perform better with respect to 

load shedding, particularly in increasing staffing and providing notice to the 

public, if they are able to get information about deteriorating system conditions 

from ERCOT earlier in the process. 

Some transmission providers indicated they are already working on 

improvements to their public notification protocols, and believe that certain 

sensitive loads (including loads with back-up generation) could have benefitted 

from earlier notification of potential outages. 

The task force also found that transmission providers with annual training 

programs, particularly those that require use of hands-on simulations or drills, 

tended to perform well during the February 2 load shedding event. Transmission 

providers with less frequent training, or that fail to simulate expected conditions 

during a load shed event, tended to have more problems with timely 

implementation of the required curtailment. Automated systems for shedding load 

may be helpful for larger transmission providers, but do not appear to be necessary 

 140 One transmission provider reported that, upon receiving ERCOT’s notice, it restored 

power to facilities believed to be compression facilities; these were later determined to be 

regulator stations, for which restoration of power would not affect pipeline pressure. 

141 ERCOT directed one transmission provider to restore power to five specific counties 

in north/central Texas due to concerns about affected gas facilities, which restoration could only 

be done by working outside the automated outage rotation system to identify each feeder or 

circuit serving those counties. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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for successful implementation of a load shed program under ERCOT’s current 

time requirements for implementation. 

Price Effects of the Cold Weather Event

As discussed in the section of this report entitled “The Electric and Natural 

Gas Industries,” ERCOT is an energy-only market. This type of market relies on 

scarcity pricing to provide price signals for the addition of needed resources. 

ERCOT transitioned from a zonal market to a nodal market in December 2010, 

and as part of its preparation for that transition, adopted rules in 2006 that included 

a Scarcity Pricing Mechanism that relaxed the then-existing system-wide cap of 

$1,000 per MWh. ERCOT did this by gradually increasing the cap in accordance 

with a defined schedule to $1,500 per MWh on March 1, 2007, to $2,250 per 

MWh on March 1, 2008, and finally to $3,000 per MWh on February 1, 2011, two 

months after the implementation of the nodal market and, as it happened, on the 

day before the severe weather impacts caused ERCOT to shed load.142

The rapidly dwindling supply of generation on February 2 created a 

scarcity event and, not surprisingly, caused prices to spike. By 4:55 AM, prices 

had reached a sustained level of $3,000 per MWh.143

These high prices, coupled with the fact they occurred the day after the 

price cap had been raised to $3,000 per MWh, fueled speculation that market 

manipulation may have been a factor. Such speculation was probably exacerbated 

by certain instances of past high prices, as well as two studies finding the 

existence of market power in the ERCOT markets. 

In 2001, prices rose to the $1,000 per MWh cap on the first day of 

operation of ERCOT’s pilot zonal market.144 During the winter storm of February 

2003, high prices of $990 per MWh in the balancing market and $967 per MWh in 

the ancillary service market were later determined to have been partially caused by 

“hockey stick bidding.”145 According to two studies evaluating behavior in the 

 142 Potomac Report at 15. 

143 Id. at 20. 

144 The Steering Committee of Cities Served by Oncor and the Texas Coalition for 

Affordable Power, The Story of ERCOT: The Grid Operator, Power Market & Prices under 

Texas Electric Deregulation, at 32 (Feb. 2011), available at http//tcaptx.com/downloads/THESTORY-OF-ERCOT.pdf. 

145 Public Utility Commission of Texas, Report to the 79th Texas Legislature: Scope of 

Competition in the Electric Market in Texas, January 2005, at 32, available at http://www.puc.

state. tx.us/industry/electric/reports/scope/2005/2005scope_elec.pdf. Hockey stick bidding 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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ERCOT balancing market, large firms were found to have exercised unilateral 

market power between 2001 and 2003.146 And in March of 2008, two days after 

the market cap rose to $2,250 per MWh, prices hit the cap for three consecutive 

15-minute intervals.147

Given these historical events, suspicions concerning the causes of the high 

prices on February 2 were understandable. The Executive Director of the PUCT 

directed the IMM for ERCOT, Potomac Economics, Ltd., to investigate whether 

there was any evidence of market manipulation or market power abuse. 

In its April 21 report to the PUCT, the IMM concluded there had not been 

any market manipulation during the cold weather event on February 2. The IMM 

further concluded that the ERCOT real-time and day-ahead markets operated 

efficiently, and that the shortage conditions were properly accompanied by 

scarcity level pricing, a phenomenon consistent with ERCOT’s energy-only 

market design.148 

The IMM reached its conclusion by examining whether there had been any 

economic or physical withholding. The IMM’s test for economic withholding was 

to determine whether energy had not been produced when the capacity would have 

been economic, given the prevailing price. Since all available capacity was being 

utilized when prices spiked, the IMM concluded there had been no economic 

withholding.149 The IMM’s test for physical withholding was to determine 

whether resources were made unavailable that were actually capable of providing 

energy and were economic at prevailing market prices. This determination 

 

involves offers of a small, expendable quantity of energy or capacity well in excess of its 

marginal cost, which can set the marginal clearing price at times of short-term demand when all 

offers must be accepted. See Daniel Hurlbut, Keith Rogas, and Shmuel Oren, Protecting the 

Market from “Hockey Stick” Pricing: How the Public Utility Commission of Texas is Dealing 

with Potential Price Gouging, THE ELEC. J., April 2004, at 26-27. 

146 Ali Hortacsu & Steven L. Puller, Understanding Strategic Bidding: A Case Study of 

the Texas Electricity Spot Market (June 2007), http://citeseerx.ist.psu.edu/viewdoc/ 

download?doi=10.1.1.73.9947&rep=rep1&type=pdf; Ramteen Sioshansi & Shmuel Oren, How 

Good are Supply Function Equilibrium Models: An Empirical Analysis of the ERCOT Balancing 

Market, 31(1) J. REG. ECON. 1 (2007). 

 

147 Eric S. Schubert, Shmuel Oren & Parviz Adib, Achieving Resource Adequacy in Texas 

Via an Energy-Only Electricity Market, in ELECTRICITY RESTRUCTURING: THE TEXAS STORY

70, 92 (L. Lynne Kiesling & Andrew N. Kleit, eds., AEI Press, 2009). 

148 Potomac Report at 1-2, 8. 

149 Id. at 8-9. 
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required a review of the causes of outages and derates. After conducting this 

review, the IMM found no evidence that the outages and derates were caused by 

anything other than the physical inability of the generators to produce power.150 

The IMM observed that the scope of the outages and derates was 

widespread in geography, generating unit type, and by class of market 

participant.151 It also observed that those market participants that were able to 

operate their generation fleet at greater than 90 percent availability during the 

morning of February 2 were financially successful that day, and the market 

participants affected by significant generation outages were unprofitable.152 

Furthermore, those market participants that lost significant generating capacity and 

were unprofitable on February 2 did not achieve gains on February 3 that 

significantly exceeded the previous day’s losses, despite high day-ahead prices.153 

These findings suggested to the IMM that market participants had every incentive 

to offer their units’ capacity into the market, had they been physically able to do 

so. 

Based both on the IMM’s study and on the task force’s independent 

evaluation of the causes of the generator outages, there does not appear to be 

evidence that the high prices on February 2 were the result of market 

manipulation. Rather, they appear to be the natural result of scarcity pricing in an 

energy-only market. 

Rio Grande Valley Event: February 3-4

In addition to the ERCOT-wide load shed on February 2, ERCOT 

experienced more localized difficulties on February 3 and February 4 that 

necessitated local load shedding. The area affected was the southernmost tip of 

Texas along the Rio Grande River, designated as the Lower Rio Grande Valley 

(LRGV). 

The weather in the LRGV is typically mild. Temperatures in February for 

Brownsville, the largest city in the LRGV, average a high of 72 degrees and a low 

of 53 degrees. For February 2011 as a whole, Brownsville had a high of 90 

 150 Id. at 12. 

151 Id. at 10. 

152 Id. at 14. 

153 Id. 
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degrees; on February 3, however, the high reached only 36 degrees, with a low of 

28 degrees.154 

Load in the LRGV generally exceeds available local generation, making the 

area dependent on imports. The Rio Grande Valley import capability consists of a 

group of five elements, three 138 kV and two 345 kV transmission lines, owned 

and operated by American Electric Power (AEP), that allow for the import of 

energy into the LRGV area. The Rio Grande Valley import limit is a contingency 

import limit based on the loss of either of the two series compensated 345 kV lines 

that transmit electricity into the LRGV. The contingency limit is 1200 MW, with 

economic redispatch occurring at 1100 MW. This limit was exceeded for short 

periods during the evening hours of February 2, and for over 30 consecutive hours 

beginning on February 3 and concluding on February 4. 

Two types of events can trigger load shedding to prevent an uncontrolled 

loss of load: under-frequency and under-voltage. Under-frequency load shedding 

is designed to rebalance load and generation within an electrical island following a 

system disturbance. Under-voltage load shedding is designed to prevent local area 

voltage collapse. While the ERCOT-wide February 2 event was the result of 

under-frequency concerns, the issue in the LRGV was one of under-voltage. Had 

the entities in the LRGV not implemented manual load shedding on February 3, a 

subsequent contingency could have resulted in the activation of automatic undervoltage load shedding. 

On February 3, the LRGV area hit an all-time winter peak demand of 2734 

MW.155 A total of 829 MW of local generation was on scheduled outage that day, 

and the picture was further complicated by the loss of the three Frontera units, 

totaling 486 MW. The two Frontera combustion turbines CTG-1 and CTG-2 

tripped due to frozen control equipment pneumatics at 9:47 PM and 9:59 PM, 

respectively, followed by the steam turbine CTG-3 at 10:00 PM. The import limit 

of 1200 MW had already been exceeded, beginning at 6:23 AM. When the three 

Frontera units tripped in rapid succession, the import level rose to 2074 MW 

(172.8 percent of the limit of 1200 MW). Additionally, the bus voltages at some 

substations dipped to 91 percent to 93 percent of nominal, which is outside the 

normal AEP Texas operating voltage range of 95 percent to 105 percent nominal. 

(The automatic under-voltage load shedding system in the LRGV activates when 

the voltage declines to 90 percent for three seconds.) 

 154 Weather Underground, Almanac for Brownsville, http://www.wunderground.com/ 

history/airport/KBRO/2011/2/3/Daily History.html. 

155 Texas Reliability Entity, Event Analysis: February 3-4, 2011 Lower Rio Grande 

Valley Load Shed Category 2f.1 Event at 4 (April 15, 2011) (LRGV Event Analysis Report). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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The transmission providers for the LRGV area are AEP, Public Utilities 

Board of Brownsville (BPUB), and the South Texas Electric Cooperative (STEC). 

AEP had previously developed a procedure with ERCOT, STEC, and BPUB that 

specified the load allocation for any necessary manual load shed in the event of the 

loss of one of the 345 kV transmission lines. The entities decided to use that plan 

for this event, even though it was not caused by the loss of a line but rather by the 

loss of Rio Grande Valley generation. AEP initiated the load shedding and the 

three entities each manually shed their portion of the target 300 MW load shed, 

beginning the process at 10:06 PM on February 3.156 The maximum actual load 

shed of 459.5 MW occurred at 10:59 PM. (Power was fully restored to most 

customers in the early morning hours of February 4.) 

Approximately 115,000 customers were affected by the rolling blackouts, 

with AEP contributing 60 percent of the load shed obligation and BPUB and 

STEC each contributing 20 percent. The task force determined that load shedding 

was executed well by all three entities and the required levels of load shedding 

were reached within ERCOT’s specified 30-minute period. The entities attempted 

to rotate the load shed through different circuits, but due to the size of the 

allotments of BPUB and STEC relative to their total load, as well as the number of 

critical loads on their systems, the rotation periods for each circuit of load 

shedding were longer than desired and more frequent than during the ERCOTwide load shed of February 2. 

Some of the transmission providers in the LRGV region expressed concerns 

about communications with ERCOT. AEP initiated the first phase of the load 

shed and then requested ERCOT to notify the other transmission providers to shed 

their portion, as opposed to ERCOT directing the simultaneous shedding of load. 

As a result, AEP proceeded alone for the first phase of the load shed. The 

transmission providers also observed that a public announcement made by 

ERCOT on February 3, advising customers that further outages appeared unlikely, 

did not accurately reflect the situation in the LRGV and complicated the conduct 

of their localized load shed. 

The task force concluded that in order to prevent similar problems in the 

future, additional generation or transmission lines are needed to reinforce the 

LRGV area. This is in accord with ERCOT’s Regional Planning Group analysis, 

which concluded that there is a need for transmission or market solutions in the 

LRGV to meet forecasted load beyond 2014.157 AEP Service Company has 

 156 LRGV Event Analysis Report at 20. 

157 Lower Rio Grande Valley (LRGV) 345 kV Project Analysis, ERCOT (May 13, 2011), 

http://www.ercot.com/content/meetings/rpg/keydocs/2011/0513/ERCOT_Lower_Rio_Grande_V

alley_345_kV_Project_Analysis.pdf. 
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proposed a new 345 kV transmission line from the Laredo area into the LRGV; 

however, improvements at this time are in the early planning stages. 

February 10, 2011

In analyzing the implications of the February 2 blackouts, it is instructive to 

compare that day with February 10, when ERCOT did not shed either firm or 

interruptible load despite setting a new winter peak.158 Cold weather was again 

expected on that day, and actual temperatures in the ERCOT region averaged a 

low of 19 degrees with a 12 degree wind chill. (This compares to a low on 

February 2 of 19 degrees with wind chill of 4 degrees; however, low temperatures 

during the earlier event were more persistent, remaining in the low twenties for 

four days with wind chills between 10 and 14 degrees.) The average high 

temperature in the ERCOT region on February 10 was over 42 degrees (compared 

to an average high between February 2 and February 5 that remained below 

freezing). 

ERCOT avoided service interruptions on February 10 largely because there 

were far fewer forced outages. ERCOT reports that 11 units, totaling 2160 MW of 

generation, were forced offline at some point during the day. The biggest 

difference between February 2 and February 10 was the number of units forced 

offline on February 2 just during the early morning hours. The cumulative net 

outages on that morning exceeded 14,700 MW,159 whereas for the entire day on 

February 10, only 2160 MW were forced offline. The equivalent total outages for 

the entire day of February 2 was 21,400 MW, a ten-fold difference. 

The majority of the forced outages in ERCOT on February 2 were weatherrelated, while on February 10, few were weather-related (those few were the result 

of frozen valves, a frozen transmitter and automatic temperature cut-offs at some 

wind farms). Representative causes of forced outages on February 10 included 

control issues, a condensate pump that was out of service, the loss of a vacuum 

pump, a low head level in a cooling lake, frozen valves, low gas header pressure, 

and a boiler tube leak. 

There appear to be three reasons ERCOT was not forced to shed load on 

February 10: repairs made and protective measures taken during the event of 

February 2 remained in place; the temperatures on February 10 were not quite as 

 

158 The peak of 57,915 MW occurred at 7:15 AM. 

159 “Cumulative net outages” subtracts out those units that were successfully brought 

back online. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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cold and the cold temperatures were of shorter duration; and the wind chill was, in 

the main, not as severe. 

In interviews with the task force, generator operators mentioned that on or 

after the earlier event they had installed wind breaks, including tarps or enclosures, 

added portable heaters or heat lamps, repaired or added insulation, and repaired or 

added heat tracing. One generator changed its procedures for monitoring the 

reliability of its heat tracing. Some generators also continued their increased level 

of staffing to address freeze protection issues, and others changed elements of 

their control logic to prevent units from automatically tripping. 

Some of the vulnerabilities identified and addressed the week before 

included re-routing piping or moving vulnerable equipment, correcting 

transformer oil levels at wind farms, and adding freeze-resistant chemicals. At 

least five generators kept units running, started units earlier or took other measures 

to keep from having a cold start. After so many static sensor and other lines froze 

the week before, some units left water lines draining, or took other measures to 

keep water flowing. 

The storm on February 10 was concentrated in Oklahoma and northern 

Texas, unlike the more widespread storm of February 2. Temperatures by and 

large were somewhat less severe, especially during the day when they rose above 

freezing. A number of generator operators told the task force that the difference in 

temperatures and the shorter duration of the cold spell on February 10 were 

significant factors in the improved performance of their units. 

Lastly, the wind chill in some areas was not as extreme on February 10 as 

during the preceding week. Some generator operators cited the lower wind speed 

as a significant factor in their improved performance, an assessment with which 

ERCOT concurred.160 

Salt River Project

ERCOT was not the only entity in the Southwest that was forced to shed 

load during the storm of February 1 through February 5. SRP shed 300 MW of 

load on February 2, affecting 65,000 customers. However, only some of the 

generation losses leading to SRP’s load shed were weather-related. 

 160 Of special interest to wind units was the absence of precipitation that would ice their 

turbine blades. Several wind farm operators mentioned this absence as a factor in their improved 

performance. 
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SRP’s problems began at 6:54 PM on February 1, when Unit 1 at the 

Navajo Generating Station (NGS) in Page, Arizona, tripped offline.161 Page was 

experiencing colder than average temperatures, reaching a high of 36 degrees and 

a low of 17 degrees, and facing average wind speeds of 10 miles per hour. NGS 

Unit 1 tripped due to these freezing conditions when a sensing line leading to a 

waterwall pressure transmitter froze. The trip resulted in a loss of 330 MW of 

generation for the SRP balancing authority area.162 

 In response to the trip, SRP called on the SRSG for assistance and imported 

its allowed amount of 170 MW. It also deployed 80 MW of spinning reserves and 

curtailed 48 MW of interruptible load. At 8:10 PM, SRP restored the interruptible 

load. 

 To make up for the loss of NGS Unit 1, SRP’s system operator scheduled 

Santan Generating Station (SGS) Unit 6, a 275 MW combined cycle unit 

(consisting of a combustion turbine and a steam turbine), to start at 5:00 AM on 

February 2 (it had not been included in SRP’s day-ahead plan). Understanding 

that it might need additional generation on February 2, SRP also decided to keep 

SGS Unit 5, a 570 MW unit, online for the following day. 

 On February 2, SRP’s difficulties resumed at 2:56 AM, when Coronado 

Generating Station (CGS) Unit 2, which is coal-fired, tripped offline due to a nonweather related mechanical problem with its coal pulverizers. Although the unit 

was running at only 130 MW at the time of the trip, it was scheduled for its full 

389 MW output for the morning peak. The loss of CGS Unit 2 also tripped 

Coronado 500 kV breakers 945 and 948. 

 SRP lost another 75 MW at 3:20 AM, when Unit 4 at the Four Corners 

Power Plant (FC) tripped due to control valve problems (all 750 MW of the unit 

was lost, of which SRP has a ten percent share). The FC unit trip was weatherrelated and occasioned by frozen sensing lines. SRP dispatched SGS Units 1, 2, 5 

and 6 to replace the loss of FC Unit 4 for the morning peak. 

 SRP was able to close the Coronado 500 kV breaker 945 at 4:21 AM, and 

brought Coronado 2 back online. Shortly thereafter, at 5:07 AM, SRP dispatched 

SGS Units 1 and 2 at 90 MW each to meet increasing system loads, and at 5:15 

AM ramped SGS Unit 6 to 236 MW. 

 161 Details are based on information provided to the task force by SRP. 

162 NGS Unit 1 is a 750 MW unit that is owned by the Salt River Project, U.S. Bureau of 

Reclamation, Los Angeles Department of Power & Light, Arizona Public Service, NV Energy, 

Inc., and Tucson Electric Power. SRP has a 21.7 percent ownership in the unit. NGS Unit 2, 

discussed below, has the same ownership structure and total output. 
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 At 5:18 AM, SRP dispatched duct firing on SGS Units 5&6.163 A few 

minutes later, at 5:22 AM, the SGS Unit 6 steam turbine tripped, although the 

unit’s combustion turbine was able to continue supplying generation. The steam 

unit had an output of 80 MW. At this time, SRP system operators told the 

generator operators at SGS that they needed the steam turbine back online as 

quickly as possible. The system operators were not aware, and were not advised 

by the generator operators, that in order to get the steam turbine back online, the 

combustion turbine would have to be ramped down significantly. Between 5:22 

AM and 5:44 AM, as a result of the ramping down of the combustion turbine, the 

output of SGS Unit 6 was reduced from 159 MW to 15 MW. 

 SRP experienced a flurry of activity between 5:22 AM and 6:00 AM. After 

the loss of the SGS Unit 6 steam turbine, SRP dispatched the Mormon Flat Hydro 

(MFH) Unit 2 to come online at 50 MW, interrupted 38 MW of instantaneous 

interruptible load, and at 5:30 AM dispatched Horse Mesa Hydro (HMH) Units 1, 

2 and 3, for a total of 30 MW additional generation. SRP’s system operators also 

directed its merchant group to purchase 100 MW for the 7:00-8:00 AM hour. At 

5:31 AM, SRP called on MFH Unit 1 for 10 MW, and also requested that a large 

interruptible customer drop 100 MW of 10-minute interruptible load. At this point 

SRP’s reserves were diminishing, and SRP used the interruptible load to increase 

its spinning reserves. 

 At 5:39 AM, SRP was able to bring SGS Unit 2 online at 92 MW, and at 

5:40 AM, SRP’s merchant group called on another interruptible customer to drop 

29 MW of contracted interruptible load in the 6:00-7:00 AM hour. However, 

Tucson Electric Power contacted SRP at the same time to report that it had lost 

Springerville Unit 3, which diminished SRP’s available capacity by another 25 

MW. At 5:44 AM, SRP determined that SGS Unit 6 would not be able to return to 

service, resulting in a total loss of 236 MW of capacity. 

 SRP was able to bring on SGS Unit 2 online at 40 MW at 5:45 AM, and 

SGS Unit 1 at 40 MW at 5:57 AM. At 6:00 AM on February 2, SRP system load 

was running at 3557 MW, which was 161 MW higher than its day-ahead schedule. 

 At 6:02 AM, SRP dispatched Units 4, 5, and 6 at the Agua Fria Generating 

Station (AFGS), at approximately 70 MW each, to recover reserves and meet 

forecasted load. SGS Unit 2 also reached full load of 100 MW at this time. Two 

minutes later SRP dispatched Kyrene Generating Station (KGS) Units 5 and 6, at 

60 MW each. Unit 6 was brought online at 6:11 AM and Unit 5 at 6:14 AM. SRP 

 163 Duct firing is a process involving additional burners being fired for a heat recovery 

steam generator (HRSG) to increase steam production and output. The output of the burners 

combines with the hot exhaust gas from the gas-fired turbines to create steam. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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dispatched the 41 MW KGS Unit 4 at 6:08 AM and HMH Units 1, 2 & 3 at 10 

MW each at 6:09 AM. At this point all available SRP generating units were 

dispatched, and SRP purchased an additional 100 MW to begin at 6:20 AM. 

 SRP issued a Capacity Alert at 6:17 AM. (A Capacity Alert is an internal 

alert telling operators in the balancing authority that SRP believes that if another 

unit were to trip, the balancing authority would have trouble recovering.) A 

Capacity Alert is a precursor to a NERC EEA-1. 

 Five minutes later, NGS Unit 2 tripped due to frozen waterwall pressure 

sensing lines. The trip resulted in the loss of 350 MW for the SRP balancing 

authority area, and constituted the event that triggered load shedding. In response 

to the NGS Unit 2 trip, SRP again called on SRSG for assistance and was supplied 

with 128 MW, 82 MW less than anticipated. EPE, a neighboring balancing 

authority experiencing its own difficulties, told SRP that it could not deliver the 

assistance it was obligated to provide under the SRSG Agreement. 

 Immediately after the NGS Unit 2 tripped at 6:22 AM, SRP’s system 

operator determined, based on the information available to him, that the remaining 

reserve and emergency assistance was insufficient to recover SRP’s ACE in a 

timely manner.164 The operator concluded that 300 MW of firm load needed to be 

shed to insure stable operations of the bulk electric system should additional 

generation trip offline. The system operator contacted its reliability coordinator, 

WECC’s LRCC (Loveland Reliability Coordination Center), to notify it of the 

impending load shed. At 6:24 AM LRCC directed SRP (as transmission provider) 

to shed 300 MW. At the same time, KGS Units 5 and 6 reached full load of 62 

MW each, and SRP’s merchant group purchased 190 MW for the 7:00-8:00 hour. 

 At 6:29 AM, SRP called on the last of its 10-minute interruptible load, 

curtailing 136 MW. At the same time, SRP’s distribution service provider 

initiated its rotating load shed program. Once initiated, load shed is to take place 

within one minute; however, SRP’s distribution service provider encountered 

problems, requiring five full minutes to initiate the sequence. At 6:31 AM, LRCC 

declared an EEA 3 for SRP, which was seven minutes after SRP had initiated the 

shedding of 300 MW of load. 

 SRP reports that the 300 MW load shed event affected approximately 

65,000 customers. 

 164 ACE, or area control error, refers to the instantaneous difference between a balancing 

authority’s net actual and scheduled interchange with other balancing authorities, taking into 

account the effects of frequency bias and correction for meter error. 
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 Immediately after the load shed was initiated, SRP’s ACE returned to 

normal. At this time SRP also restored its reserves to meet its SRSG reserve 

requirement. At 6:34 AM, Springerville Unit 3 tripped offline due to high furnace 

pressure, cutting 75 MW of generation (although this did not affect SRP’s 

operations). 

 AFGS Units 4, 5 and 6 remained online and ramping to full load, and at 

6:34 AM SRP’s system operator instructed the distribution service provider to 

restore 100 MW of firm load. However, instead of restoring only the 100 MW, 

the distribution service provider mistakenly restored all 300 MW of the load that 

was shed. At 6:45 AM, the distribution service provider realized its mistake and, 

without further instruction, shed 200 MW of the load that had been restored. Prior 

to the second load shed of 200 MW, SRP’s ACE had returned to normal. 

 At 6:52 AM, KGS Unit 4 came online and began ramping to full load, and 

the system operator directed the restoration of another 100 MW of shed load. At 

6:55 AM, SGS Unit 6 returned to service and a minute later the system operator 

directed that the final 100 MW of shed load be restored. By 6:57 AM, 

approximately a half-hour after the initial load shed, SRP was able to restore 

service to its customers.165 At 7:05 AM, LRCC declared a return to an EEA 0 

condition effective as of 6:59 AM.

El Paso Electric Company 

 

During the cold weather event, EPE experienced forced outages of all but 

one generator in its El Paso area fleet. Because of the significant loss of its local 

generation (six out of seven operational units) and the resulting loss of dynamic 

reactive support, EPE was limited in the amount of generation that could be 

imported on its transmission system.166 

With limited import capability and limited local generation, EPE had to 

operate its system in such a way as to prevent cascading due to voltage instability. 

It was therefore necessary for EPE to reduce loads in its service area by manual 

load reduction. Load shedding occurred four times between February 1 and 

 165 Although SRP had directed that all load be restored at this time, some of the 

distribution service provider’s breakers would not close, leaving 4000 customers without service 

until 9:43 AM. 

166 EPE utilizes WECC Path 47 to import power from Palo Verde and Four Corners. The 

capability of this path is limited by post-contingency voltages. EPE can also utilize the Eddy DC 

tie in New Mexico to help regulate the flows on Path 47 by importing up to approximately 200 

MWs from Southwestern Public Service (SPS) to the East. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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February 4, totaling up to approximately 1023 MW and affecting 253,000 

customers. Two of the load shed events occurred on February 2, one on February 

3 and one on February 4 (all due to voltage instability concerns). 

 The four-day sequence of events is set forth below.167

Tuesday, February 1, 2011

On February 1, an arctic air mass moved in across the Las Cruces and El 

Paso area. Temperatures hovered in the low 40s between midnight and 4:00 AM, 

but dropped as the wind changed direction. The temperature dipped below 

freezing at approximately 8:51 AM and then plummeted into the middle teens by 

the late evening hours. Maximum temperature for the day was 43 degrees and the 

minimum was 14 degrees. 

As the colder air moved in, gusty winds picked up in the late evening, 

measuring up to 26 mph at the El Paso International Airport. These gusts, 

combined with air temperatures in the middle teens, produced wind chill values 

below zero. The peak wind gust reached on February 1 was 43 mph (during the 

1:00 AM hour). 

Timeline of Events 

 At 6:34 PM, the Coyote-Dell City 115 kV line tripped (reportedly as a 

result of gunshot damage to a conductor). 

 At 8:07 PM, the first of EPE’s gas-fired generators, Newman No. 3, 

tripped (loss of 40 MW).168

 At 10:15 PM, Rio Grande No. 6 tripped (loss of 50 MW). 

 At 10:15 PM, system controllers contacted LRCC, EPE’s reliability 

coordinator, and advised it of the loss of local generation. 

 At 10:52 PM, system controllers requested that interruptible loads be 

interrupted due to the extreme weather conditions and the loss of local 

generation. 

 167 Details are based on information provided to the task force by EPE. 

168 The various causes of EPE’s unit trips are discussed in the following section of the 

report, entitled “Causes of the Outages and Supply Disruptions.” 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 At 11:45 PM, the Copper Generator was brought online. 

Wednesday, February 2, 2011

The air temperature continued to drop during the morning of February 2, 

falling from 13 degrees at 1:00 AM to 8 degrees by 8:00 AM. Temperatures 

moderated during the afternoon, reaching 15 degrees. On February 2, the 

maximum temperature was 15 degrees (45 degrees below normal) and the 

minimum temperature was 6 degrees. 

The maximum temperature for the day was the coldest maximum (high) 

temperature ever recorded in El Paso, Texas. A few wind gusts up to 24-26 mph 

occurred around mid-day. This, combined with the frigid air temperatures, 

produced wind chill values of -9 to -10 degrees. The peak wind speed reached on 

February 2 was 26 mph. 

Timeline of Events 

 At 12:10 AM, Newman 5 GT3 tripped. 

 At 12:26 AM, Newman 5 GT4 tripped. 

 At 1:49 AM, Rio Grande No. 8 tripped. 

 At 1:53 AM, system controllers contacted LRCC, which declared an EEA 

l. 

 At 2:02 AM, EPE purchased power from SPS; the Eddy DC tie was 

opened and ramped to 100 MW. 

 At 2:27 AM, a switching order was given by the system controller to 

synchronize PNM’s Luna Energy Facility (Luna) to the grid, permitting 

the transmittal of power EPE had purchased from PNM. 

 At 3:17 AM, Newman Generator No. 4 GT1 tripped. 

 At 3:20 AM, Four Corners Unit No. 4 tripped. 
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 At 5:07 AM, the HVDC terminal at the Eddy DC Tie experienced a 

runback169 from 100 MW to 48 MW. 

 At 5:12 AM, system controllers again contacted LRCC, and the EEA 

level was heightened to EEA 2. This Alert advised other utilities that 

EPE was placing its load management procedures in effect due to its 

energy deficient condition. Actions taken pursuant to this Alert included 

public appeals to reduce demand, made through media announcements, 

and other demand-side management procedures. 

 At 6:28 AM, the Coyote-Dell City 115 kV line was restored. 

 

 At 7:12 AM, the Newman No. 4 steam turbine (ST) tripped, and the 

Newman-Butterfield 115 kV line opened at Newman (tripping the line). 

 At 7:16 AM, the Newman No.4 GT2 unit tripped. With the loss of 

Newman No.4 GT2, the Copper unit was the only local unit remaining 

online that could supply dynamic reactive support (it was producing 55 

MW of power). 

 At 7:22 AM, system controllers initiated load shedding in order to 

balance load with generation and maintain voltage stability. Area load 

was at 982 MW at the time, and approximately 170 MW of firm load was 

shed. 

 At 7:23 AM, EPE again contacted LRCC and EPE’s EEA status was 

increased to an EEA 3. This alert advised other utilities that EPE had 

implemented firm load interruptions. 

 At 7:55 AM, system controllers saw that Luna had lost approximately 130 

MW of generation. Another 103 MW of load was shed, with load 

stabilizing at 710 MW. 

 At 8:16 AM, Luna ramped up to 235 MW. 

 At 9:51 AM, the combustion turbine portion of PNM’s Afton combined 

cycle generator was placed online (the steam turbine portion of this 

generator experienced problems and remained unavailable throughout the 

 169 “Runback” is a manually or automatically controlled decrease in output designed to 

protect against loss of thermal transfer capability or transient angle instability. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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event). EPE made arrangements to obtain power from that unit on an 

hourly basis. 

 At 12:17 PM, controlled load shedding ended, with load at 977 MW. 

 At 12:19 PM, LRCC was contacted and EPE’s EEA alert level was 

decreased to EEA 2. 

 At 6:04 PM, the terminal at the Eddy DC tie tripped (opening the AmradEddy 345 kV line). 

 At 6:11 PM, load shedding resumed, and continued for approximately 

two hours and 45 minutes. Load shed amounts varied between 100 and 

250 MW during this period. 

 At 6:15 PM, EPE contacted LRCC, which again placed EPE under EEA 3 

status. 

 At 8:58 PM, load shedding terminated because of reduced load demand. 

EPE contacted LRCC, which changed the EEA alert level back to an EEA 

2. 

 At 11:04 PM, the Eddy DC tie (and the Amrad-Eddy 345 kV line) 

resumed operation. (According to SPS, operating agent for the DC 

Terminal, the tie had tripped due to loss of thyristors.170) 

Thursday, February 3, 2011

The lowest temperatures of the event were experienced in the El Paso area 

during the morning of February 3, 2011. Temperatures remained in the single 

digits from midnight through 10:00 AM, slowly climbed into the teens during the 

late morning, and reached a maximum of 18 degrees at 2:51 PM. The high 

temperature for the day was 18 degrees, and the low was 1 degree. (The high 

temperature was 43 degrees below normal, and the low was 34 degrees below 

normal). The peak wind speed reached on February 3 was 20 mph. The 

combination of frigid air temperatures and wind speeds produced wind chill values 

from midnight to 11:00 AM of -10 to -17 degrees. 

 170 A thyristor is a semiconductor with an anode, a cathode and a gate. Thyristors have 

the ability to switch high voltages and withstand reverse voltages, and are used in switching 

applications, especially in AC circuits, for AC power control, and overvoltage protection for 

power supplies. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Timeline of Events 

 At 3:45 PM, PNM’s Afton CT tripped. 

 At 4:23 PM, PNM put the Afton CT back online. 

 At 5:00 PM, as the evening load increased, LRCC was contacted, and 

EPE’s alert status was elevated to EEA 3. 

 At 5:30 PM, controlled rotating load shedding resumed for just over five 

hours. During this period, the load shed amounts varied between 100 

MW and 250 MW. 

 At 6:52 PM, Newman 4 GT1 was brought online. 

 At 7:20 PM, Newman 4 GT1 tripped. 

 At 9:32 PM, Newman 4 GT1 returned online. 

 At 10:30 PM, Newman 4 GT2 was brought online. 

 At 10:30 PM, EPE terminated the controlled rotating load shedding. 

 At 10:40 PM, LRCC lowered the EEA level to Alert Level 2. 

Friday, February 4, 2011

On February 4, although skies were clear and winds relatively calm, 

temperatures were as low as 3 degrees during the early morning hours. By late 

morning, temperatures moderated, reaching the middle 20s by 12:00 PM. The 

temperature continued to rise during the afternoon, and the high for the day was 37 

degrees. Winds, with speeds under 10 mph, were generally light and variable in 

direction. The low for the day was 3 degrees. (The maximum air temperature was 

24 degrees below normal and the minimum air temperature was 32 degrees below 

normal).

Timeline of Events 

 At 2:02 AM, Newman 4 GT2 tripped. 

 At 2:04 AM, Newman 4 GT1 tripped. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 At 3:17 AM, PNM’s Luna steam turbine tripped. 

 At 3:23 AM, one Luna gas turbine dropped from 90 MW to 11 MW. 

 At 3:51 AM, the Luna steam turbine was brought back online and slowly 

ramped up. 

 At 6:30 AM, LRCC issued an EEA Level 3 for EPE. With Copper again 

as the only local unit online, controlled rotating load shedding of between 

100 MW and 250 MW resumed. 

 At 6:49 AM, Newman 4 GT2 was brought online. 

 At 12:05 PM, the controlled rotating load shedding ended. 

 At 12:12 PM, the RC changed EPE’s alert status to an EEA Level 2. 

 At 3:57 PM, Newman 5 GT4 unit was brought online and remained stable 

at 50 MW. 

 At 5:12 PM, the Rio Grande 8 unit was brought online. 

 Due to the added generation, which provided the necessary dynamic 

reactive support, no controlled rotating load shedding was required for the Friday 

night peak load period or thereafter during the event. 

Saturday, February 5, 2011

 At 4:07 PM, Newman 5 GT3 came online. 

 At 4:30 PM, LRCC modified EPE’s alert status to an EEA Level 1. 

Sunday, February 6, 2011

 At 9:46 AM, LRCC decreased EPE’s alert status to an EEA Level 0. 

Public Service Company of New Mexico

PNM set a new record winter system demand during the February cold 

weather event and experienced outages on some of the generating units it owns, 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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co-owns, or from which it purchases power.171 PNM was generally able to meet 

its system load requirements and also to provide energy assistance to another 

utility. On February 3, however, PNM was forced to implement a localized rolling 

blackout in the Alamagordo and Ruidoso areas in southern New Mexico, and 

experienced an outage in the town of Clayton in northeastern New Mexico. 

In the Alamogordo and Ruidoso areas, the February 3 rolling blackout was 

implemented at 5:21 AM by the PNM Distribution Operations Center, as a result 

of a transmission line outage. The PNM Amrad to Alamogordo 115 kV 

transmission line locked out due to a failed conductor clamp, a condition that was 

apparently unrelated to the weather. As a result, the Las Cruces to Alamogordo 

115 kV transmission line, owned by Tri-State Generation and Transmission 

Association, Inc. (Tri-State), became overloaded and required load relief from 

PNM and Tri-State. PNM implemented its share of the load curtailment by 

sequential curtailment of two separate feeder lines. Approximately 20,207 

customers were affected, with an estimated load loss of up to 22.1 MW. All 

circuits were fully restored at 8:08 AM. 

The outage in Clayton began at 5:03 AM as a result of the outage of a TriState 69 kV transmission line that serves PNM’s Van Buren substation, located in 

Clayton. A static wire, stretched by the extremely cold weather, snapped and fell 

on one of the phases of the line, interrupting service to the town. All service was 

restored at 6:54 AM. The estimated load lost was 3.7 MW. 

Southwest Power Pool 

SPP also experienced severe weather conditions over much of its footprint 

during the February cold weather event. However, none of its entities was forced 

to shed load. Three BAs within SPP declared varying levels of EEAs due to 

tripping or derating of generating resources or deficiencies in natural gas supply. 

In one instance, SPS requested an EEA 1 following the trip of a 250 MW gas-fired 

generating unit. SPS had all of its available resources in use and issued public 

appeals for energy conservation. In a second instance, Oklahoma Gas & Electric 

Company (OG&E) experienced multiple generation losses on February 2 and 

February 3, and requested four separate EEA 2 declarations during the week. It 

was unable to meet its energy commitments to the reserve sharing group run by 

SPP. In the last instance, Sunflower Electric Cooperative (Sunflower) requested 

an EEA 3 on February 2 following the loss and subsequent derating of a large coal 

 171 Generating units affected, to a greater or lesser degree, included Four Corners Unit 4, 

Reeves Unit 1, Reeves Unit 3, Delta Person CT, Valencia, Afton, LGS Units 1 and 2, and Luna 

Unit 2. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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generating unit. The failure to start of a gas-fired combustion turbine aggravated 

the situation, which continued until the afternoon of February 3. During this 

period, Sunflower was unable to meet its energy commitments to the SPP reserve 

sharing group. However, following declaration of the EEA 3, Sunflower obtained 

sufficient transmission service to purchase energy and was able to meet its own 

firm energy commitments, thereby avoiding the need to shed load. 

In SPS’s case, its purchases over the Blackwater Tie (a connection between 

the Western and Eastern Interconnections) were lost between 9:00 AM and 10:00 

AM on February 2, due to capacity emergencies in the Western Interconnection. 

SPS replaced this purchase with a 100 MW purchase from Public Service 

Company of Colorado, importing it over the Lamar Tie (another one of the 

connections between the Western and Eastern Interconnections). SPS ultimately 

increased this purchase to 210 MW, and was later also able to make limited 

purchases through the Blackwater Tie. 

Notwithstanding SPS’s transactions over the ties, the majority of the 

purchases made by the energy-deficient utilities within SPP were made from other 

SPP entities. Thus, even if SPP had been separated from its neighbors by 

asynchronous ties, as is ERCOT, it probably would not have had to shed load 

during the February event. This suggests that the problems ERCOT experienced 

did not directly relate to its functionally separate interconnection status, but rather 

to the ability and preparedness of the generators within its footprint to operate as 

scheduled during the severe weather conditions. 

B. Natural Gas

The extreme cold experienced in early February 2011, particularly on 

February 2 and February 3, caused widespread production declines. These 

reductions were typically the result of freeze-offs,172 mostly at wellheads but also 

in nearby processing plants. To a lesser extent, other equipment reliability issues 

contributed to the problems, both at the wellhead and at processing and treating 

facilities. The rolling power blackouts in ERCOT also played a role in the Fort 

Worth Basin, as did customer curtailments in the Permian Basin. These supply 

reductions had adverse effects all the way down the delivery chain.173

 172 A “freeze-off,” as described earlier, occurs when water produced alongside the natural 

gas crystallizes or freezes, completely blocking off the flow and shutting down the well. 

173 Unless otherwise noted, the entity-specific data was obtained from materials submitted 

to the task force by producers, processing plants, pipelines, and LDCs. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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This subsection summarizes the supply shortfalls resulting from production 

declines in the basins, discusses the resulting reduced gas volumes and pressures 

experienced by the pipelines, and ends with a detailed examination of the retail 

curtailments made by LDCs in the affected states of New Mexico, Arizona, Texas, 

and California. 

Producing and Processing Facilities

The reductions in supply experienced during the cold weather event were 

comparable in magnitude to production shut-ins during hurricanes. The following 

chart illustrates this point. 

Relative to average dry gas production of 59.22 Bcf per day on January 31, 

2011, Bentek estimates that production in the first week of February declined by 

5.55 Bcf per day, a reduction of 9.4 percent. The decline began on February 1 

and reached its lowest level on February 4.174

 174 Data is based on task force analyses using supply and demand history from Bentek. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Of the 5.55 Bcf per day decline during the first week in February, 79 percent, 

or 4.36 Bcf per day, occurred in production basins in Texas and New Mexico 

(where production declined by 21 percent). Both the San Juan Basin in northern 

New Mexico and the Permian Basin in west Texas and southeastern New Mexico 

tend to experience production declines with low temperatures, and the February 

event was no exception. The declines in these basins, together with the large 

increases in demand, were almost exclusively responsible for the gas curtailments 

in Texas, New Mexico and Arizona.175 

This weather event was so extreme that production freeze-offs were 

experienced not only in the San Juan and Permian Basins, but throughout Texas 

and as far south as the Gulf Coast. Based on scheduled pipeline receipts, the task 

force estimates that production in the Fort Worth Basin declined by 1.63 Bcf per 

day compared to the last week of January, 2011; East Texas Basin production 

declined by 0.72 Bcf per day; and Gulf Coast Basin production declined by 0.65 

Bcf per day. 176 The shortfalls in these additional Texas basins, while not directly 

a cause of the natural gas curtailments, did contribute to fuel-related electric 

 175 Production declined by 0.43 Bcf per day in the San Juan Basin and by 1.31 Bcf in the 

Permian Basin, based on task force analyses of Bentek supporting data, pipeline receipts and flow 

data from El Paso and Transwestern. 

176 Staff’s analysis based on supporting data, display reports and data warehouse on file 

with Bentek (unpublished); see also Market Alert: Deep Freeze Disrupts U.S. Gas, Power, 

Processing, Bentek Energy LLC, Feb. 8, 2011, at 2-6; materials submitted to the task force by 

pipelines. Note that basin level production reductions may not be equal to the total February 4 

reduction as not all basin level maximum reductions occurred on February 4. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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generation failures in ERCOT. The following charts demonstrate absolute and 

percentage declines by production basin. 

Basin Production Declines Relative to Jan 31, 2011

(5.0)

(4.0)

(3.0)

(2.0)

(1.0)

0.0

2/1/2011

2/2/2011

2/3/2011

2/4/2011

2/5/2011

2/6/2011

2/7/2011

2/8/2011

2/9/2011

2/10/2011

2/11/2011

Bcf per day

Permian San Juan Fort Worth East Texas Texas Gulf Coast

Source: Task Force chart based on Bentek data 

Basin Percentage Declines Relative to Jan 31, 2011

-60.0%

-50.0%

-40.0%

-30.0%

-20.0%

-10.0%

0.0%

10.0%

2/1/2011

2/2/2011

2/3/2011

2/4/2011

2/5/2011

2/6/2011

2/7/2011

2/8/2011

2/9/2011

2/10/2011

2/11/2011

% Decline

Permian San Juan Fort Worth East Texas Texas Gulf Coast

Source: Task Force chart based on Bentek data 

The causes of these production declines are examined in detail in the 

following section of this report, entitled “Causes of the Outages and Supply 

Disruptions.” 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Effects on the Pipelines and Storage Facilities

At the same time that gas supplies flowing into the pipelines were reduced, 

shippers requested increased volumes of gas. The reduced supply relative to 

higher deliveries (a situation known as a draft condition) resulted in lower line 

pressures and reduced line pack, which for most pipelines began on February 2.177 

Between February 1 and February 4, pipelines responded to this draft 

condition through a variety of approaches. To the extent possible, deliveries to 

shippers were met by relying upon line pack. Pipelines with storage used 

increased withdrawals to build line pack. El Paso, for instance, used its 

Washington Ranch Storage Field to support its south system when gas supplies 

failed to arrive. 

El Paso 

The effect of the draft conditions on El Paso’s line pack is depicted in the 

following graph (the numbered dots reference various occurrences on El Paso’s 

system during the cold weather event):

El Paso Line Pack Time Line February 1 to February 5 

 Source: El Paso Natural Gas Company 

 177 Generally by February 4, line pressures and line pack began rising again, as the 

previous day’s scheduled receipts were received into the system. By February 5, line pack grew 

to a level above that prevailing on February 1.
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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El Paso system demand increased from 3,416 MDth178 on January 31 to 

3,675 MDth on February 2. For the same period, supply from all sources, 

including pipeline interconnects, decreased from 3,264 MDth to 3,040 MDth. As 

supply decreased and demand increased, El Paso used line pack to attempt to 

maintain deliveries. As a result, line pack fell from almost 7.8 Bcf on February 1 

to approximately 6.8 Bcf at 2:00 PM on February 3. 

As line pack fell, pipeline pressure on the western edge of the system 

dropped below 600 pounds per square inch gauge (psig). Pressure on the east side 

of the system had already dropped below 600 psig, as of 12:00 noon on the 

previous day. At 10:51 PM on February 3, El Paso issued a low pressure force 

majeure announcement, suspending its contract obligations and declaring that 

operating pressure on portions of its system could not sustain contract levels.

Pipeline Communications

Interstate pipelines issue a variety of communications and directives to 

shippers and, pursuant to FERC regulations (18 CFR §284.12 (2011)), post critical 

notices to describe strained operating conditions, to issue operational flow orders 

and, when applicable, to make force majeure announcements. Most intrastate 

pipelines provide similar information and instructions to shippers, either by 

posting or direct communications. 

Critical notices describe situations when the integrity of the pipeline 

system is threatened. A critical notice will specify the reasons for and conditions 

making issuance necessary, and also state any actions required of shippers. 

Operational integrity may be determined by use of criteria such as the weather 

forecast for the market area and field area; system conditions consisting of line 

pack, overall projected pressures at monitored locations, and storage field 

conditions; facility status (defined as horsepower utilization) and availability; and 

projected throughput versus availability, for capacity and supply. 

Operational flow orders (OFO) are used to control operating conditions 

that threaten the integrity of a pipeline system. (Individual pipeline companies 

may have other names for operational flow orders such as alert days, performance 

cut notices or an emergency strained operating condition.) OFOs request that 

shippers balance their supply with their usage on a daily basis within a specified 

tolerance band. An OFO can be system-wide or apply to selected points. Failure 

by a shipper to comply with an OFO may lead to penalties. Pipelines may also 

(cont’d)

 178 “MDth” is a thousand dekatherms. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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limit services such as parking and lending of natural gas, no-notice (the provision 

of natural gas service without prior notice to the pipeline), interruptible storage 

and excess storage withdrawals and injections. 

 Force majeure, if authorized by the pipeline’s tariff, is a declaration of the 

suspension of obligations because of unplanned or unanticipated events or 

circumstances not within the control of the party claiming suspension, and which 

the party could not have avoided through the exercise of reasonable diligence. 

 

Based on data responses to task force inquiries, the number of companies 

making use of these various communications and directives for weather-related 

reasons in the Southwest during the first week of February is as follows: 

Type of 

Pipeline 

Number of 

Data Responses 

Number of 

Companies 

With a Critical 

Notice 

Number of 

Companies 

With an OFO 

Number of 

Companies 

Declaring 

Force Majeure 

Interstate 24 6 3 1 

Intrastate 21 5 5 3 

 

El Paso Natural Gas issued a force majeure declaration on February 3, 

stating that it had experienced system operating pressure on portions of its 

mainline and some laterals that could not sustain contract levels. The other 

interstate pipeline most affected by the supply shortfalls, Transwestern, did not 

declare a low pressure force majeure. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Transwestern

The effect of the draft conditions on Transwestern’s line pack is depicted in 

the following graph. 

 Source: Transwestern Pipeline Company, LLC 

Scheduled deliveries on Transwestern from January 31 to February 2 

increased from 1,426 MDth to 1,526 MDth. Supplies dropped by approximately 

400 MDth by midday on February 2; however, Transwestern continued to make 

scheduled deliveries from line pack. Accordingly, line pack decreased from 3.9 

Bcf on February 1 to a low of 3.5 Bcf on February 3. Transwestern, unlike El 

Paso, did not declare a low pressure force majeure.179

 

New Mexico Gas Company

NMGC also experienced significant line pack problems on its distribution 

system. On January 31, NMGC bought additional supply for its north segment 

and its south/remotes segment, for delivery on the following day. On February 2, 

 179 By midday on February 3, pressures and line pack were beginning to increase, and on 

February 4, NMGC’s line pack was over 4 Bcf. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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NMGC contacted 39 large industrial and commercial customers, requesting them 

to reduce or curtail their gas usage. By 9:00 PM on February 2, NMGC reported 

to supplying pipelines that pre-ordered gas was not being delivered as scheduled. 

The effect of events on NMGC’s line pack is depicted in the following 

graph. 

The vast majority of the shortages experienced on NMGC’s north segment on 

February 2 and 3 was attributable to supply failures at the Transwestern Rio 

Puerco and El Paso’s Wingate interconnection points. An NMGC representative 

has stated that the failure of Transwestern to deliver scheduled flows of 127,454 

MMBtu on February 2 and 146,438 MMBtu on February 3 “was devastating to 

NMGC and its customers.”180 

Transwestern responded by observing that it scheduled much greater volumes 

of gas at Rio Puerco than NMGC historically flowed (and equal to the amount 

nominated by NMGC and other shippers to the point). NMGC was unable to flow 

all of the scheduled volumes, suggesting there were difficulties on NMGC’s 

system in taking away the gas from the Rio Puerco delivery point. On February 2, 

 180 Transcript of Testimony of Tommy Sanders at 13, In the Matter of an Investigation 

into New Mexico Gas Co.’s Curtailments of Gas Deliveries to New Mexico Consumers, NMPRC 

(Mar. 17, 2011) (No. 11-0039-UT). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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for example, Transwestern scheduled 305,000 MMBtu/d and NMGC took 

182,000; on Feb. 3 Transwestern scheduled delivery of 298,000 MMBtu/d at Rio 

Puerco, and NMGC took 128,000. 

NMGC also reported lower pipeline pressure than those on which it typically 

relies. On an average winter day in the north segment, pressure ranges from 800 

to 900 pounds per square inch atmosphere (psia) at Rio Puerco. The average 

pressures were lower during the week of January 31 and, from February 1 to 

February 4, the loss of pressure caused NMGC to experience significant pressure 

losses on its own system. For example, the interstate pipeline pressure at 

NMGC’s interconnection at Rio Puerco fell to a low of 724 psia from a normal 

operating pressure of 850 psia. 

Notwithstanding this decline in pressure, Transwestern’s contractual 

obligation with respect to pressures at Rio Puerco (as opposed to its typical 

operating pressures) is 700 psia, and Transwestern reports that pressure never fell 

below that obligation. 

The following chart provided by Transwestern depicts the pressure at Rio 

Puerco (fluctuating brown line) relative to contractually obligated pressure (nonfluctuating red line), total receipts (green line) and deliveries (blue line) on the 

Transwestern system. According to the chart, pressure did not fall below the 

contractual obligation of 700 psia. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Coordination Among Pipelines to Address Supply Problems

Flows between and among pipelines through redirected 

supplies and incremental transactions at least partially alleviated 

supply shortage conditions during the first week of February, 2011. 

These flows were the result of active coordination among the 

involved counterparties to address shortfalls. The redirection of gas 

came too late to avoid the curtailments in New Mexico and Arizona 

that occurred on February 2 and February 3. However, in the Texas 

intrastate markets, the increased purchases of gas at pipeline 

interconnects was an important factor in maintaining pressure in the 

Dallas-Fort Worth area and also served to move gas east to west in 

response to reduced supply at Waha. 

Changes in gas deliveries do not occur instantly. Operation 

Balancing Agreements (OBA) contractually specify how gas 

imbalances between flows and scheduled amounts are to be 

managed. (Interstate pipelines are obligated by FERC regulations to 

have OBAs at interconnects with other interstate pipelines and with 

intrastate pipelines). These agreements enabled counterparties to 

make operational changes and revise nominations. 

Chevron Keystone Storage Facility

In addition to the pipelines, at least one storage facility experienced weatherrelated difficulties. These difficulties, however, stemmed not from freeze-offs 

upstream, but from the rolling blackouts on ERCOT’s system and from the 

facility’s own operational problems. 

The Chevron Keystone Storage Facility (Keystone), which has 

interconnections with El Paso, Transwestern, and Northern Natural Gas Company, 

was affected by two rolling blackouts on February 2, at 6:30 AM and 10:00 AM. 

It was shut down completely for six hours (from 6:30 AM to 9:30 AM and again 

from 10:00 AM to 1:00 PM). 

Keystone remained at less than 100 percent capacity through February 6, due 

to line and equipment freeze-offs. Keystone declared force majeure at 9:00 AM 

on February 2. As a result, during the period February 2 through February 4, 

Keystone was unable to deliver 100 percent of nominated volumes to its three 

interconnecting pipelines. Keystone lifted the force majeure effective 9:00 AM on 

February 7. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Keystone’s difficulties did not meaningfully contribute to the curtailments of 

natural gas customers, but they did affect supplies to gas-fired generators of EPE 

and SRP. (The failures of EPE’s generating units stemmed from other causes,181

so they would not have been able to utilize the gas in any event; SRP was able to 

obtain gas from another source.) In order to estimate reduced output per customer, 

the task force prepared the following table, which compares customer scheduled 

deliveries with contractual withdrawal rights for the Keystone storage facility. It 

appears that on the coldest day, February 2, shortfalls were most significant not for 

NMGC, but for EPE, SRP and the two marketers Sequent and Tenaska. 

Keystone Storage Scheduled Deliveries Relative to Contractual Rights 

Total 

(MMbtu) WD Rights

Scheduled 

Deliveries 2-Feb 3-Feb 4-Feb

Arizona Electric Power (6,000) - (1,687) (6,000) 

Atmos Energy (20,000) (5,096) (20,000) (2,009) 

BP Energy Company (17,000) (2,500) (17,000) (7,706) 

EI Paso Electric (26,000) (12,730) - (26,000)

New Mexico Gas (140,000) (140,000) (140,000) (52,510) 

Salt River Project (35,000) (11,667) (24,791) (35,000)

Sequent Energy (27,000) (19,125) (4,793) (27,000)

Tenaska Marketing (55,500) (14,718) (24,112) (55,500)

Total - (326,500) (178,774) (232,160) (239,010)

Natural Gas Curtailments to Retail Customers

The retail customer is the last link in the natural gas delivery chain, taking 

gas for home or business consumption from LDCs. LDCs receive their gas from 

interstate or intrastate pipelines at a delivery point called the “citygate.” They 

distribute the gas through a large network of increasingly smaller diameter pipes to 

homes and businesses in the distribution area. LDC distribution networks operate 

at much lower pressures than transportation pipelines, but must maintain certain 

minimum pressures in order to deliver gas to end users. Some large LDCs use 

compressors to help maintain minimum delivery pressure, but others rely solely on 

pressure supplied by the upstream pipelines.182 

 When receipt pressures from the pipelines fall, or when consumer demand 

for gas exceeds the volume being delivered to the citygate, gas pressure within the 

LDC network will decline correspondingly. In such instances, LDCs must reduce 

 181 The causes of the generating unit outages experienced by EPE are described in the 

following section of the report, entitled “Causes of the Outages and Supply Disruptions.” 

182 NaturalGas.Org, Natural Gas Distribution, http://www.naturalgas.org/naturalgas/ 

distribution.asp. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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the amount of gas being consumed to prevent pressures from falling to the point 

where the entire system could fail. LDCs typically do this by first seeking 

voluntary curtailment from large users. If voluntary curtailment fails to stabilize 

gas pressure in the system, they will further reduce consumption by cutting off 

sections of the network, usually beginning with remote sections that would be the 

first to fail under strained conditions.183 

State Regulation of Curtailment

 Arizona, New Mexico, Texas, and California all regulate curtailments by 

LDCs in their states, but generally grant LDCs a great deal of discretion in 

determining how curtailments are implemented. 

 In Arizona, for example, the Arizona Administrative Code directs utilities 

to file, as a part of their general tariffs, a procedural plan for handling severe 

supply shortages or curtailments.184 The definitions of customer classes and the 

priority of curtailment are left to the utilities. Southwest Gas’s Arizona 

curtailment rule places residential and other human needs customers at the highest 

service priority. Electrical generators are classified below that, at priority 2 or 3, 

depending on the amount of gas they consume. 

 New Mexico also requires LDCs to create and file a list of customer 

classifications prioritizing curtailments during a system emergency, but does not 

prescribe how customers should be ranked.185 NMGC Original Rule 21 sets forth 

the company’s curtailment priorities, assigning the highest priority to residential 

and other human needs end users, including suppliers of service to human needs 

customers.186 Under the NMGC plan, electrical generators fall within this highest 

priority category. Zia gives the highest curtailment priority to residential and 

small commercial or industrial customers.187 

 183 Transcript of Testimony of Timothy A. Martinez at 15, In the Matter of an 

Investigation into New Mexico Gas Co.’s Curtailments of Gas Deliveries to New Mexico 

Consumers, NMPRC (Apr. 20, 2011) (No. 11-00039-UT). 

 184 ARIZ. ADMIN. CODE § 14-2-308(H) (2010). 

 185 N.M. CODE R. § 17.10.660.10(E)(1) (2011). 

186 N.M. Gas Co., Original Rule No. 21 IV (2009), available at https://www. 

nmgco.com/Regs/Rule21.pdf. 

187 Zia Natural Gas Co., Second Revised Rule 21 (C) (1997). 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 In Texas, state law provides that the highest priority of service should be 

given to “residences, hospitals, schools, churches, and other human needs 

customers,” but LDCs have the authority to set their own priorities, which override 

the general provisions if the TRC approves the LDC’s plan. The TRC-approved 

plan of Atmos Energy, for example, classifies electric generators several levels 

below residential customers.188 Texas Gas Service’s curtailment plan gives top 

priority to residential customers, ranking all commercial and industrial users 

below them.189 

 The California Public Utility Commission allows LDCs to set curtailment 

priorities, subject to PUC approval, and it has specifically declined to mandate 

priority service for electric generators.190 Both San Diego Gas & Electric 

Company (SDG&E) and SoCalGas assign the highest priority of service to all 

residential customers and to small core commercial customers (including some 

electric generators) that use less than 20,800 therms per month.191 

Restoration of Gas Service Following a Curtailment

 Restoration of gas service to residences following curtailment is a lengthy 

process that must be performed by trained, qualified personnel. The first step is to 

shut off each individual gas meter. The LDC’s distribution lines and lines from 

the meters to homes must then be purged of air and re-pressurized with gas. Once 

this is done, workers visit each home, inspect gas appliances for safety, open meter 

valves, relight pilot lights, and confirm that the appliances are operating safely. 

This can only be done when the customer is home, and if workers find that any 

appliances are not operating properly, service cannot be restored to that home until 

repairs have been made. 

 188 In re Curtailment Program of Lone Star Gas Co., Order No. 496, Docket No. 496 

(Texas Railroad Comm’n Oct. 15, 1973). 

 189 Curtailments, El Paso Texas Gas Service Area Gas Tariff, Third Revised, § 14.2. 

 190 Pub. Util. Comm’n of Cal., Opinion Declining to Provide Service Priorities to Electric 

Generators in the Event of a natural Gas Shortage, No. 01-12-019 (2001), available at 

http://docs.cpuc.ca.gov/published/Graphics/11821.pdf. 

191 Annual Notice, San Diego Gas & Electric, Information on Natural Gas Services and 

Programs (Feb. 26, 2010) (on file with author); Continuity of Service and Interruption of Delivery 

Rule 23(B), SOUTHERN CALIFORNIA GAS CO. at 1, http://www.socalgas.com/documents/business/ 

23.pdf. A therm is 100 MMBtu. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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The February 2011 Curtailments

 From February 2 through February 4, 2011, LDCs interrupted gas service 

to more than 50,000 customers in New Mexico, Arizona, and Texas. Areas 

affected included the cities of El Paso, in Texas (863 customers) Tucson (14,620) 

and Sierra Vista (4,596) in Arizona, and Hobbs (406), Ruidoso (50), Alamogordo 

(2,385), Silver City (290), Tularosa (1,445), La Luz (475), Taos (8,505), Red 

River (557), Questa (548), Española (12,367), Bernalillo (3,172), and Placitas 

(1,114) in New Mexico. 

The New Mexico Curtailments and Outages

Zia Natural Gas Company

 The city of Hobbs, in southeastern New Mexico, was the first to experience 

gas outages. Its LDC, Zia Natural Gas Company, receives gas from DCP Raptor 

Pipeline, LLC, (DCP) an intrastate pipeline that receives its supply from 

processing plant tailgates and wellheads. Zia serves approximately 11,000 retail 

customers in the Hobbs area. 

 On February 1, 2011, DCP fell behind for a two-hour period on deliveries 

to Zia because of wellhead freeze-offs and other supplier issues. However, the 

pipeline made arrangements with the Northern Natural Gas (NNG) pipeline to 

reverse the flow of gas at a DCP/NNG interconnect near Hobbs, making additional 

supplies available. Thus, according to both Zia and DCP, DCP’s temporary 

supply shortage did not adversely affect customers in Hobbs. 

 At approximately 3:00 AM on February 2, an electrical blackout affected 

approximately 2,065 homes in the northeast area of Hobbs.192 Zia was not notified 

of the blackout until approximately 7:30 AM, but at 5:55 AM, the company 

received a low pressure alarm from a regulator station on the northeast end of the 

system. Personnel sent to the site reported that pressure was well below normal 

levels, and Zia immediately contacted DCP, which informed them that a plant had 

gone out of service due to a cold weather-related mechanical failure and that DCP 

was attempting to address the problem. The DCP plant in question did not return 

to service until February 6. 

 Zia reported that it was able to continue supplying gas to all its customers 

in Hobbs until approximately 7:30 AM that day, when electric power was restored. 

At that point, there was a surge in demand as gas appliances that had been unable 

 192 SPS is the city’s electrical supplier. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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to operate without electricity simultaneously came back in service. Almost 

immediately, Zia began receiving calls from customers reporting that they had no 

gas or very low gas pressure. In all, 406 customers called in to report supply 

problems. 

 Zia believes the reason for the outages was the sudden surge in demand 

when electric power came back online, coupled with the low line pressures that 

resulted from the DCP plant outage. That morning, Zia began the process of 

relighting the primarily residential customers that were affected, and the company 

was able to restore all gas service by 10:00 PM the same day. 

 Zia customers in the Ruidoso, New Mexico area also lost gas service as a 

result of the cold weather events. During the early morning hours of February 3, 

the Ruidoso area experienced power outages that lasted until 8:00 AM. At the 

same time, receipt pressures from El Paso were declining. 

 At approximately 7:30 AM, Zia began receiving complaints of no gas or 

low gas pressure. Personnel sent to the area reported extremely low pressures, and 

did what they could to boost flow by bypassing regulator stations. Through a local 

radio station that was operating on backup power, the company asked the 

community to cut back on gas use. Pressures were critically low through most of 

the morning but began to rise just before noon. However, when electrical power 

was restored, there was a surge in demand that further strained the system. A total 

of 50 customers at the far reaches of the distribution system lost gas service that 

day, but their service was fully restored by the end of the working day. 

According to Zia, it has no industrial or large load single customers; almost 

all of its customers are residential or small commercial users. Thus, it was not 

possible for Zia to reduce demand by curtailing large commercial accounts. Zia 

believes the Ruidoso outages were caused by high demand on the system, 

combined with low supply pressures and the surge in demand that occurred when 

power was restored. 

New Mexico Gas Company

 NMGC serves more than 500,000 retail customers in towns, pueblos, cities 

and rural areas throughout New Mexico. NMGC’s distribution system is divided 

into two areas: (1) the north segment, serving the Albuquerque metropolitan area 

and communities to the north; and (2) the south/remotes segment, consisting of (a) 

the southeast system, which serves the towns of Roswell, Artesia, Carlsbad, 

Lovington, Eunice, and surrounding areas, and (b) remote locations, including 

Alamogordo, Silver City, Clovis, Portales, Tucumcari, Hatch, and Truth or 

Consequences. The north and the south/remotes segments are served by the 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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Transwestern and EL Paso interstate pipelines and by other third-party pipelines. 

The remote locations that lost gas service during the period in question were 

supplied solely by El Paso. 

NMGC: The North Segment

 On February 2, 2011, NMGC personnel monitoring the company’s north 

segment, which serves the Albuquerque metropolitan area and communities to the 

north, noted that gas volumes at the company’s receipt points with El Paso and 

Transwestern were not increasing, indicating that much of the company’s 

nominated gas was not being received. However, although line pack was 

decreasing, the system was still operating within sustainable limits. Based on 

additional gas purchases made during the day, the company expected pressures at 

receipt points to increase at 9:00 PM that night and at 8:00 AM the following 

morning. 

 

 As a precautionary measure, the company began telephoning large 

commercial users on the morning of February 2, seeking voluntary reductions of 

gas consumption. NMGC employees, working from a list of the company’s 200 

largest customers, placed phone calls or sent emails to points of contact on the list. 

Customers were informed that the company was expecting a gas shortage and that 

cutting back on gas usage was necessary to maintain service to home, hospitals, 

and other top priority consumers. 

 In some instances, large customers agreed to reduce their gas use, either by 

switching to alternative fuel supplies, lowering thermostats, or shutting down 

equipment or manufacturing processes. However, some of the customers 

(approximately 10 percent of those contacted) indicated that they could not or 

would not reduce their usage. 

 One of the large customers NMGC contacted was PNM, which operates 

two gas-fired generating plants in the Albuquerque area. Contacted at 9:42 AM on 

February 2, PNM responded by stating that no curtailment options were available 

to it, and that the plants would be increasing their gas consumption to meet power 

generation requirements. 

 In other instances, NMGC was unable to reach a point of contact for its 

large customers and could only leave messages requesting cutbacks or return calls. 

NMGC estimates that it was ultimately able to contact 30 percent of the top 200 

users to request voluntary curtailment. 

 NMGC was expecting the supply problems to improve at 9:00 PM on 

February 2, because of the extra gas it had purchased. When line pressure did not 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 129 - 

improve at that time, due to the inability of suppliers to put the purchased gas on 

the system, the company began contacting other pipelines and suppliers in an 

effort to purchase more gas. 

 During the early morning hours of February 3, NMGC personnel 

monitoring line pressure on the north segment, from both the company’s gas 

control center and field locations, believed the system would have enough gas to 

meet the anticipated morning demand, based on the amount of gas that had been 

used the previous day. However, beginning at 7:12 AM, the demand for gas rose 

to unprecedented levels, even though temperatures were only slightly higher than 

the day before.193 

 Even at this point, however, the company concluded that if pressures at 

receipt points began to rise at 8:00 AM, as expected based on the additional gas 

that had been purchased, they would be able to meet the increased demands on the 

system. 

 However, pressures continued to decline at 8:00 AM, leading NMGC to 

conclude that it was in immediate danger of losing the entire system and that they 

must immediately reduce demand by cutting off sections of the system. At around 

this time, the company also began receiving reports of no gas or low gas pressure 

in the Albuquerque area, further indicating that its system was near collapse. 

 Because NMGC needed to act quickly, and because the distribution 

systems in the larger metropolitan areas of Santa Fe and Albuquerque were not 

configured so as to allow curtailment of large numbers of customers by closing 

just a few valves, the company decided to curtail the areas served by the Taos 

mainline, which runs from the company’s north-south mainline at Otowi junction, 

located approximately 80 miles north of Albuquerque. That line serves the 

communities of Española, Dixon, Taos, Questa, and Red River. The Otowi 

Junction valve was closed at 8:37 AM, cutting off service to those communities. 

 

 The company also curtailed two additional communities just north of 

Albuquerque by closing two valves that supplied the town of Bernalillo at 8:55 

AM and 9:14 AM, and by closing one valve to the town of Placitas at 9:29 AM. 

 193 NMGC told the task force that although temperatures were slightly warmer on the 

morning of February 3, compared to the previous morning, demand was nevertheless higher, 

despite NMGC’s efforts to seek voluntary curtailment from large users, and despite appeals 

through the media for residential customers to conserve gas. NMGC does not know the reason 

for the increased demand. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 130 - 

 If pressures continued to decline, the next step anticipated by NMGC was 

curtailing sections of the Albuquerque metropolitan area. Curtailment options in 

that area were limited, however, because of the lack of shut off valves capable of 

curtailing a large block of customers at one time. The company nevertheless 

prepared for curtailments by sending a crew with a backhoe to two sections of 

pipeline that served 2,000 customers, with the intention of digging up the pipes 

and pinching them off.194 

 At 9:20 AM, following discussions between NMGC and PNM about 

system conditions, PNM decided to switch its Delta Person (Cobisa) power plant 

from gas to backup fuel oil. PNM was unable to make the changeover because of 

a faulty valve, and as a result the plant went out of service and did not draw gas 

from the system for the duration of the cold weather event. 

 By 10:30 AM, pressure on the north segment had stabilized and had begun 

to increase. The restoration process was already underway at that point, as NMGC 

teams began shutting off meter valves to individual customers so that the lines 

could be purged and recharged. 

NMGC: The South/Remotes Segment

 On February 2, line pressure on El Paso’s delivery pipeline to NMGC’s 

south/remotes segment steadily declined, dropping below contract pressure195 at 

approximately 10:00 AM. As the day progressed, NMGC personnel monitored 

line conditions and began considering the possibility that if conditions worsened, 

they would have to curtail certain areas. 

 At approximately 3:00 PM, NMGC started calling large customers on the 

south segment to ask them to voluntarily reduce their gas consumption. Some of 

the larger customers, such as Western New Mexico University, Silver City School 

System, and the Alamogordo School System, agreed to reduce usage, but two 

other large users -- Holloman Air Force Base and the White Sands Missile Range -

- could not be reached that day, reportedly because the bases were closed because 

of the weather conditions and the contact persons were not present. (Holloman 

Air Force Base was successfully contacted the following day at approximately 

1:00 AM, and agreed to reduce its usage at that time.) 

 194 Transcript of Testimony of Doug Arney at 4, In the Matter of an Investigation into 

New Mexico Gas Co.’s Curtailments of Gas Deliveries to New Mexico Consumers,, NMPRC 

(Mar. 17, 2011) (No. 11-00039-UT). 

195 Contract pressure is the minimum gas pressure, measured in pounds per square inch, 

that a pipeline agrees to provide to a customer at a given delivery point. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 131 - 

 Shortly before 5:00 PM on February 2, NMGC received notice from El 

Paso that line pressure was not expected to improve during the next 24 hours. 

 At 1:50 AM on February 3, NMGC began cutting off service to schools and 

non-essential government buildings in Alamogordo. At 2:36 AM, seeing that 

conditions were continuing to deteriorate, the company declared a system 

emergency on the south segment. 

 At 3:00 AM, NMGC cut off service to the communities of Tularosa and La 

Luz, which are located at the end of the NMGC distribution pipeline that serves 

Alamogordo. Line pressures continued to decline, however, and at 5:05 AM, the 

company shut off one section of Alamogordo. At 6:00 AM, the Alamogordo area 

experienced an electrical blackout. When electricity was restored at 8:00 AM, the 

resulting surge in demand for gas caused pressure to drop to zero on the southern 

part of the Alamogordo system, forcing NMGC to cut off that section as well. In 

all, more than 4,300 customers lost gas service in Alamogordo, Tularosa and La 

Luz, out of a customer base of approximately 15,000. By 9:25 AM, pressures in 

the Alamogordo area began to stabilize, and by 3:00 PM that day, the company 

began restoring service to curtailed areas. 

 Another community on the NMGC south/remotes segment that lost a 

portion of its gas service on February 3 was Silver City. According to NMGC, the 

Silver City distribution network lacked the capacity to meet the unprecedented 

demand for gas on February 2 and February 3, due to system limitations. NMGC 

stated that in 2007, it determined that the system’s maximum operating pressure 

should be reduced from 40 psi to 30 psi for safety reasons. With that limitation, 

the system could not transport the volumes demanded by customers. 

 

 Although two large users in that area, the Silver City Consolidated School 

District and Western New Mexico University, agreed to curtail gas use on 

February 2, mitigating demand on the system to some extent, pressure continued 

to drop. NMGC curtailed a section of Silver City at approximately 6:00 AM the 

following day, February 3, in order to avoid total collapse of the system. Pressure 

began to recover by 11:00 AM, and restoration efforts began shortly thereafter. A 

total of 271 out of approximately 9,200 customers in the area lost gas service due 

to the curtailments. 

 NMGC has informed the task force that it is in the process of making 

improvements to the Silver City distribution system that should allow it to meet 

peak loads of the sort that occurred during the February event. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 132 - 

 Restoration of Service

 Closing individual gas meters, which is the first stage of restoring service, 

began shortly after NMGC cut off service on the morning of February 3. In some 

areas, NMGC personnel began shutting off meters within minutes of the 

curtailment. As restoration efforts got underway, the company sought additional 

help through its mutual assistance agreements with the American Gas Association 

and the Southern Gas Association, whereby member LDCs agree to help each 

other in emergency situations. That morning, NMGC asked other member LDCs 

by email and by conference call to send personnel to help them restore service in 

the affected areas. Out-of-state LDCs responded by sending qualified service 

personnel, who began to arrive the following day. NMGC also sought help from 

other New Mexico LDCs, and hired local contractors and plumbers to help restore 

service. Police, fire department, and National Guard personnel all eventually 

played roles in the effort to restore service. 

 Relighting continued through the weekend and into the following week, 

with a workforce of more than 700 persons participating. Service was restored to 

some areas as early as February 5, but the statewide relighting effort was not 

substantially completed until the following week, on February 10. 

The Arizona Curtailments and Outages

 Southwest Gas, a multistate LDC whose service areas include the cities of 

Tucson and Sierra Vista in Arizona, was forced to curtail service to parts of those 

cities on February 3 due to low pressures at receipt points with El Paso. After El 

Paso declared a system-wide Critical Operating Condition at 11:52 AM on 

February 2, due to declining line pack and drop offs in gas supply, Southwest 

Gas’s management met at 1:00 PM to plan for increased monitoring of the 

distribution systems. Shortly thereafter, at about 2:00 PM, the company started 

calling large commercial customers to alert them to possible curtailments. 

 At 10:00 PM, as conditions on the El Paso pipeline continued to deteriorate, 

Southwest Gas concluded that it might be necessary to cut off some customers in 

order to preserve system operability. When pressures on the Sierra Vista system 

reached a critical stage at approximately 3:30 AM on February 3, the company 

identified several sections of the system that should be shut down to reduce 

demand. At approximately 6:30 AM, crews began closing valves in Sierra Vista 

and Tucson. Out of a total of 17,801 customers in Sierra Vista, 4,596 were shut 

off; out of a total of 279,362 customers in Tucson, 14,620 were shut off. 

 Starting at approximately 5:00 AM on February 3, the company began 

curtailing several large commercial customers, including an electric power plant in 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 133 - 

Tucson. Other commercial users voluntarily curtailed or reduced their use 

throughout the day. 

 By 8:30 AM, pressures began to stabilize and recover, and the restoration 

process was initiated. Southwest Gas brought in 130 employees from other 

divisions in California, Nevada, and Central Arizona to help with the relighting 

process, and service was fully restored on the afternoon of February 7, 2011. 

The Texas Curtailments and Outages

 Texas Gas Service (TGS) serves several communities in Texas, with a total 

of 616,462 residential, commercial, and transportation customers. The City of El 

Paso is one of those communities, and during the week in question it was the only 

city in Texas to experience gas curtailments, with 863 residential customers (out 

of approximately 231,000) losing service. 

 Gas is delivered to TGS by the El Paso and ONEOK WesTex 

Transmission, L.L.C. (ONEOK WesTex) pipelines. Beginning around February 2, 

TGS received cuts from its suppliers and had to make alternative arrangements to 

obtain gas for the anticipated cold weather demand, including buying compressed 

natural gas (CNG) for expedited delivery by tanker truck from Arizona. The 

company also experienced low delivery pressures from El Paso later that week. 

However, those factors were not responsible for the service disruptions that 

occurred. According to TGS, the El Paso system experienced unprecedented 

demand during the winter event, as much as 41 percent higher than the previous 

historical peak.196 The company’s distribution system was simply unable to 

handle that much volume. 

 Beginning on February 2, at approximately 8:00 AM, residential customers 

began reporting low pressures. Shortly thereafter, customers in low pressure areas 

of the system began losing service. TGS responded to each reported outage, and 

in some instances service was restored the same day. A total of 863 customers lost 

service during an approximately 24 hour period. Service was fully restored by 

February 5. The restoration process was hampered by icy road conditions, and by 

the fact that TGS workers could not restore service when customers were not at 

home.

 In order to alleviate pressure on the system during the period of peak 

demand, TGS asked ten large transportation customers to reduce consumption at 

 196 On February 3, 2011, TGS delivered 258,853 MMBtu to its customers in El Paso. 

The previous peak at that location was 184,088 MMBtu, in January 2007. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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approximately 10:00 AM on February 3. The company also restricted service to 

36 commercial customers in areas that were experiencing low pressure, and on 

February 3, extended a gas main to boost pressures in one of the affected areas. In 

addition, TGS used two CNG tankers to help deal with low pressure issues. One 

was used to maintain service to a hospital, and the other was deployed to assist in 

the restoration process in one of the affected neighborhoods. 

 TGS plans to make additional system improvements to increase delivery 

capacity by extending gas mains in several areas that experienced low pressures 

during the period in question. The cost of these improvements is expected to total 

more than $1.7 million and the company estimates that they will be completed by 

September 30, 2011. 

 

The California Curtailments

 SoCalGas and SDG&E are separate utility companies, both owned by 

Sempra Energy. SoCalGas serves approximately 20 million customers in Central 

and Southern California; SDG&E serves approximately 3.4 million customers in 

Orange and San Diego Counties, California. SoCalGas operates the natural gas 

transportation systems of both companies.197 

 

 Beginning on January 31, 2011, SoCalGas monitored weather 

developments in the Southwest and was aware of the supply problems that had 

developed because of the severe cold weather. The company responded to supply 

shortfalls by increasing withdrawals from on-system storage and by purchasing 

operational gas to support the southern system, which cannot be served by storage 

gas. Delivery shortfalls were highest on February 2 and February 3. SoCalGas 

estimates that the net cost of the operational gas it purchased was $3.81 million, 

representing the purchase price of the gas less the price at which SoCalGas was 

later able to sell it. 

 On the morning of February 3, the company issued a curtailment advisory 

to non-core (lower priority) customers, informing them that curtailments could 

occur. At 1:15 PM, due to the continuing severe weather and its effect on 

production, the company declared a system emergency and curtailed transmission 

service on its southern system for all interruptible and some firm non-core 

customers by limiting the amounts they could withdraw from the system. 

 SoCalGas curtailed 19 interruptible retail non-core and electric generator 

customers, and 40 firm non-core and electric generator customers. SDG&E 

 197 Sempra Energy, Our Companies, http://www.sempra.com/companies/companies.htm. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 135 - 

curtailed all its interruptible load and all its firm service to three electric generator 

customers. SoCalGas reported that its non-core customers and electric generator 

customers generally complied with curtailment limits during the emergency. 

When the CAISO informed the two companies that approximately 500 MW of 

total generation was needed from two of the curtailed electric generators in order 

to ensure reliable grid operations, SoCalGas and SDG&E adjusted the 

curtailments so that the two plants could provide the necessary generation. 

Resumption of Production

 Weather conditions moderated slightly in the Southwest on February 3 and 

improved further on February 4, rising above freezing for the first time in days. 

Although production did not return to pre-event levels for several weeks, 

consumer demand slackened with the warmer weather, and line pack and system 

pressure rose steadily on the interstate pipelines. As a result, El Paso issued a 

warning of a system pack condition on February 5, and declared a system -wide 

Strained Operating Condition for high line pack February 6, 2011.198 

Impacts of the Event on Natural Gas Prices

Gas prices responded to the winter weather and associated freeze-offs, 

although the increases were short-lived and not exceptionally dramatic. Some 

points in the midcontinent and southwest regions did post increases of 

approximately two dollars to three dollars per MMBtu, which were gains of 40 to 

60 percent relative to February 1. West Texas prices were particularly strong with 

a basis at Waha of $2.60 relative to Henry Hub.199 Southern California prices at 

Ehrenberg and Needles also traded higher by $1.77, reflecting upstream supply 

shortfalls. 

The price gains in east Texas and south Texas were more muted, despite the 

freeze-offs extending to the Gulf Coast, and limited to $0.50 to $0.60 per MMBtu. 

The Houston Ship Channel, however, had an increase of almost $1.57. 

The NYMEX (New York Mercantile Exchange) futures contract was flat to 

declining for the week. Cash prices at Henry Hub increased by only $0.29. 

Most gains were gone by February 5, at which time warmer weather had 

returned. Prices on February 8 actually traded below those of February 1. 

 198 Production figures from Bentek, supporting documentation for Deep Freeze Disrupts 

U.S. Gas, Power, Processing ( Feb. 8, 2011); information provided to the task force by pipelines. 

199 Basis is the price differential between, in this case, Henry Hub and Waha. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 136 - 

The following table shows spot prices at a variety of locations for February 

1 to February 8.200 Daily closing prices are also listed for the NYMEX March gas 

futures contract, which is based on delivery at Henry Hub. The NYMEX price 

was relatively unaffected by the spot price increases during February 1 to February 

8, suggesting that traders viewed the increases as a temporary, weather-related 

event. 

Spot Prices 

Flow Date 1-Feb 2-Feb 3-Feb 4-Feb 5-Feb 6-Feb 7-Feb 8-Feb 

Waha $ 4.47 $ 4.79 $ 5.80 $ 7.30 $ 4.76 $ 4.76 $ 4.76 $ 4.25 

El Paso-Permian $ 4.40 $ 4.75 $ 5.74 $ 7.23 $ 4.86 $ 4.86 $ 4.86 $ 4.19 

Transwestern-San Juan $ 4.35 $ 4.66 $ 5.73 $ 6.40 $ 4.49 $ 4.49 $ 4.49 $ 4.11 

El Paso-San Juan $ 4.30 $ 4.51 $ 5.77 $ 6.52 $ 4.51 $ 4.51 $ 4.51 $ 4.10 

East Texas, Carthage Hub $ 4.36 $ 4.42 $ 4.63 $ 4.89 $ 4.49 $ 4.49 $ 4.49 $ 4.28 

Houston Ship Channel $ 4.40 $ 4.37 $ 4.61 $ 5.91 $ 4.43 $ 4.43 $ 4.43 $ 4.29 

South Texas, Tennessee Zone 0 $ 4.38 $ 4.39 $ 4.62 $ 5.03 $ 4.40 $ 4.40 $ 4.40 $ 4.28 

Oneok Oklahoma $ 4.49 $ 5.31 $ 7.06 $ 6.28 $ 4.59 $ 4.59 $ 4.59 $ 4.40 

SoCal Gas $ 4.40 $ 4.50 $ 5.47 $ 6.17 $ 4.52 $ 4.52 $ 4.52 $ 4.22 

Henry Hub $ 4.42 $ 4.43 $ 4.55 $ 4.70 $ 4.48 $ 4.48 $ 4.48 $ 4.33 

NYMEX Contract $ 4.42 $ 4.35 $ 4.43 $ 4.34 $ 4.31 $ 4.31 $ 4.31 $ 4.10 

The following table shows the basis for the same locations relative to cash 

prices at Henry Hub. 

Basis 

Flow Date 1-Feb 2-Feb 3-Feb 4-Feb 5-Feb 6-Feb 7-Feb 8-Feb 

Waha $ 0.05 $ 0.37 $ 1.25 $ 2.60 $ 0.29 $ 0.29 $ 0.29 $ (0.08) 

El Paso-Permian $ (0.02) $ 0.32 $ 1.19 $ 2.53 $ 0.38 $ 0.38 $ 0.38 $ (0.14) 

Transwestern-San Juan $ (0.07) $ 0.24 $ 1.18 $ 1.70 $ 0.02 $ 0.02 $ 0.02 $ (0.22) 

El Paso-San Juan $ (0.12) $ 0.08 $ 1.22 $ 1.82 $ 0.04 $ 0.04 $ 0.04 $ (0.23) 

East Texas Carthage Hub $ (0.05) $ 0.01) $ 0.08 $ 0.19 $ 0.01 $ 0.01 $ 0.01 $ (0.05) 

Houston Ship Channel $ (0.01) $ (0.06) $ 0.06 $ 1.21 $ (0.05) $ (0.05) $ (0.05) $ (0.04) 

South Texas Tennessee Zone 0 $ (0.04) $ (0.04) $ 0.07 $ 0.33 $ (0.08) $ (0.08) $ (0.08) $ (0.05) 

Oneok Oklahoma $ 0.07 $ 0.88 $ 2.51 $ 1.58 $ 0.12 $ 0.12 $ 0.12 $ 0.07 

SoCal Gas $ (0.02) $ 0.08 $ 0.92 $ 1.47 $ 0.04 $ 0.04 $ 0.04 $ (0.11) 

 200 Daily price survey ($/MMBtu), Platts Gas Daily, Feb. 1, 2011, at 1-2.; Daily price 

survey ($/MMBtu), Platts Gas Daily, Feb. 2, 2011, at 1-2.; Daily price survey ($/MMBtu), Platts 

Gas Daily, Feb. 3, 2011, at 1-2.; Daily price survey ($/MMBtu), Platts Gas Daily, Feb. 4, 2011, at 

1-2.; Daily price survey ($/MMBtu), Platts Gas Daily, Feb. 5, 2011, at 1-2.; Daily price survey 

($/MMBtu), Platts Gas Daily, Feb. 6, 2011, at 1-2.; Daily price survey ($/MMBtu), Platts Gas 

Daily, Feb. 7, 2011, at 1-2.; Daily price survey ($/MMBtu), Platts Gas Daily, Feb. 8, 2011, at 1-2. 

Reprinted with permission of Platts. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 137 - 

The following three charts show the absolute prices, basis, and price change 

of natural gas during the week of the event. 

GDD Midpoint and NYMEX Pricing 

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

$7.00

$7.50

2/1/2011 2/2/2011 2/3/2011 2/4/2011 2/5/2011 2/6/2011 2/7/2011 2/8/2011

Waha El Paso-Permian Transwestern-San Juan El Paso-San Juan

East Texas Carthage Hub Houston Ship Channel South Texas Tennessee Zone 0 Oneok Oklahoma

SoCal Gas NYMEX Contract

 Source: Task Force analysis based on Platts data 

GDD Midpoint Basis to Henry Hub

-$0.10

$0.40

$0.90

$1.40

$1.90

$2.40

$2.90

2/1/2011 2/2/2011 2/3/2011 2/4/2011 2/5/2011 2/6/2011 2/7/2011 2/8/2011

Waha El Paso-Permian Transw estern-San Juan

El Paso-San Juan East Texas Carthage Hub Houston Ship Channel

South Texas Tennessee Zone 0 Oneok Oklahoma SoCal Gas

 Source: Task Force analysis based on Platts data 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

- 138 - 

Price Change Relative to Feb 1

-$0.10

$0.40

$0.90

$1.40

$1.90

$2.40

$2.90

2/1/2011 2/2/2011 2/3/2011 2/4/2011 2/5/2011 2/6/2011 2/7/2011 2/8/2011

Waha El Paso-Permian Transwestern-San Juan El Paso-San Juan

East Texas Carthage Hub Houston Ship Channel South Texas Tennessee Zone 0 Oneok Oklahoma

SoCal Gas NYMEX Contract

 Source: Task Force analysis based on Platts data 

The causes of the electric generator failures and the natural gas shortfalls 

described above are examined in the following section of this report, entitled 

“Causes of the Outages and Supply Disruptions.” 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

VI. Causes of the Outages and Supply Disruptions 

The precipitating cause of the rolling blackouts experienced in Texas and 

Arizona during the February 2011 cold weather event was the large number of 

electric generator outages. The principal cause of the gas service curtailments 

experienced in several southwestern states was the production declines in the 

supply of natural gas, which led to volume and pressure reductions in the 

pipelines. The task force has analyzed in detail the causes of these outages and 

declines, and found that the majority of them were directly or indirectly related to 

the weather, particularly so with respect to production declines in the gas supply. 

This section of the report describes in detail those causes, both weather and nonweather-related. 

While the storm itself was an uncontrollable event of force majeure, the 

question arises as to whether the facilities affected should have been better 

prepared to withstand the severe weather. Was the cold spell so unprecedented 

that the entities responsible for those facilities could not reasonably be expected to 

have taken preventative actions? Or did entities fail to take into account lessons 

that could have been learned from past cold weather events in the Southwest? 

These questions are addressed in the next section of this report, entitled “Prior 

Cold Weather Events.” 

A. Electric

 The rolling blackouts that utilities implemented during the cold weather 

event, which centered in Texas (ERCOT, EPE) and Arizona (SRP), were almost 

entirely the result of trips, derates, and failures to start of the generating units in 

those regions. The localized blackouts experienced by PNM in New Mexico, 

however, were caused by transmission trips. Units in Oklahoma and Kansas also 

experienced generator outages, but these did not result in blackouts. 

 The task force has analyzed these various generator outages to determine 

their underlying causes. By far, the most common cause of the outages was the 

cold weather, most commonly when sensing lines froze and caused automatic or 

manual unit trips. There were also several outages that were due to operator error 

or non-weather-related equipment failures. In a lesser number of cases, an 

interruption in the supply of natural gas prevented gas-fired units from providing 

power. 

- 139 - 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

The following two charts201 and supporting table depict the various causes 

of the trips, derates, and failures to start202 for generating units throughout the 

Southwest, both by number of units and by MWhs. 

Southwest - Number of Units Tripped, Derated, and Failed to 

Start - Feb. 1 - 5, 2011 

Total Entries in Pie Chart: 317 

Total Number of Units Forced Out, Derated, or Failed to Start: 268 

 201 Data includes generation in Texas (ERCOT and non-ERCOT), New Mexico, Arizona, 

and SPP. Units on the first chart are counted more than once if they failed multiple times from 

different causes (75 units failed on more than one occasion during the event); however, they are 

only counted once per cause. Data used in the preparation of this chart are drawn from materials 

submitted to the task force by balancing authorities and generators. Data throughout the section 

are drawn from materials submitted by transmission operators, generators, producers, processing 

plants, and pipelines. 

202 Trips totaled 167 units (30,376 MW), derates totaled 57 units (5024 MW), and failures 

to start totaled 44 units (4743 MW). 

- 140 - 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Southwest – MWh203 of Generation Unavailable - Feb. 1 - 5, 2011 

Total MWh in Pie Chart*: 1.2 Million 

Total MWh of Load Served in affected Southwest Areas: 6.7 Million 

Generation unavailable as a percentage of Total MW-hours Load Served: 18% 

*Total time period is 106 hours (Midnight going into Feb. 1 through 10 AM Feb. 5) 

 203 Megawatt hours were used for this chart to give an indication of the time impact of the 

outages, derates, and failures to start. (From an operator’s perspective, a smaller unit out for a 

longer time might have a greater impact than a larger unit out for a short time, depending on the 

circumstances.) To capture this time factor, each instance of unavailable capacity was multiplied 

by the associated duration of the particular outage or derate and the results were summed. 

- 141 - 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Supporting Table (Southwest): 

Cause 

# of Unique 

Units MWh 

Total Frozen Sensing lines: 89 432,897 

Frozen - Drum level sensing lines 48 150,000

Frozen - Other Sensing lines 41 282,896

Frozen Equipment (General) 21 153,393 

Frozen Water lines 14 80,091 

Frozen Valves 12 20,603 

Blade Icing (Wind Turbines) 10 53,989 

Low Temperature Limits (Wind Turbines) 17 80,389 

Transmission Loss 2 2,944 

Fuel Supply Problems (Curtailments/Quality) 32 119,844 

Mechanical Failure 47 192,610 

Control System Issues 34 33,872 

Operator Error 9 3,792 

Emissions 4 10,508 

Fuel Switching 15 29,106 

Miscellaneous 11 7,952 

 The large percentage of weather-related outages speaks in part to the design 

and construction of generating facilities in the Southwest. Unlike facilities in cold 

climates, generating stations in the Southwest are typically designed and 

constructed so that their boilers, turbines, and other auxiliary systems are exposed 

to ambient weather conditions. This design prevents heat build-up from occurring 

in the hot summer months. A more detailed discussion of generating plant design 

is contained in the appendix entitled “Power Plant Design for Ambient Weather 

Conditions.” 

Sub-freezing temperatures can have adverse operational effects on 

generating stations if systems containing water do not have sufficient freeze 

protection, if pneumatic air systems do not have sufficient air drying capacity or 

freeze protection, or if equipment lubricants are not maintained above prescribed 

minimum temperatures. Generators with exposed elements typically employ a 

combination of heat tracing, insulation, wind breaks or enclosures, and heat 

sources to prevent freezing and to maintain minimum lubricant temperatures. 

Frozen sensing lines were a particular problem during the February cold weather 

event, when many generators automatically tripped offline due to faulty readings 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

from transmitters whose sensing lines froze (most notably steam drum204 level 

transmitters). 

A detailed examination of the causes of the generator outages experienced 

within ERCOT, SRP and EPE during the February event, both weather and nonweather-related, is set forth below. 

Generation Outages in ERCOT

 As a preliminary matter, the task force categorized by age and fuel type the 

ERCOT units that failed, to determine whether there was any statistical indication 

that older units or units of a given fuel type were more prone to developing 

problems. With respect to age, no strong correlation was found. The failure 

percentage of units with in-service dates before 1981 (19 percent) was actually 

less than their percentage contribution to the ERCOT fleet as a whole (22 

percent).205 The failure of units with recent in-service dates (between 2001 and 

2010) represented 55 percent of the failures, which was slightly more than their 

contribution to the fleet as a whole (48 percent). 

 The results are more equivocal with respect to type of unit, where a more 

significant correlation was found with respect to combined cycle units. Otherwise, 

however, no significant correlation was found between failure and type of unit. Of 

ERCOT’s combined cycle units, 48 percent failed, compared to their 35 percent of 

the total. For wind units, 16 percent failed, compared to their 15 percent of total 

units. For simple cycle units, 21 percent failed, compared to their 20 percent of 

total units. For gas-steam and coal units, the percentage that failed exactly 

matched their percentage contribution of total units (13 percent and 7 percent, 

respectively). Nuclear facilities account for only 1 percent of the total fleet, and 

no nuclear units failed.206 

 204 Steam drums are used in boilers (excluding once-through supercritical boilers) to take 

in a mixture of steam and water coming from the boiler’s waterwall tubes. The drum separates 

the steam from the water by gravity and mechanical separation (such as baffles). The water level 

in the drum is controlled to keep water in the waterwall tubes and to prevent water carrying over 

into the steam section of the boiler. The drum also functions to remove solids from the steam. 

205 This statistic and those immediately following are based on number of units, rather 

than on capacity. (Coal units, for instance, have a larger capacity contribution to the fleet as a 

whole than seven percent, which is their percentage contribution based on number of units.) 

206 The totals do not add up to 100 percent because certain other facilities have not been 

taken into account, such as hydro facilities and storage facilities. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

For purposes of further analysis, the task force sorted by unit207 the ERCOT 

generator trips, derates, and failures to start into three broad categories: weatherrelated, non-weather-related, and fuel supply. (The weather-related category 

considers only failures directly related to the weather; problems of insufficient fuel 

supply as well as outages and derates resulting from fuel switching, although 

indirectly related to the weather, are listed separately.) Direct weather-related 

causes accounted for 52 percent of the total failures, non-weather-related causes 

for 40 percent, and problems with fuel supply for nine percent.208 Sub- categories 

within these major groupings, as well as specific examples of the various types of 

failures, are provided below. 

ERCOT Weather-Related Outages and Derates

The task force identified the various specific causes for the trips, derates, or 

failed starts in ERCOT between February 1 and February 5 that were due directly 

to the cold weather.209 (Some of the other failures experienced by ERCOT 

generators, such as reduced supplies of natural gas, were indirectly related to the 

weather.) The task force has identified the specific causes of these weatherrelated failures, by number of units and number of MWs: 

Cause No. of Units Lost MW Lost 

Frozen Sensing Lines (Total) 68 15,255 

 Frozen Drum Level Sensing Lines (43) (9438) 

 Frozen Other Sensing Lines (25) (5817) 

Frozen Equipment (General) 13 2942 

Frozen Water Lines 12 1072 

Frozen Valves 8 1501 

Blade Icing (Wind Turbines) 10 709 

Low Temperature Limits (Wind Turbines) 17 1237 

Transmission Loss 2 89 

Total Weather-Related 130 22,805 

 207 A unit that failed multiple times for different reasons is counted under each separate 

reason; if it failed multiple times for the same reason, it is counted once. That convention applies 

as well to the three charts detailing ERCOT’s weather, non-weather, and fuel failures. 

208 Numbers add up to slightly higher than 100 percent due to rounding. 

209 The weather effects stemmed not only from the prolonged cold, but from high wind 

chill factors. Although typically thought of as applying to living beings, wind chill also more 

quickly cools inanimate objects, such as water pipes, bringing them down to the current air 

temperature. Wind also causes the loss of radiant heat, which otherwise can protect equipment 

from freezing. This phenomenon is discussed at more length in the appendix entitled “Impact of 

Wind Chill.” 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

A sample of the ERCOT generating units that experienced weather-related 

failures, categorized by the specific cause of failure, provides some insight into the 

variety of concerns with which the generator operators had to contend during the 

event, and illustrates the complexity of the protections needed for generating plant 

systems. 

 

 Frozen Sensing Lines: Instrumentation provides operational data 

necessary to monitor and control the generator’s systems. Typically, 

sensing lines containing a standing water column sense changes in pressure 

and a transducer produces an electronic signal that is transmitted to 

instrumentation or controls. In sub-freezing temperatures, if freeze 

protection is not employed on critical unit systems, the water in the sensing 

lines freezes, causing faulty signals and subsequent unit trips or derates. 

During the February event, frozen sensing lines were the leading cause of 

outages, with steam drum sensing lines being the most prevalent (43 units 

tripped from this cause alone). 

 JK Spruce Unit 2, a 785 MW coal unit, tripped due to frozen sensing 

lines that caused a false high water level reading in the steam drum. 

 Ingleside Cogeneration lost two units due to frozen sensing lines. 

The lines were heat traced, but the ground fault interrupter breakers 

protecting the heat trace circuits tripped, resulting in a loss of 176 

MW. 

 Another unit tripped due to frozen sensing lines on feedwater heater 

level controls. The freezing caused a high condensate level in a 

feedwater heater, which in turn incorrectly initiated a trip of the unit. 

 Non-drum sensing line failures included a unit whose vacuum 

system became erratic when the sensing line to the auxiliary steam 

pressure indication froze. Another unit tripped when the sensing 

lines to the rotor air cooler level transmitters froze. 

Sensing Lines and Frozen Transmitters

There were many reports of frozen transmitters causing generating units to be 

forced offline during the cold weather event. In almost all cases, it was not the 

transmitters themselves that froze, but rather sensing lines filled with standing 

(non-flowing) water routed between the transmitters and the points the sensing 

lines are measuring. 

(cont’d)

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Transmitters

The transmitter assemblies perform three distinct functions. First, they detect the 

difference in pressure between two water lines, typically with a diaphragm-type 

sensor that deflects in the direction of, or towards, the lower pressure. Second, 

they serve as transducers that translate the pressure difference into an electrical 

signal. Third, they boost or otherwise process the signal for transmitting to the 

plant’s control room, generally using electronics. 

Differential Pressure Measurement

The technique of measuring the pressure difference (differential pressure) between 

two sensing lines filled with water has widespread application throughout power 

plants, especially in steam-powered generating units. This is due to the fact that 

differential pressure can be used to provide not just a measure of pressure itself, 

but also of water levels and flow rates. Significant applications include the 

following: 

 Pressure Measurement 

o Between a boiler feedwater pump and the steam drum 

 Water Level Measurement 

o In feedwater heater tanks 

o In the deaerator tank 

o In the steam drum 

 Water Flow Measurement 

o Feedwater flow 

o Generator stator cooling water flow 

Water Level Measurement

Differential pressure can be used to measure water level by virtue of the force of 

gravity, which results in greater pressure as the water level increases. This is akin 

to the hydraulic head resulting from water in an open reservoir, which is a measure 

of water pressure compared against standard atmospheric pressure. The method 

needs to be modified, however, to account for the fact that the space within a tank 

above the water is pressurized. Hence the use of differential pressure 

measurement, with one sensing line connected to the bottom of the tank to sense 

the water pressure, and the other to the top of the tank to sense the water vapor or 

steam pressure. The line at the top of the tank is known as the reference line. 

Even though the reference line connects to the top of the tank, which is above the 

water level, it will itself still fill up with water because the vapor/steam condenses 

in the line due to the much cooler ambient air temperature external to the tank. 

 (cont’d)

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Water Flow Measurement

Differential pressure can be used to measure water flow by virtue of Bernoulli’s 

principle: an increase in the speed of a flowing fluid is accompanied by a decrease 

in pressure. This increase in speed can be forced by placing a constriction such as 

an orifice plate or nozzle inside a pipeline, reducing its effective diameter. In 

order for the rate of flow in gallons per minute, for example, to remain the same, 

the velocity of the fluid must increase to make up for the fact that it is travelling 

through a smaller opening. This phenomenon is known as the Venturi effect. The 

higher velocity translates into lower pressure by Bernoulli’s principle. Thus, 

measuring the differential pressure on either side of the constriction provides a 

measure of the rate of flow through the pipeline. 

For exact flow measurement, the design and dimensions of the constriction are 

critical. In some cases, however, the concern lies more with changes in flow rate, 

indicative of blockages in the piping or overall flow path. This concern is 

important when strainers are used to filter out undesired particles from the fluid, 

especially in generator stator cooling systems. The strainers provide constriction 

to the water flow, resulting in a pressure difference. When the strainers are 

clogged, the pressure difference increases. 

Steam flow can also be measured using the Venturi effect. But in that case, long 

sensing lines are not needed, as pressure immediately on either side of the orifice 

plate or nozzle is measured. 

The Freezing Problem

Since differential pressure measurement requires gauging the difference in 

pressure between two separate sensing lines, if the water in either or both of those 

lines freezes, the measurement will be false. When a sensing line is plugged with 

ice, it cannot convey the intended water pressure to the transmitter location. 

The fact that the water in the sensing lines is not flowing makes freezing all the 

more likely, and emphasizes the need for proper freeze protection methods such as 

insulation and heat tracing. Some sensing lines must run long distances through 

areas exposed to outdoor ambient air, which significantly exacerbates the risk of 

false readings. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

 Frozen Equipment (General): Many other critical systems besides 

sensing lines experienced problems from the low temperatures. These 

included emissions systems, feedwater systems, control air systems, 

lubricating oil systems, and the like. Emissions systems sometimes rely on 

water, which is susceptible to freezing. Control air systems contain 

moisture-laden air; if the moisture is not removed, freezing can occur. 

Changes in the viscosity and properties of lubricants that are not kept at 

specified temperatures can adversely affect the operation of equipment. 

 

 Two units at one plant were derated when the NOx water storage 

tank lines froze. 

 At a City of Garland unit, 78 MW were lost from a draft fan failure, 

which was caused by frozen damper controls and a resulting low air 

flow trip. 

 A wind facility lost six units when lubricating oil fell below the 

minimum operating temperature and automatically tripped the units. 

 Frozen Water Lines: The condensate and boiler feedwater systems of 

steam-cycle generating units (coal, conventional gas, and combined cycle) 

utilize water from the condenser and add heat (through a series of feedwater 

heaters) and pressure (through condensate and boiler feedwater pumps) to 

increase cycle efficiency before the water enters the boilers. Piping, 

pressure vessels, and valves contained in these systems are susceptible to 

freezing, absent freeze protection measures. (This is especially true if the 

unit is offline at the onset of freezing temperatures.) 

. 

One facility lost a 160 MW unit when air compressor drains froze. 

Another unit was shut down because of high boiler “superheat” 

temperature when its superheat spray lines froze. 

 Frozen Valves: The operation of valves can become sluggish when 

exposed to severe cold weather. Depending on the particular application of 

these components, sluggish valves can cause instability in the boiler or 

turbine controls, which can eventually lead to a unit trip. 

Kiowa Power Partners attempted to free up a frozen valve and, in the 

process, shut the valve completely, cutting off steam to the turbine 

and tripping 307 MW of capacity. 

Another generating unit experienced a frozen valve on a fuel gas 

temperature controller, which caused gas temperatures to become 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

erratic. A bypass valve on another unit’s fuel gas temperature 

controller froze, preventing the unit from reaching full capacity for 

a period of time. 

 Blade Icing: Blade icing caused problems for wind generators. 

Precipitation and condensation during cold weather can cause layers of ice 

to form on turbine blades, causing potential balancing, bearing, and other 

equipment problems (as well as safety problems resulting from “ice 

throws”). 

 Turkey Track Wind Energy lost 27 turbines and 40.5 MW of 

capacity during the event due to blade icing problems. 

 Low Temperature Limits: Wind turbines are typically designed to operate 

within a designated range of temperatures, and have an automatic shutdown 

feature to protect their components if the range is exceeded. Although 

manufacturers offer a “cold weather package”210 that allows a turbine to 

continue operating in colder temperatures, it does not appear that the 

package is used in the Southwest. 

 McAdoo Wind Energy suffered outages of 90 of its 100 turbines 

when the turbines, designed to shut down when the temperature 

drops below five degrees, performed as expected. Although 

McAdoo’s turbines restarted automatically when the temperatures 

rose above the shutdown point, other units, such as Bull Creek 

Wind, did not come back online as temperatures rose. 

 Transmission Loss: Generators can also be affected by external outages of 

transmission facilities. 

 At one generating plant, cold grease in a breaker appears to have 

caused slow clearing of the breaker, tripping six units. 

 210 Press Release, General Electric, GE Energy’s 2.5xl Wind Turbine Now Offers 

Extreme Cold Weather Capabilities for Challenging Applications in North America and Europe 

(Sept. 21, 2009), available at http://www.genewscenter.com/content/Detail.aspx? 

ReleaseID=8415& NewsAreaID=2. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

ERCOT Non-Weather-Related Outages and Derates

 While the majority of the ERCOT generator failures during the February 

event were weather-related, other causes also played a part. This is not surprising, 

as on any given day generating units can and do experience problems. To 

determine whether the amount of non-weather-related failures during the February 

cold weather event was typical, the task force reviewed ERCOT’s 2010 daily 

forced outage data. During that year, forced outages ranged from 900 MW to 

6300 MW per day, averaging 3200 MW per day or 16,000 MW for a five-day 

period. Therefore, the task force concluded that the 14,386 MW of non-weatherrelated failures experienced by ERCOT generators between February 1 and 

February 5, 2011 were comparable to what might be expected over a normal fiveday period. 

The causes (other than fuel supply) of the non-weather-related outages 

between February 1 and February 5 included difficulties with mechanical 

equipment, control equipment, operator error, emissions limitations, and fuel 

switching failures. The task force identified six general categories of nonweather-related causes of generator trips, derates, and failed starts over these five 

days: 

Cause No. of Units Lost MW Lost 

Mechanical Failure 37 7588 

Control System Issues 28 3624 

Fuel Switching 12 909 

Operator Error 9 980 

Emissions 3 358 

Miscellaneous 11 927 

Total Non-Weather-Related 100 14,386 

Representative problems within these categories are discussed below. 

 Mechanical Failure: A number of generators experienced mechanical 

equipment problems that were not related to the cold weather. For instance, 

several had combustion turbines trip due to high exhaust temperature 

spreads, which is an indicator of internal problems with the combustion 

turbine (or with the thermocouple211). Another common combustion 

turbine problem encountered during the event was high blade path 

 211 Thermocouples are used to measure process temperatures and consist of two dissimilar 

metal wires soldered together at the tip, which produce an electrical current in response to 

temperature changes. Thermocouples can fall out of calibration over time or fail suddenly due to 

broken wires or damaged lead wire insulation. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

spread,212 which resulted in several more trips. Other trips, derates, and 

failures to start resulted from such problems as boiler and heat recovery 

steam generator leaks, plugged suction strainers on condensate pumps, 

improper boiler feed water pump oil pressure, gas pressure regulation 

issues (which were mainly resolved by the pipelines), and an assortment of 

gas turbine tuning issues. 

 Greens Bayou CT 81 (54 MW) tripped due to a high combustible 

gas alarm, which was triggered by a leak in a coupling. 

 San Miguel Unit 1 (395 MW) tripped due to a waterwall tube leak. 

 Control System Issues: A prominent problem with control equipment 

appears to have been failed thermocouples. Control parameters, logic, and 

dynamics probes also resulted in several trips. Other problems included, but 

were not limited to, malfunctioning flame detectors and sheared air register 

pins,213 loose wiring, a failed speed sensor, broken control linkages and 

faulty flow meter switches. 

 Deer Park CT 1 (195.5 MW) tripped due to a blade path temperature 

spread resulting from a failed sensor in the plant’s distribution 

control system logic. 

 One facility experienced problems with its 46 relay,214 which caused 

an outage. Another unit had a false indication of a ground fault on a 

generator rotor, which prompted the operator to take the unit offline. 

 Fuel Switching: ERCOT has approximately 90 generating units with fuel 

switching capabilities, permitting them to switch from natural gas to an 

alternate fuel when natural gas is in short supply. (Generators may wish to 

switch fuel for other reasons as well, such as economics.) During the 

February event, 20 units attempted to switch from natural gas to their 

 212 Blade path spread is a measurement, utilizing thermocouples, designed to identify 

turbine exhaust temperatures. A temperature spread beyond allowable limits will initiate an 

alarm or a trip. However, the alarm or trip can also be triggered by a defective thermocouple, 

rather than by actual fuel problems or air cooling problems. 

213 The failed flame detectors and air register pins caused burners inside the boiler to 

malfunction. 

214 A 46 relay (negative sequence relay) is used to detect unbalanced load on a generator 

that may cause excessive rotor heating and result in significant damage to the generator. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

alternate fuel, with 15 units managing the switch successfully. The other 

units encountered various failures in their switching equipment. Derates 

also resulted from fuel switching. 

 The Decker CT 2 (54 MW) tripped when attempting to burn fuel oil. 

 The GEUS steam plant was derated by 5 MW due to operating on 

fuel oil. 

 Operator Error: Several generators experienced minor problems 

associated with operator error. In some cases, the problems arose when 

operators switched control systems from automatic to manual mode. In 

other cases, generators tripped as the result of improper maintenance 

procedures. 

 A flameout of the boiler at one unit forced the burner valves to close 

but left the main gas trip valve open. In attempting to close the trip 

switch before restarting the unit, an operator selected the trip switch 

for the second unit, putting the second unit out of service. 

 

 An operator noticed that the fuel forwarding system for two units 

were operating in the incorrect mode. In attempting to rectify this 

situation, the operator correctly selected the automatic mode for one 

pump (it was operating in manual), but mistakenly selected 

“lagging” instead of “leading.” This caused both units to give low 

pressure alarms and trip offline. 

 Hydraulic oil heaters at a generating unit had been left unplugged 

since the summer of 2009 (they had been unplugged at that time to 

avoid overheating). During the February event, trips resulted from 

low hydraulic oil temperatures. 

 Emissions: At approximately 12:00 PM on February 2, ERCOT informed 

generators that the Texas Commission on Environmental Quality (TCEQ) 

was temporarily waiving air permit requirements that were preventing some 

generators from operating at full capacity during the emergency. (Although 

ERCOT characterized the action as a waiver, the TCEQ actually stated that 

it was exercising enforcement discretion.) This decision had little effect on 

the situation within ERCOT, as it was not announced until after half of the 

shed load had been restored. 

 Prior to issuance of the notice, Calpine’s Clear Lake facility, which 

consists of three combustion turbines and two heat recovery steam 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

generators, was forced to manually shut down its GT102 and GT104 

turbines in order to avoid exceeding NOx Limits. 

 On February 3, another Calpine unit, Freestone Unit GT4, was 

derated so as not to exceed its NOx permit limits. 

 Miscellaneous: A variety of other problems was also experienced, such as 

the following: 

 Switchyard Equipment Problems: Some generators encountered 

switchyard problems that led to units failing during the event. One 

entity was unable to start certain units because a standby transformer 

was not energized. 

 

 Low Frequency Related Issues: Two facilities reported frequencyrelated issues as causes for their units tripping. One facility’s three 

generators tripped as a result of a low frequency turbine protection 

relay operating improperly. At another facility, the decline in 

frequency during the event caused the turbine control system to 

initiate an increase in fuel pressure to increase turbine speed, but it 

overshot its set point. 

ERCOT Gas Supply Outages and Derates 

Fuel supply problems did not significantly contribute to the amount of 

unavailable generating capacity in ERCOT during the first week in February. The 

outages and derates from inadequate fuel supply totaled 1282 MW from February 

1 through February 5. (For comparison, the overall net generating capacity 

reduction in ERCOT peaked at 14,702 MW on the morning of February 2.) The 

fuel supply problems also did not occur all at the same time. The following table 

summarizes generation capacity reductions in ERCOT due to fuel curtailment and 

fuel quality problems. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Generator Trip Time Unit Gen 

MW 

MW 

Reduction 

Pipeline (s) 

Bosque 

Power 

Company 

2/2 9:26 AM Bosque 

Power: 

Unit 1, 

Unit 2, 

Unit 3, and 

Unit 4 

597 154 Enterprise Texas Pipeline, 

Markwest Lateral 

Calpine 2/4 7:55 AM Corpus 

Christi: 

GT1, 

GT2, and 

ST1 

516 174 South Cross CCNG 

Transmission 

City of 

Austin 

(Austin 

Energy) 

2/2 7:30 AM Decker : 

Unit 2 

450 100 Enterprise Texas Pipeline / 

Atmos Texas Pipeline 

Power 

Resources

2/2 5:14 PM Cal 

Energy: 

Unit 1 

212 7 ONEOK WesTex Transmission 

Luminant 2/1 10:00 AM Lake 

Hubbard: 

Unit 1 

441 174 Atmos-Texas Pipeline 

GEUS 2/1 9:00AM GEUS 

Steam 

Plant 

112 112 Atmos-Texas Pipeline 

Exelon 2/1 7:30 PM 

2/2 11:00 AM 

2/2 3:00 PM 

2/2 6:00 PM 

Mountain 

Creek: 

Unit 6, 

Unit 7, and 

Unit 8 

808 476 

396 

476 

396 

Atmos-Texas Pipeline and 

Energy Transfer Fuel 

Frontera 

Generation 

2/2 8:16 AM Frontera: 

Unit 1, 

Unit 2, and 

Unit 3 

485 85 Kinder Morgan Tejas 

 Bosque Power Company: MarkWest PNG Utility operates an intrastate, 

30-mile, 18 inch diameter lateral in Hill, Johnson, and Bosque Counties, 

Texas. The lateral has an operating pressure of approximately 700 psi, and 

has no compressor stations. Gas is transported from Enterprise Texas 

Pipeline, a second intrastate pipeline, to the Bosque County Power Plant, 

the only electric generation facility served by the pipeline. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Bosque Power Company’s QSE, EDF Trading North America (EDF), 

manages all transportation and gas supply purchases, nominations, and 

scheduling, including capacity on the Enterprise Texas Pipeline. EDF has 

only interruptible capacity on the Enterprise Texas Pipeline. The majority 

of its receipt points are in Waha and West Texas. 

The power plant’s units are programmed to automatically shut down if 

pipeline pressure drops below a certain point. On February 2, gas pressure 

steadily dropped to near the automatic shut down point. To mitigate the 

effects of lower gas pressures, the plant began reducing energy output on 

all four of its units. 

MarkWest informed the task force that there are no compressors on their 

pipeline, and therefore the declining pressure was likely a gas supply issue. 

The pipeline had no capacity constraints. 

 Calpine: The Calpine Corpus Christi facility is supported by one pipeline 

system, the Southcross CCNG Transmission pipeline (Southcross). Calpine 

Energy Services (CES), a subsidiary of Calpine Corporation, is an energy 

marketer that arranges for natural gas supplies for generation facilities 

owned by Calpine, including the Corpus Christi facility. 

On February 3 and 4, CES delivered gas into Southcross at four separate 

locations. However, at approximately 7:55 AM on February 4, the Calpine 

units tripped off line due to declining pipeline pressure on the Southcross 

system. The pressure on Southcross fell below the minimum delivery 

pressure obligation of 560 psig that is stated in both of CES’s firm and 

interruptible agreements. Southcross reported that the low pressures on its 

system were due to supply freeze-offs that reduced expected deliveries into 

its system. 

Calpine was able to restart one of its units in less than one hour and run the 

facility at a derated level. Later in the day on February 4, once Southcross 

restored its line pack pressures, Calpine successfully brought all units back 

online. 

 City of Austin (Austin Energy): The city of Austin has firm capacity on 

the Enterprise Texas Pipeline and is connected to the Atmos Pipeline-Texas 

(Atmos), both intrastate pipelines. Under the terms of the city’s agreement 

with Atmos, its capacity rights are reduced when freezing weather is 

forecasted, pursuant to a specific formula in the contract. Most of the gas 

supply for the transportation is from Waha. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

The plant did not experience curtailments. However, given the limitations 

on Atmos, usage was limited on February 2. Austin Energy exceeded its 

contractual hourly take on Enterprise Texas Pipeline and was requested by 

Enterprise to reduce flows to the hourly take (this is referred to as “back on 

rate”). This reduction caused a 100 MW derate of the Decker unit. 

 Power Resources: Power Resources’ Cal Energy Plant ramped down one 

hour early due to low gas pressure on its supplying pipeline, ONEOK 

WesTex, an intrastate pipeline located primarily in west Texas and the 

Texas panhandle. 

ONEOK WesTex states that it did not interrupt service but did experience 

operational difficulties and supply reductions. Beginning on February 1, 

increased gas usage by towns and power plants reduced the pipeline 

pressure, and several interconnecting gas processing plants also 

experienced supply difficulties. Normal operating pressures were restored 

by the afternoon of February 2. 

 Luminant and GEUS: These plants are connected to the Atmos system, 

which traverses the Fort Worth, Permian, and East Texas Basins, all of 

which experienced supply losses due to freeze-offs. 

Transportation for power generation feeding off Atmos is only offered as 

an interruptible service, and is subject to electric generation restrictions, 

called “Tier 3 restrictions.” Atmos instituted Tier 3 restrictions beginning 

at 9:00 AM on February 1, restricting gas flow to zero for the GEUS steam 

units and for Luminant’s Lake Hubbard generating station. On February 2, 

increased demand resulted in continued loss of line pack and declining 

pressures at citygate points in Dallas-Fort Worth. Additionally, suppliers 

experienced well freeze-offs and equipment problems. 

On the morning of February 2, ERCOT initiated rolling blackouts to 

maintain the grid. The TRC contacted Atmos at approximately 10:00 AM 

to ask if additional volumes could be delivered to the Lake Ray Hubbard 

Electric Generating Station to assist with electric grid issues. Atmos 

explained to the TRC that such action would result in the loss of service to 

firm residential and commercial customers served by LDCs located to the 

north of the electric generation station on the pipeline system, and that 

therefore such deliveries could not be made to an interruptible customer. 

 Exelon: Exelon has a firm gas transportation contract with Energy 

Transfer Fuel (ET Fuel) for the Handley Generating Station and an 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

interruptible gas transportation contract with Atmos for Handley 

Generating Station and Mountain Creek Station. Atmos implemented a 

Tier 3 restriction during the extreme weather event, which limited hourly 

flow to both the Handley and Mountain Creek stations. 

The fuel curtailments at Handley did not affect operations until Unit 3 was 

called on the evening of February 2. Gas supply during the day was 

enough to allow Units 4 and 5 to run at full load. When Unit 3 was brought 

on line, it fuel switched Unit 4 to run partially on oil to allow Units 3 and 5 

to increase output. Mountain Creek Units 6 and 7 ran at minimum load due 

to fuel restrictions. Mountain Creek Unit 8 ran at full load (but did have 

other non-gas related derates that affected output). 

 Frontera Generation: The Frontera Generation plant is on the Kinder 

Morgan network of pipelines (collectively, KM Texas Pipes). The KM 

Texas Pipes receive natural gas from producing fields in south Texas, east 

Texas, the Gulf Coast, the Gulf of Mexico, and the Permian Basin. They 

also own or control gas storage capacity. 

Frontera has firm transportation service with deferred account service. 

“Deferred account service” is a balancing service that enables a shipper to 

acquire supply during low demand and deliver it to the KM Texas Pipes for 

future redelivery during peak demand, subject to contractual limits on 

hourly, daily, and total quantities. 

During the morning of February 2, the KM Texas Pipes contacted those 

customers that were taking more than their firm contractual rights, 

including both of the Frontera plants, requesting they stay within their 

contractual rights because pipeline pressures were falling and putting all 

firm services at risk. Later that day, ERCOT, along with the TRC, advised 

the KM Texas Pipes that ERCOT had declared an emergency condition. 

ERCOT then advised the KM Texas Pipes that the power grid in the Rio 

Grande Valley was in a critical state. ERCOT and the TRC requested the 

KM Texas Pipes to allow the Frontera electric generating plant to pull 

supplies in excess of their firm contractual rights. The KM Texas Pipes 

complied with this request. 

Generation Outages in Salt River Project

 The SRP balancing authority suffered several generator outages during the 

cold weather event, which severely affected its ability to serve load. On February 

1 and 2, SRP lost a total of seven units. The failures of three of them were related 

to weather. On February 1, SRP lost Unit 1 at its Navajo Generating Station due 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

to a frozen transmitter sensing line, reducing generation capacity by 330 MW. On 

February 2, SRP lost additional generation due to weather-related problems: it lost 

75 MW, its 10 percent share, from Unit 4 at Four Corners Generating Station 

(operated by Arizona Public Service Company), which failed due to a frozen 

sensing line that served the throttle pressure transmitter; and it lost Unit 2 at 

Navajo Generation Station, which tripped due to frozen waterwall pressure 

transmitter sensing lines. 

SRP also suffered generation losses from the trips of four units on 

February 2, due to non-weather related issues: Coronado Generating Station Unit 

2 , which experienced a mechanical problem with a coal pulverizer, losing peak 

load of 389 MW; the combustion turbine and the steam turbine units at Santan 

Generation Station Unit 6, which suffered an internal mechanical failure on the 

heat recovery steam generator and an accompanying runback of the combustion 

turbine; Springerville Unit 3 (operated by Tucson Electric Power), which 

developed high furnace pressure, causing a loss to SRP of its 75 MW share of the 

plant’s 400 MW. 

Generation Outages in El Paso Electric

 The EPE balancing authority shed approximately 623 MW of firm load 

over the course of the February event, due to the loss of 646 MW of local 

generation. Unlike SRP, almost all of EPE’s’s outages were due to the cold 

weather. 

 On February 1, EPE lost its Newman Unit 3 because of frozen 

condensation on the fresh air inlet, and lost Rio Grande Unit 6 because of a frozen 

gas transmitter. The loss of these units resulted in a 152 MW reduction of 

capacity.215

 On February 2, EPE lost 495 MW of capacity from its Newman and Rio 

Grande plants. Newman Gas Turbines 1 and 2 at Newman Unit 4, each with a 

capacity of 73 MW, tripped due to faulty drum level readings resulting from the 

cold weather. Gas Turbines 3 and 4 at Newman Unit 5, each with a 70 MW 

capacity, also tripped due to frozen drum level instrumentation sensing lines. 

Newman Unit 4 Steam Turbine, a 64 MW unit, tripped on February 2 due to 

frozen instrumentation associated with the condenser vacuum. Finally, EPE lost 

Rio Grande Unit 8, a 145 MW unit, due to frozen transmitter sensing lines that 

caused a low gas pressure signal. 

 215 The Newman plant is not enclosed; the Rio Grande plant is enclosed. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

El Paso attempted to bring its units back online on February 3 and February 

4, with limited success. Newman Unit 4’s GTs were restarted, only to trip on 

subsequent occasions for similar weather-related issues. (Luna and Afton, PNM 

remote generating facilities from which EPE was receiving energy, also 

experienced outages on February 3 and February 4.) 

 During the event, two EPE units, Newman Unit 1 and Rio Grande Unit 7, 

were offline and EPE tried to bring them online to assist with the shortages. Both 

units, however, failed to start due to frozen components and, in the case of 

Newman Unit 1, frozen drum drain lines and transmitter. 

B. Natural Gas

 Most of the natural gas supply problems experienced in the Southwest 

during the cold weather event were caused by freeze-offs, principally at the 

wellhead or, to a lesser degree, at nearby processing plants. Other equipment 

failures also played a role, as did the rolling blackouts and customer curtailments 

in the ERCOT region.

In order to analyze the causes of the supply shortfalls, the task force 

reviewed daily shortfalls at receipt points on pipelines. Most of these receipt 

points were at processing plants. The following table summarizes the information 

received from 13 processing companies, which overwhelmingly pointed to 

upstream supply outages as the major cause of the reduced volumes. (The second 

column is the maximum estimated production shortfall by basin; the third column 

is the percentage of shortfall of the processing plants that provided information; 

the final column lists the causes of the shortfalls.) 

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Processing Plant Outages Relative to Daily Production Shortfalls

BASIN MAXIMUM 

DAILY 

PRODUCTION 

OUTAGE 

PROCESSING 

RESPONSES AS 

A % OF THE 

DAILY OUTAGE 

CAUSES 

Permian 1.31 Bcf on Feb 4 0.44 Bcf (34%) 85% Upstream Supply 

Freeze-offs, 15% 

Mechanical/Electricity 

Outages 

San Juan .43 Bcf on Feb 2 

and Feb 3 

0.21 Bcf (52%) Upstream Supply Freezeoffs, Minimal Amount 

due to Mechanical 

Fort Worth 1.63 Bcf on Feb 6 0.17 (11%) Upstream Supply Freezeoffs, Minimal Amount 

due to Mechanical 

East Texas .72 Bcf on Feb 3 

and Feb 5 

NA NA 

Gulf Coast .65 Bcf on Feb 4 NA NA 

The task force further explored these upstream production outages by 

surveying 15 of the larger producers in the San Juan, Permian, Fort Worth, East 

Texas, and Gulf Coast Basins. These producers accounted for almost 40 percent 

of the total production for the five basins, with the highest percentages from the 

Fort Worth, San Juan, and Permian Basins. 

 For February 1 to February 5, an estimated 14.8 Bcf of production was lost 

from these five basins due to weather-related reasons. Of that amount, the 

surveyed producers lost 7.1 Bcf, equal to 48 percent of the total. 

These production losses occurred for a variety of reasons. Some of the most 

common occurrences reported to the task force included: 

 Freeze-offs (in some circumstances winterization was only designed for 

temperatures in the 20s), 

 Icy roads that hampered logistics such as hauling away water produced 

by treatment equipment, and 

 Rolling blackouts and customer curtailments. 

 Rolling blackouts were a problem particularly in the Fort Worth Basin, 

where they caused outages of compressors on gathering lines. In the Permian 

Basin, deployment of Load Resources by ERCOT during the event caused 

disruption to electric pumping units. According to information received from the 

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surveyed producers, 27 percent of the outages in the Fort Worth Basin were due to 

the rolling blackouts, and 29 percent of the outages in the Permian Basin were due 

to rolling blackouts or the curtailment of interruptible load. 

The following table itemizes the reasons stated by these 15 producers for 

the supply shortfalls (the check marks indicate how many separate producers 

submitted information for each category): 

Permian San Juan Fort Worth East Texas Texas 

Gulf 

Rolling Black 

Outs/ 

Curtailed 

Load 

 

Icy Roads    

Freezing of 

Compressors 

   

Freezing 

Meters 

 

Wellhead 

Freeze-offs 

    

Processing 

Facility Shutin 

   

Ice Plugs in 

Gathering 

Lines 



Frozen Salt 

Water 

Disposal 

Facilities 



A basin-by-basin description of the gas production declines, and the resulting 

reduction in flows, follows.216 

Permian Basin

 The Permian Basin suffered production losses from February 1 through 

February 5 of 3.98 Bcf, with a maximum daily decline of 1.31 Bcf on February 4. 

The reasons provided for these declines are based on information received from 

 216 The information is drawn from materials provided to the task force by producers and 

processing plants. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

processors representing 34 percent of the maximum daily outage and producers 

representing 28 percent of the cumulative losses. 

Reduced Flows at Processing Plant Pipeline Receipt Points

The task force reviewed receipt points on El Paso, Transwestern, Northern 

Natural Gas Company, and Enterprise Texas pipelines that had reductions 

exceeding 20,000 MMBtus per day, and thirteen processing plant points that had 

reductions of approximately 0.6 Bcf per day. 

The receipt points on the El Paso pipeline with flow declines exceeding 

20,000 MMBtus per day from February 1 to February 3 are all processing 

plant/gathering locations. They include Enterprise Waha (reduction of 120,681 

MMBtus per day); Southern Union Jal#3 (reduction of 35,966 MMBtus per day); 

DCP Midstream GPS Eunice, reduction of 32,055 MMBtus per day; DCP 

Midstream Goldsmith Plant (reduction of 29,562 MMBtus per day); Southern 

Union Keystone (reduction of 28,515 MMBtus per day); Versado Gas Processors 

Texaco Eunice (reduction of 26,407 MMBtus per day); DCP Midstream Pegasus 

(reduction of 23,475 MMBtus per day); and Versado Gas Processors, Warren 

Monument (reduction of 21,460 MMBtus per day). 

Transwestern’s supply shortfalls in the Permian Basin were modest, relative 

to El Paso’s, and were most significant at the Frontier Maljamar Gas Plant 

(reduction of 33,000 MMBtus per day) and at the Agave producer gathering 

connection (reduction of 44,000 MMBtu per day). Northern Natural processing 

plant receipt points with large reductions were the Atlas Midkiff Plant (reduction 

of 63,997 MMBtus per day) and the DCP Linam Ranch Plant (reductions of 106, 

406 MMBtus per day). Finally, on Enterprise Texas Pipeline, the Crockett Gas 

Plant had a production shortfall of 34,376 MMBtus per day.217

Explanations varied for the reductions from the processing plants located in 

the Permian Basin.218 The largest supply reduction to El Paso was the Enterprise 

Waha treating plant, which has a capacity of 280 MMcf per day. Enterprise 

reported that volumes delivered to the Waha Treating Plant decreased from 120 

MMcf per day to approximately 40 MMcf per day, due to gas supply freeze-offs 

on February 2 and February 3. The plant’s GE turbine then went down on 

 217 Staff’s analysis based on supporting data, display reports and data warehouse on file 

with Bentek (unpublished); See also Market Alert: Deep Freeze Disrupts U.S. Gas, Power, 

Processing, Bentek Energy LLC, Feb. 8, 2011, at 2-6. 

218 The task force received materials from a number of processing plants located in the 

basin. The material cited represents a sampling of data from those materials. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

February 3, due to high discharge pressure when El Paso closed its valve at the 

plant tailgate (because of a high dew point in the gas stream). 

On February 2, DCP's Linam Ranch plant in east New Mexico experienced 

freezing air ducts, resulting in a modest reduction to El Paso of 4,865 MMBtu per 

day from February 1 to February 3 (the reduction is 24,092 when measured from 

January 31). The plant then experienced a delay returning to service because of 

gas supply shortages from well freeze-offs, resulting in a lack of gas to restart the 

plant. The plant returned to normal operations on February 6 and supply returned 

to normal levels on February 7. Reductions in volume at three other DCP plants, 

Goldsmith, Pegasus, and Eunice, were the result of supply shortages from 

wellhead freeze-offs. Goldsmith and Pegasus experienced rolling blackouts that 

resulted in only brief outages, with gas being at the time either processed at the 

plants or delivered directly into pipelines. 

Four DCP Texas processing plants were impacted by the rolling blackouts on 

February 2, but only one of them had resulting operational problems. The power 

outage caused the cooling water used for compression at the Roberts Ranch Plant 

in west Texas to freeze, leading to a plant shut down. (The plant was back in 

service on February 5.) The remaining plants did not experience any operational 

issues from the power outages. When the brief power outages occurred, the 

upstream gas bypassed the plants and was delivered without being processed. 

Southern Union operates the Keystone and Jal #3 plants that together flowed 

reduced volumes of 64,481 MMBtu per day to El Paso. Southern Union reported 

that it experienced major property damage and significant financial losses due to 

freezing and failure of wells, pipes, and other facilities. The weather event 

ultimately resulted in the cessation of operations at many plants and field facilities, 

with corresponding reductions in deliveries to downstream pipelines. Some of 

Southern Union’s issues were a direct result of rolling power outages at the 

Keystone facility at 7:25 AM and 9:05 AM on February 2, lasting 34 and 30 

minutes, respectively. 

Producer Declines in the Permian Basin

Producers representing a customary production level of approximately 0.75 

Bcf per day219 (approximately 30 percent of total basin production), reported 

production losses for the period February 1 through February 5 of 1.1 Bcf, 

 219 This number represents the producers’ usual production level, absent reductions 

experienced during the event. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

estimated to be approximately 28 percent of the total basin production losses for 

the five days. The losses were attributed to the following: 

 Power disruptions to electric motors on pumping units (29 percent of 

the total losses, or 0.32 Bcf), 

 Icy roads, 

 Ice plugs in gathering lines, 

 Freeze-offs, and 

 Downtime at processing plant. 

 Occidental Energy Marketing reports that on February 2, because of its 

status as a Load Resource on ERCOT’s system, electric service to its production 

facilities were interrupted when ERCOT deployed it as a Load Resource. This 

interruption resulted in significant production losses. Power began to be restored 

approximately 1.5 hours after the disruption occurred. 

 

 ConocoPhillips Company reports that a significant percentage of its 

production losses in the Permian Basin were attributable to rolling blackouts that 

knocked out processing plants and pumps and lifts. The majority of its Permian 

Basin production comes from oil wells that rely on electric pumps and lifts to 

maintain oil flow. When the pumps failed, the natural reservoir pressures were 

unable to sustain flow, the oil congealed, and the wells and flow lines froze. 

San Juan Basin

 The San Juan Basin suffered production losses from February 1 through 

February 5 of 1.3 Bcf, with a maximum daily decline of 0.43 Bcf on February 3 

and February 4. The reasons provided for these declines are based on information 

received from processors representing 52 percent of the maximum daily outage 

and producers representing 71 percent of the cumulative losses. 

Reduced Flows at Processing Plant Pipeline Receipt Points

The task force reviewed receipt points on El Paso and Transwestern that had 

reductions exceeding 20,000 MMBtus per day, and eight processing plant receipt 

points with a reduction of approximately 0.35 Bcf per day (when netted against 

increased flows elsewhere). 

Receipt points off of El Paso that had flow reductions exceeding 20,000 

MMBtus per day are the BP Florida River Plant, with a reduction of 155,691 

MMBtus per day, and two Williams Field Services processing plant/gathering 

locations; Milagro, with a reduction of 66,764 MMBtus per day, and #37, with a 

reduction of 24,047 MMBtus per day. Transwestern’s most significant supply 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

shortfalls in the San Juan Basin for February 1 through February 3 were the 

William FS Kutz Plant, with reductions of 36,000 MMBtus per day, the Red Cedar 

Arkansas Loop gathering facility, with a reduction of 33,000 MMBtus per day, the 

Valverde Gas Plant, with a reduction of 48,000 MMBtus per day, and the 

Enterprise Chaco Plant, with a reduction of 87,000 MMBtus per day. These 

reductions were partially offset by increased flow of 100,000 MMBtus per day 

from the Williams FS Ignacio Plant. 

Williams Fields Services reported that they had no operational problems, and 

the reduced volumes at Milagro and Kutz were due to upstream production shutins. With regard to the Chaco Plant, Enterprise reported it was operating at less 

than full capacity during the first week of February primarily because: (i) gas 

supplies were limited, (ii) ConocoPhillips moved approximately 100 MMcfd220

from Chaco to their own San Juan processing plant on February 1, and (iii) winter 

production shut-ins occurred. In addition, the plant tripped on February 2 due to a 

hazardous gas supply alarm, and Enterprise’s attempts to restart it were impeded 

by the combination of the lower volumes being nominated by producers and the 

cold weather experienced at the time. 

Producer Declines in the San Juan Basin

Producers representing a customary production level of 2.0 Bcf per day 

(approximately 67 percent of total basin production), reported production losses 

for February 1 through February 5 of 0.9 Bcf, estimated to be approximately 71 

percent of the total basin production losses for the five days. 

None of the producers cited power outages as a cause of production losses. 

The losses were attributed to the following: 

 Problems with compressor units, 

 Freezing of wellhead meters, 

 Cold weather, Freeze-offs, 

 Icy roads, and 

 Downtime at a processing plant. 

Fort Worth Basin

 The Fort Worth Basin suffered production losses from February 1 through 

February 5 of 4.7 Bcf and a maximum daily decline of 1.63 Bcf on February 6. 

The reasons provided for these declines are based on information received from 

 220 MMcfd is a million cubic feet per day. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

processors representing 11 percent of the maximum daily outage and producers 

representing 80 percent of the cumulative losses. 

Reduced Flows at Processing Plant Pipeline Receipt Points

The Fort Worth Basin experienced supply reductions of almost 1.3 Bcf per 

day. Energy Transfer Fuel (ET Fuel) and Crosstex North Texas Pipeline 

(Crosstex) both receive gas from the Fort Worth Basin, and experienced reduced 

receipts. 

ET Fuel had reduced receipts of 0.35 Bcf per day from January 31 through 

February 4. The largest reductions on the system occurred at the following 

receipt points: Chesapeake Energy production, with a reduction of 71,314 

MMBtus per day; EOG Resources production, 127,418 MMBtus per day; 

Quicksilver Gathering, reduction of 69,675 MMBtus per day; and an ET Fuel 

processing plant, reduction of 61,668 MMBtu per day.221 

Crosstex had a flow reduction estimated at 0.14 Bcf per day. The reduced 

volumes were due largely to the weather-related shut-down of the Silver Creek 

processing plant. Primarily due to freeze-offs, production at the plant declined by 

approximately 110,000 MMBtus per day from a normal flow rate of 185,000 

MMBtus per day, to a five day average of 75,000 MMBtus per day on the outlet. 

Atmos reported that intermittent supply reductions from nominated volumes 

were 0.13-0.17 Bcf per day. 

The Energy Transfer Corporation Texas (ETC Texas) Godley area plant in 

north Texas experienced weather related difficulties on February 1 when one of its 

amine systems froze. ETC Texas was able to flow amine again on February 5. 

From February 1 through February 5, the inlet volume of the Godley Processing 

Plant decreased by 100 MMcfd, due to the loss of third party production from 

freeze-offs. 

Producer Declines in the Fort Worth Basin

Producers representing a customary production level of 3.3 Bcf per day 

(approximately 69 percent of total basin production), reported production losses 

from February 1 through February 5 of 3.8 Bcf, estimated to be approximately 80 

 221 Staff’s analysis based on supporting data, display reports and data warehouse on file 

with Bentek (unpublished); pipeline scheduled volumes. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

percent of the total basin production losses for the five days. The losses were 

attributed to the following: 

 Rolling blackouts primarily affecting compressors on gathering lines 

(27 percent, or at least 1.0 Bcf), 

 Icy roads, and 

 Freeze-offs. 

One large producer in the basin reported production losses for the period 

February 1 through February 5 as a result of electrical compression being shut 

down on a gathering system in the Dallas/Ft. Worth area. After power was 

restored, production was slow to return to standard rates. It therefore appears 

likely that a significant percentage of the lost production even after February 2 

was due to the loss of power during the rolling blackouts. 

East Texas

 Producers representing a customary production level of 1.2 Bcf per day 

(approximately 24 percent of total basin production), reported production losses 

from February 1 through February 5 of 0.9 Bcf, estimated to be approximately 33 

percent of the total basin production losses for the five days. The losses were 

attributed to the following: 

 Equipment freeze-offs, 

 Icy roads, 

 Downtime at processing plants, 

 Freezing of equipment, and 

 Wellhead freeze-offs. 

Gulf Coast

 Producers representing customary production level of 0.7 Bcf per day from 

February 1 through February 5 (approximately 14 percent of total basin 

production), reported production losses from February 1 through February 5 of 

0.36 Bcf, estimated to be approximately 18 percent of the total basin production 

losses for the five days. The losses were attributed to the following: 

 Compressors freezing, 

 Frozen meters, and 

 Freeze-offs. 

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VII. Prior Cold Weather Events 

 The arctic cold front that descended on the Southwest during the first week 

of February 2011 was indisputably severe. Many cities in Texas and New Mexico 

experienced a 50 degree drop in temperature over an eighteen-hour period. 

Temperatures dropped to the low teens in Texas and below zero in New Mexico. 

Much of north Texas experienced record setting sleet and snow, totaling up to 

seven inches. Exacerbating the effects of the cold temperatures were 

accompanying sustained winds of 30-40 mph, with gusts as high as 51 mph. 

 The 2011 winter weather event has been determined by at least one weather 

service to be a one in 10 year occurrence for some regions of Texas, in terms of 

low temperatures and duration.222 Adding the sustained winds to these low 

temperatures, the resultant convective heat loss (wind speed plus ambient 

temperature) for some generators was estimated to approach a one in 25 year 

severity. Specifically in El Paso, only four prior recorded cold weather events 

approached 2011 in severity, making the storm the worst weather event in the El 

Paso area in 49 years.223 

 This cold weather event was thus unusual in terms of temperature, wind, 

and duration. It was not, however, entirely without precedent. The Southwest 

experienced other cold weather events in 1983, 1989, 2003, 2006, 2008, and 2010. 

In fact, two of those years, 1983 and 1989, had lower temperatures than 2011.224 

But only in l989 were the severity, geographical expanse, and duration of cold 

temperatures and high winds comparable to the February 2011 event. 

 In most of those prior years, utilities avoided any significant outages or 

curtailments. In other years, however, that was not the case. This section 

examines pertinent prior winter weather events to determine if there were lessons 

that could have been learned that might have prevented or ameliorated the service 

disruptions experienced in 2011. 

 222 Key Document, Severe Weather Readiness Workshop Formerly Generation 

Weatherization Workshop, Winter Weather Readiness for Texas Generators, (June 8, 2011), 

http://www.ercot.com/calendar/2011/06/20110608-OTHER (citing Weatherbank, Inc). 

223 Forensic Weather Consultants, LLC, Forensic Weather Investigation of the Weather 

Conditions and Air Temperatures for the Period 1911-2011 (100 Years) in El Paso, Texas, May 

12, 2011, at 1. 

224 Based on data from the National Weather Service. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

A. Electric

 The two prior cold weather events of most significance for the ERCOT 

region occurred in 2003 and 1989; generators experienced weather-related outages 

in both of those years, and rolling blackouts were implemented in 1989. The 

winter of 1989 in particular resembles that of 2011, both in the severity of the 

weather and in loss of load. 

 These two events are described below, beginning with the most recent. 

2003 Event

 On Friday, February 21, 2003, weather forecasts predicted a cold front over 

a large part of Texas. The front moved in earlier and was more severe than 

projected. Statewide, temperatures ranged from 15 to 27 degrees below normal. 

On Monday, February 24, with freezing temperatures as far south as San Antonio, 

the demand for electricity reached 42,029 MW, exceeding ERCOT’s forecast by 

4218 MW, or 11 percent. Owners of gas-fired generating units were short on gas 

and tried to acquire more gas on the intraday market. At the same time, the 

demand for gas increased as a result of heating needs. 

System Events

 By 6:00 PM on February 24, ERCOT issued a Market Alert to increase 

available energy and capacity, and ordered all Reliability Must Run (RMR) units 

raised to maximum output levels. Temperatures remained below freezing in 

Austin and Dallas into Tuesday. By 7:30 AM on Tuesday, ERCOT issued a 

Market Advisory requesting more bids. At the same time, gas companies 

informed customers that they were activating tariff provisions to curtail gas for 

purposes other than “human need.” At the request of three QSEs, the ERCOT 

Chief Operating Officer signed affidavits stating that gas needed for electric 

generation met the qualification of human need. 

 At 9:08 AM on February 25, gas curtailment to a power plant caused three 

units to trip, resulting in the loss of 745 MW of generation. System frequency 

dropped to 59.81 Hz and could not be restored. The ERCOT system control error 

(SCE) was -1,500 MW and increasing. At 12:01 PM, ERCOT declared 

Emergency Electric Curtailment Plan (EECP) Step 1 (EECP was the predecessor 

to today’s Emergency Energy Alerts). Step 1, invoked when reserves fall below 

2300 MW, entailed instructing all available generation to come on line, and 

securing emergency power from neighboring electrical grids through the DC ties. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

The EECP Step 1 succeeded in rebalancing the system within 30 minutes. Step 1 

remained in effect for about seven hours and 30 minutes.225

Gas Supply Problems

 Generator owners reported to the PUCT that they had problems acquiring 

natural gas to run their gas-fired units. Natural gas was suddenly in short supply, 

but equally significant was the fact that the structure of the natural gas market 

limited the way generators were able to respond to fuel shortages in real time. 

Specifically this involved the following: 

 Depleted reserves: The amount of gas in storage declined rapidly starting 

in November 2002, faster than the usual drawdown over the winter period, 

dropping from a five year high to a five year low in just four months. 

 Timeline for gas nominations: Natural gas trading closed for the weekend, 

meaning that fuel for Monday must be procured on Friday, thereby not 

allowing leeway for late changes in the forecast. 

 Fuel shortages and curtailments: Delivery constraints reduced the fuel 

supply to some plants, forcing their electric generating capacities to be 

derated. 

 Lack of on-site storage: Natural gas pipeline companies have the bulk of 

their storage underground, but most of the former vertically integrated 

electric utilities had their own gas storage facilities. Independent power 

producers generally do not have their own gas storage; in a deregulated 

environment, most believe it is uneconomical to maintain it. 

 In 2003, almost three-quarters of the installed electric generating capacity 

was fueled by natural gas. Of those units, 16 percent had dual fuel capability, the 

other fuel being oil. Many units switched from gas to oil on February 24 and 

February 25, but most had to be derated in the process, and some experienced 

operating problems. Of the total of 5500 MW of capacity that was lost due to gas 

curtailments, ERCOT estimated that only 3200 MW was regained on back-up fuel 

oil, yielding a net loss of 2300 MW. 

 225 Prices spiked to $990 per MWh on February 24 and February 25, 2003, as the result of 

hockey stick bidding. For a discussion of this phenomenon, see the earlier section of this report 

entitled “The Event: Load Shed and Curtailments.” 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

PUCT Recommendations

 The Market Oversight Division of the PUCT investigated the 2003 cold 

weather event and issued a number of recommendations.226 Notable among these 

are the following: 

 

 Stricter enforcement of Resource Plan accuracy. 

 Improved weather and electric demand forecasting. 

 Consider providing financial incentives for fuel oil inventories to be 

maintained for use by dual fueled units. 

 Curtailment prioritization – development of a joint curtailment methodology 

for natural gas and electricity production. 

 ERCOT should communicate with both QSEs and Transmission / 

Distribution Service Providers in the future when the power system is under 

stress. 

Consequences

 Following the 2003 generating unit outages, ERCOT revised its Protocols 

to establish Resource Plan performance metrics. These were put in place in 2004. 

The February 2003 event ultimately became an impetus for the establishing of 

Emergency Interruptible Load Service in ERCOT. 

1989 Event

 Beginning on Thursday, December 21, 1989, an arctic air mass descended 

on Texas for three days, delivering some of the coldest temperatures ever recorded 

in the state over a one hundred year period. Temperatures bottomed out at 7 

degrees in Houston, -1 in Dallas, and -7 in Abilene. As a result of the cold 

weather, the demand on the ERCOT power system peaked at 38,300 MW, an 11 

percent increase over the previous winter’s peak and 18 percent above the 

projected peak for the winter of 1989-1990. This load level was equivalent to 93 

percent of the summer peak demand.227

 226 Julie Gauldin, Richard Greffe, David Hurlbut & Danielle Jaussaud, Pub. Util. 

Comm’n of Tex., Market and Reliability Issues Related to the Extreme Weather Event on 

February 24-26, 2003, 29 (May 19, 2003), available at http://puc.state.tx.us/industry/electric/ 

reports/ERCOT_annual_reports/special/weather_event.pdf (PUCT 2003 Report). 

227 Elec. Reliability Council of Texas, ERCOT Emergency Operation: December 21-23, 

1989 (Undated), at 5 (ERCOT Emergency Operation). 

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The high demand, combined with weather-related forced outages of 

generating units and the curtailment of natural gas fuel supplies, resulted in the 

need for ERCOT to shed firm load system-wide for the first time in its history or 

the history of its predecessor.228 Although there were two subsequent years in 

which ERCOT shed load during hot weather spells,229 the 1989 event remained 

the only cold weather-related load shed event until February 2011.230 

 The 1989 event predated deregulation of the electric utility business in 

Texas, which began in 2002. Utility companies were therefore still vertically 

integrated and owned and operated generation, transmission, and distribution in 

their franchise service territories. 

System Events

 On Wednesday, December 20, 1989, a severe cold weather alert was 

declared for north Texas, effective the following morning; by 6:00 PM on 

Thursday, all of ERCOT’s territory had been placed under severe alert. The 

temperature was 21 degrees in Dallas and 41 in Houston at that time. Gas 

curtailments were experienced starting on December 21, and continued for several 

days thereafter. These resulted in a considerable number of generators switching 

to or increasing their mix of fuel oil. 

 

 On Friday, December 22, ERCOT was unable to maintain minimum 

required operating reserve levels, due to record-high loads and a large number of 

generating units being forced offline. The frequency dropped below 59.95 Hz at 

8:30 AM, and ERCOT ordered the start up of all available units. Those local 

control centers experiencing generation deficiencies also shed interruptible loads 

and minimized their own internal loads such as mining operations and station 

 

 228 ERCOT’s predecessor was Texas Interconnected Systems, formed in 1941. Id. at 1. 

229 In May 2003, the loss of two nuclear-powered generating units tripped automatic 

UFLS relays, resulting in the shedding of 1549 MW of firm load; service was restored within 

three hours and 30 minutes. In April 2006, an early season heat wave and the loss of four 

generating units caused ERCOT to shed 1000 MW of firm load via rolling blackouts; service was 

restored within one hour and 45 minutes. 

230 For the Houston area, which was the hardest hit in Texas, it was the first shedding of 

firm load in the history of the Houston Lighting and Power Company, dating back to the 

energizing of its first lighting load in 1882. See Bill Beck, At Your Service: An Illustrated 

History of Houston Lighting & Power Company (Houston Lighting & Power Company, 1st

ed.1990) at 409; see also A Brief history of CenterPoint Energy, 1880-1889, CenterPoint Energy, 

http://www.centerpointenergy.com/about/companyoverview/companyhistory/timeline/23b55aef7

af66210VgnVCM10000026a10d0aRCRD/ (last visited Aug. 3, 2011. 

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lighting. Utilities made public appeals for customers to voluntarily reduce 

consumption. 

 At 10:00 AM on December 22, ERCOT’s load peaked at 38,300 MW. At 

this point, the online generating capacity was 39,800 MW, or 1500 MW greater 

than the load. Within two hours, decreasing load and the restoration of some 

generating units that had been forced offline earlier succeeded in bringing reserves 

back up to acceptable levels. Thus, the record-setting peak load period was met 

without the need to shed firm load. 

 However, temperatures continued to drop overnight Friday into Saturday, 

December 23, when they reached minimums of -7, -1, and 7 degrees in Abilene, 

Dallas, and Houston, respectively, with wind chill factors down to -35 degrees. 

 Up until midnight Friday night, approximately 3000 MW of generation was 

offline due to weather-related problems. The system also suffered 1500 MW of 

capacity reduction on account of units switching from natural gas to fuel oil. 

Between midnight and 7:00 AM on the following morning, an additional 4700 

MW of generation was forced offline due to weather-related problems. It was also 

difficult getting power from outside ERCOT. West Texas Utilities offered 220 

MW of emergency power to Houston Lighting and Power Company (HL&P), to 

be delivered over the North Tie, but then had to withdraw the offer due to 

unspecified technical problems. 

 By 5:36 AM on Saturday, December 23, the frequency had again dropped 

below 59.95 Hz, and over the course of the next hour and a half it hovered 

between 59.79 and 59.92 Hz, indicating the system was in difficulty. Interruptible 

loads were shed during the early morning hours. At 7:49 AM, ERCOT directed 

the utilities that were generation deficient to shed firm load. 

 HL&P had already begun shedding firm load, and increased its load shed to 

1000 MW. Lower Colorado River Authority and the City Public Service of San 

Antonio shed 60 and 150 MW of firm load, respectively. 

 This firm load shedding, combined with some internal and external power 

transfers, succeeded in restoring the frequency to 60 Hz, re-stabilizing the system. 

Around 10:20 AM, however, seven generating units producing a combined 1275 

MW were all forced offline nearly simultaneously, causing the frequency to 

plummet to 59.65 Hz. ERCOT was then forced to invoke system-wide load 

shedding, beginning with 500 MW, allocated among the utilities. Within ten 

minutes, the frequency had recovered and the system was stable once again. 

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As the midday Saturday load declined (typical for a weekend midday), 

much of the firm load that had been shed was able to be restored within only 30 

minutes. The load shed directive was terminated slightly more than two hours 

later, when reserves increased to acceptable levels. 

 Accounts vary regarding the amount of total firm load that was shed. The 

PUCT reported a total load shed of 1710 MW.231

Generation Outages, Derates and Failures to Start

 The following table presents a summary of the causes of the outages, 

derates, and failures to start experienced in ERCOT during the 1989 cold weather 

event. 

Number of 

Units 

Capacity Cause 

34 11,623 

MW 

Frozen Instrumentation 

6 1385 MW Paralyzed or Dead Fish Clogging Water 

Intakes 

9 1051 MW Other, Cold Weather-related 

7 1246 MW Non-weather-related 

56 15,305 

MW 

Subtotal 

Not Available 1500 MW Gas curtailment impact (oil burning derate) 

56+ 16,805 

MW 

Total 

 

231 See Pub. Util. Comm’n of Tex., Electric Utility Response to the Winter Freeze of December 

21 to December 23, 1989 (Nov. 1990), at 14 (PUCT 1989 Report); ERCOT Emergency 

Operation at 6. 

. 

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Virtually all types of generating units encountered problems, whether 

viewed from the perspective of fuel type or unit type, suggesting that the problems 

could not be attributed to a particular fuel or unit design. The breakdown is as 

follows: 

 Sorted by Fuel Type:

o Coal: 8 units; 4669 MW 

o Natural Gas: 29 units; 3881 MW 

o Distillate Oil: 1 unit; 257 MW 

o Dual Fuel – Gas & Oil: 15 units; 4418 MW 

o Dual Fuel – Coal & Gas: 1 unit; 670 MW 

o Nuclear: 1 unit; 1250 MW * 

o Petroleum Coke: 1 unit; 160 MW 

This unit was forced off line the previous weekend due to the 

failure of an expansion joint in a steam condenser. An attempt was 

made to start it up during the December 21-23 cold spell, but that 

failed due to equipment freeze-ups. 

 Sorted by Unit Type:

o Conventional Steam Turbine Generators: 32 units; 13,298 MW 

o Simple Cycle Gas Turbines: 7 units; 235 MW 

o Combined Cycle Units: 17 units; 1772 MW 

PUCT Recommendations

 The PUCT staff investigated the cold weather event of 1989 and issued a 

report the following year that evaluated the causes of the generator outages and 

made recommendations. Because the circumstances of the event, and the causes 

of the outages, are so similar to those of the 2011 event, it is worth reproducing 

those recommendations verbatim:232 

 All utilities should ensure that they incorporate the lessons learned 

during December of 1989 into the design of new facilities in order to 

ensure their reliability in extreme weather conditions. 

 All utilities should implement procedures requiring a timely annual 

(each Fall) review of unit equipment and procedures to ensure readiness 

for cold weather operations. 

 232 PUCT 1989 Report at 7. 

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 All utilities should ensure that procedures are implemented to correct 

defective freeze protection equipment prior to the onset of cold weather. 

 All utilities should maintain insulation integrity and heat tracing 

systems in proper working order. Generating unit control systems and 

equipment essential to cold weather operations should be included in a 

correctly managed preventive maintenance program. 

 Additional training programs for plant personnel on the emergency cold 

weather procedures, including periodic drills, should be implemented by 

each responsible utility. 

 PUC Engineering Staff should modify procedures for power plant CCN 

[Certificates of Convenience and Necessity] reviews to include a 

specific review for plant reliability under adverse weather conditions. 

Of special interest would be the selection of proper design temperature 

ranges for the power plant site. 

 

The PUCT identified inoperative or inadequate heat tracing systems and 

inadequate insulation on instrumentation sensing lines as the most common 

technical equipment problems encountered during the freeze. (These problems 

also featured prominently in the failure of many generators during the February 

2011 event.) Many of the PUCT’s recommendations involve weatherization 

improvements it advised the generators to make, including ensuring the working 

operation of freeze protection equipment, insulation, and heat tracing systems; 

instituting preventative maintenance for cold weather equipment; and 

implementing adequate training for extreme conditions. 

 The report concluded that “the near complete loss of the ERCOT grid 

brings an awareness that, even in Texas, plant operators must prepare for cold 

weather emergencies...this awareness of and attention to cold weather problems 

must be continued.”233 

Comparison of 1989 and 2011 Events

 A summary of the statistics for the 1989 event and the 2011 event show 

how similar they were. Weather conditions and system events for each year are 

set forth below. 

 233 Id. 

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Comparison Table: Basic Information

December 21-23, 1989 February 1-2, 2011 

Min. Temps & Wind 

Chills in Dallas Area 

Temperature: -1 degrees F 

Wind Chill: -12 degrees F 

Temperature: 13 degrees F 

Wind Chill: -6 degrees F 

Peak System Load 38,300 MW 56,334 MW 

Net Generating 

Capacity Reduction 

11,809 MW 

31% of peak load 

14,702 MW 

26% of peak load 

Gross Generating 

Capacity Reduction 

56+ units 

16,805 MW 

193 units 

29,729 MW 

Firm Load Shed 1710 MW 

4.5% of peak load 

4900 MW 

8.7% of peak load 

Overall Duration of 

Firm Load Shedding 

5 hours, 47 minutes 7 hours, 24 minutes 

 The following table compares the causes of the outages, derates, and 

failures to start for each year.

Comparison Table: Generator Problems

December 21-23, 1989 February 1-2, 2011 

Frozen Instrumentation 34 units 

11,623 MW 

61 units 

13,924 MW 

Fish Clogging Water Intakes 6 units 

1385 MW 

None reported 

Other Cold Weather-related 9 units 

1051 MW 

54 units 

6365 MW 

Non-weather-related 7 units 

1246 MW 

63 units 

7905 MW 

Gas Curtailment Impact No. of units not specified 

1500 MW 

15 units 

1534 MW 

Weather-related % of Gross 

Capacity Reduction in MW 

 84 % * 68 % * 

Frozen Instr. % of Gross Capacity 

Reduction in MW 

69 % 47 % 

* Does not count gas curtailments as weather-related. 

 Despite the recommendations issued by the PUCT in its report on the 1989 

event, the majority of the problems generators experienced in 2011 resulted from 

failures of the very same type of equipment that failed in the earlier event. And in 

many cases, these failures were experienced by the same generators. Of the over 

56 units and 16,805 MW of generating capacity that became unavailable during 

the December 1989 event, 43 units (representing 13,606 MW of capacity) are still 

in service in 2011. And 26 of those units, representing 5654 MW of capacity, 

experienced problems again during the February 2011 cold weather event. 

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The failures of these repeating units alone eroded a large share of ERCOT’s 

reserve margin going into the morning of February 2, 2011, putting the entire 

system in jeopardy. Weighing the shedding of 4000 MW of firm load in February 

2011 against the 5654 MW of generation capacity that experienced problems in 

both the December 1989 and February 2011 events, it can be argued that had 

three-quarters of that capacity not failed again in 2011, the February 2011 

blackouts would not have happened. 234

 In its 1989 report, the PUCT commented that “whether the corrective 

actions being implemented [by the generators in the wake of the event] are 

sufficient to prevent future freeze-off related power plant failures, only direct 

experience with another deep freeze will ascertain.”235 Texas has now had that 

second event, and the answer is clearly that the corrective actions were not 

adequate, or were not maintained. Generators were not required to institute cold 

weather preparedness, and efforts in that regard lapsed with the passage of time. It 

is also possible that new ownership or new plant personnel lacked the historical 

perspective to make these efforts a priority, at least in the absence of externally 

imposed requirements. 

 The task force considered whether cost alone could have been the driving 

factor in the failure to maintain adequate winterization, and believes it to be 

unlikely. Based on current industry data, the task force estimates that for 

conventional gas-fired units and combined cycle units, the capital cost of 

upgrading basic equipment such as insulation and heat tracing could range from 

$50,000 to $500,000, depending on the age and condition of the materials, the 

original design temperature of the unit, and any change in the design 

temperature.236 (However, if significant plant components needed to be upgraded 

 234 The number of units that tripped, had derates, or failed to start was much larger in 

2011 than in 1989. This is primarily a matter of scale. The number of generating units in 

ERCOT increased from 323 in 1989 to 550 in 2011. However, the increase in the number of 

units does not correlate exactly with the increase in generating capacity from 54,000 MW to 

84,400 MW (using full wind power nameplate capacity, i.e., not adjusted) because of the large 

increase in combined cycle natural-gas fired plants since 1989 and the introduction of wind 

power. Combined cycle plants have multiple, and smaller, generating units than conventional 

steam-turbine plants. Wind power installations vary widely in size from tens of megawatts to 

hundreds of megawatts, adding greatly to the unit count, but less so to the actual capacity. With 

so many more, and smaller, units on line in 2011, it is not surprising that the number of trips, 

derates, and failures to start were greater than in 1989. 

235 PUCT 1989 Report at 6. 

236 See Black and Veatch Corp., Cold Weather Protection Assessment for El Paso 

Electric Company (Rev. 1), at 6-4 and 6-7. In the event an independent engineering analysis is 

commissioned, and based on current industry estimates, the costs for such an analysis for a gasfired unit could range from $25,000 to $150,000, depending on the type of unit. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

or replaced, the cost could be significantly higher. For instance, if cooling towers 

had freezing problems, the addition of a cooling tower bypass or variable speed 

tower fan motor might be needed; such costs could range from $150,000 to 

$500,000.237) 

 Texas has recently enacted legislation to deal with the problem of 

inadequate winterization by generators. A bill was introduced in the Texas 

legislature following the February 2011 blackouts, with provisions directing the 

PUCT to prepare a weather emergency preparedness report, to review the 

emergency operations plans on file, and to recommend improvements to the plans 

to ensure electric service reliability. In introducing the bill, State Senator Glenn 

Hegar stated: “What I don’t want, is another storm and another report someone 

puts on the shelf for 21 years and nobody looks at.”238 

 After a Senate Committee hearing, the bill was amended and unanimously 

adopted by the Texas Senate.239 The House unanimously passed the bill on May 

23, and the bill was signed into law by Governor Richard Perry on June 17, 2011. 

 

B. Natural Gas

 Gas production suffered declines in each of the six prior years identified by 

the task force as having had severe cold weather, and in 1989 and 2003, the 

declines led to gas curtailments that caused outages or derates to a number of gasfired electric generators. While some winterization has been put in place by 

producers and processing plants, production declines occur with each successive 

severe cold weather event, including the event of February 2011. It may well be 

that producers have limited market incentives to pay for more elaborate 

winterization, as they will likely lose less money from short periods of nonproduction than they would expend on preventing freeze-offs at each of the many 

wells a producer typically owns. 

 237 Id. 

238 Eric Dexheimer, February Power Blackouts Across Texas echoed 1989 Failures, State 

Report Shows, Austin American-Statesman, Apr. 10, 2011, http://www.statesman.com/news/

local/ february-power-blackouts-across-texas-echoed-1989-failures-1390558.html?view 

AsSinglePage=true. 

239 SB 1133, 82 Leg., Reg. Sess. (TX 2011) available at http://www.capitol.state.tx.us/ 

tlodocs/82R/billtext/pdf/SB01133E.pdf#navpanes=0. The bill would also allow the PUCT to 

require entities to update their emergency operations plans and to adopt rules relating to 

implementation of the bill. 

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Gas production declines in these prior extreme cold weather years are 

presented below, beginning with the most recent. 

January 2010

 In 2010, an ongoing cold spell led to wellhead and gathering line freezeoffs in the Rockies, San Juan and other southwestern producing basins. About 0.5 

Bcfd240 was lost in the Rockies and another 1.0 Bcfd was lost from the Southwest 

and shale basins. From January 21 through January 28, Northern Natural Gas and 

Southwest Gas issued low line pack alerts. High temperatures in every city in the 

area were above freezing during the month, and low temperatures fell only to the 

low 20s in a few cities on a few days. 

[Color legend: N is normal, B is below normal, MB is much below normal, 

and SB is strong below normal.] 

February 2008

 There was widespread cold weather during late January and early February 

2008 in the Rockies, Midwest, and Northeast. El Paso, Southwest Gas, 

Mississippi River Transmission (MRT), Natural Gas Pipeline Company of 

America (NGPL), ANR, Northern Natural Gas, and Kern River issued low line 

pack warnings, and receipts at the Opal241 processing plant in Wyoming fell due to 

 240 Production data in this section is drawn from Bentek, Supply and Demand Daily 

report. 

241 The Opal processing plant is a major source of output for Rockies production. Major 

interstate pipelines transport output from that plant to regional markets and markets in the East, 

the Pacific Northwest, California and the desert Southwest. 

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wellhead and gathering line freeze-offs in the region. Rockies production was off 

between 0.5 and 1.0 Bcfd over a 10-day period. Southwest regional production 

also fell by about 0.5 Bcfd during that time. 

December 2006

 During the first few days of December 2006, unseasonably cold air 

accompanied by a good deal of snow covered much of the Rockies, the Great 

Plains and the Midwest. The Midwest and Chicago took the brunt of the frigid 

temperatures. Lows were in the single digits with a wind chill of -12 degrees. For 

two days, wellhead freeze-offs caused midcontinent production to fall almost 1 

Bcfd, while Rockies and Texas/Louisiana production each were off about 0.5 

Bcfd. Temperatures in Midland and El Paso dipped into the low teens for a short 

time. The short cold snap set off a flurry of operational warnings and alerts; El 

Paso issued a system operating condition flow order, and Southwest Gas, MRT, 

NGPL, Kern River, and Transwestern issued low line pack warnings. 

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February 2003

 Overall, the winter of 2002/2003 was the third coldest of the most recent 11 

winter periods. The winter began with record inventories (at that time) of gas in 

underground storage. But by April, over 2.5 Tcf (trillion cubic feet) was 

withdrawn, also a record at the time. Regional and national natural gas storage 

inventories were at record lows when compared to many metrics. During the 

period from February 23 through February 25, a shot of very cold air swept out of 

the Rockies and through the Midwest. It brought wind chills of -50 ̊ to portions of 

Wyoming and Colorado and lows below zero in Chicago. Gathering system and 

wellhead freeze-offs were reported in the Permian Basin and the midcontinent and 

Rockies regions, and NGPL issued an operational flow order. Midland and Dallas 

temperatures fell below freezing, although only for a short time. El Paso and 

Transwestern did issue low line pack alerts that were quickly lifted. As noted 

earlier, in ERCOT there were gas curtailments to electric generators, estimated by 

ERCOT to have resulted in a loss of 5500 MW of capacity. 

 In a May 19, 2003 report on the 2003 cold weather event, the PUCT 

observed that the gas supply shortages experienced by electric generators in Texas 

were due in part to an unusually steep decline in storage volumes in the months 

preceding the event. Those depleted storage reserves during a time of increased 

demand made it difficult for generators to obtain adequate gas supply, although 

only one supplier, the TXU Lone Star Pipeline (now Atmos Pipeline-Texas), 

actually curtailed industrial customers. The PUCT also noted that newly 

independent power producers, unlike the old vertically integrated utilities, tended 

not to have their own storage facilities, a factor that contributed to the supply 

shortage.242 

 242 PUCT 2003 Report at 12-16. 

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The 2003 PUCT report recommended that the PUCT and the TRC 

collaborate on developing a joint curtailment methodology for natural gas and 

electricity.243 According to industry observers at the time, the recommendation 

was aimed at coordinating electrical generation needs with gas supply, to ensure 

that supply was being used where it was most needed during shortages. However, 

the agencies reportedly were unable to develop a policy and the project died.244 

December 1989

 December 1989 was described at the time by the National Weather Service 

as the coldest December ever recorded for the combined northeast, central, and 

southeast regions of the United States. The freeze of December 21 through 

December 25 caused severe problems for Texas electric utilities, as described 

earlier in the discussion on electric prior cold weather events. Record and near 

record low temperatures occurred across the state. For Dallas, it was the coldest 

and second coldest days in the last 38 years; for Midland, the third and fifth 

coldest days; for San Antonio, the first and fourth. Houston and Brownsville each 

had two days among the top five coldest. Wind chill factors in Houston fell to -5 

degrees, and in Dallas and Midland, to -12 degrees and -14 degrees, respectively. 

 While the gas supply situation was more precarious in the Northeast, the 

Gulf Coast supply regions, Texas and the Southwest were not without their 

problems. United States productive capacity had not been tested by a prolonged 

cold snap for more than a decade. Major processing plants245, refineries and 

petrochemical plants in the Gulf Coast region shut down. Supply problems 

occurred in the Gulf of Mexico, Kansas, Texas, Oklahoma, Arkansas, and 

Louisiana. High winds prevented crews from reaching offshore production 

platforms that froze off. A major gathering operation in Oklahoma saw 40 percent 

of its supply frozen off. Producer respondents to a 1991 AGA study said that 10 

percent of their production was affected by the cold temperatures.246 

 Most major interstate pipelines accessing Gulf supply experienced some 

kind of problem. Texas Eastern Transmission Corporation (TETCO) suspended 

all interruptible transportation deliveries and reduced firm deliveries by 0.5 

 243 Id. at 16. 

244 Drawn from materials submitted to the task force by a pipeline company. 

245 Conoco Inc. lost its 1 Bcfd Grand Chenier processing plant in coastal Louisiana due to 

gas supply and plant operational problems. 

246 Foster Natural Gas Report No. 1845 (Oct. 3, 1991) at 20. 

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Bcfd.247 Trunkline and NGPL also suspended interruptible transportation 

services. Transco curtailed firm service between 22 percent and 50 pe 248 rcent. 

In ERCOT there were gas curtailments to electric generators, tabulated 

earlier in the section on prior electric cold weather events. 

December 1983

 At the end of December 1983, a nine-day stretch of cold weather in Texas 

resulted in a 3 Bcfd shortfall in supply. Demand was met by massive withdrawals 

from storage and fuel switching by generators. Refinery operable capacity fell 

over 72 percent during the week, due to gas supply curtailments. The TRC said 

that if schools and factories had not been closed for the Christmas holiday, 

deliveries to high priority customers would have been curtailed. Producers behind 

Valero Energy reported well freeze-offs, accounting for a 43 percent drop in 

supply.249

 247 TETCO reported a field supply shortfall of 1 Bcfd from its normal of 1.9 Bcfd. 

248 See Rick Hagar, Winter Hits U.S. Industry, Strains Gas Supply, OIL & GAS J., Jan. 1, 

1990, at 28; see also Rick Hager, U.S. Gas Industry Ponders Lessons Learned from Severe 

Winter, OIL & GAS J., Mar. 5, 1990, at 17. 

249 See Rick Hagar, TRC Chairman Downgrades Size of Gas Surplus in U.S., OIL & GAS 

J., Feb. 27, 1984, at 47. 

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 An examination of these prior years reveals that production declines are 

common during cold weather events. However, only in limited circumstances did 

they lead to curtailment of natural gas customers, including curtailment of gasfired electric generators. 

 The production declines raise the question as to why producers did not 

improve their winterization preparations to withstand these not uncommon cold 

snaps. The reason most likely comes to one of cost (as well as to the lack of 

regulation requiring it). A study performed for the task force by the Gas 

Technology Institute250 has estimated that capital costs for winterization could 

vary from as little as $2,800 to more than $30,000 per well, depending on the 

degree of cold weather protection required and other variable factors such as gas 

flow rates, pressures, existing winterization, and the like. In addition to these 

capital costs, the cost of maintenance and operational supplies such as methanol 

(antifreeze) could add up to several thousand dollars per year for each well. 

(These costs include costs associated with protecting field processing, such as 

separating water from the gas, as well as the flow lines to the separating 

facilities.)251 Since it is not uncommon for the larger producers to have hundreds 

of wells in a given basin, these costs would quickly mount up. Such costs need to 

be accounted for in some fashion if mandatory weatherization were to be 

considered by regulatory or legislative bodies (as would the costs that would be 

incurred by electric generators to meet comparable requirements.) 

 250 This report is included as an appendix, entitled “GTI: Impact of Cold Weather on Gas 

Production.” 

251 Kent F. Perry, Gas Technology Institute, Impact of Cold Weather on Gas Production 

in the Texas and New Mexico Gas Production Regions of the United States During Early 

February, 2011 (June 2011) at 33. 

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Producers suggest that even improved winterization of the wells would not 

prevent a significant portion of production declines, since other problems, such as 

icy roads that prohibit hauling off water (which, if not done, shuts down the well), 

are also commonly encountered. 

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VIII. Electric and Natural Gas Interdependencies

The February 2011 cold weather event highlights the interdependency of 

electricity and natural gas, an interdependency that has grown in recent years. 

Natural gas has become an increasingly popular fuel choice for electric generators. 

Concurrently, compressors used in the production and transportation of natural gas 

have come to rely increasingly on electricity for their power source, rather than 

natural gas. 

The reason for the increased popularity of gas-fired electric generation is 

one of economics. Natural gas prices have fallen due to increased gas production, 

beginning in 2008 when producers developed the technology to drill the Barnett 

Shale. Just prior to 2008, average daily marketed production was about 55.5 Bcf 

per day. Spot prices at the Henry Hub during 2007 averaged almost $7.00 per 

MMBtu. Shale production accounted for perhaps five percent of total United 

States production, and offshore production comprised approximately 15 percent. 

But by the end of 2008, average daily production had grown to over 59.3 

Bcf per day. In the ensuing years, producers applied the lessons learned in the 

Barnett Shale to other basins, most notably the Fayetteville, Haynesville and 

Marcellus Shales, with notable results. Thus far in 2011, gas production is 

averaging almost 62.8 Bcf per day (and recently topped 64 Bcf per day), while 

average daily spot prices at the Henry Hub have fallen to $4.27 per MMBtu. 

Offshore production in 2010 accounted for only 10 percent of total United States 

production, and analysts estimate that shale production alone now accounts for 25 

percent of total production. 

 At the same time, gathering companies, as well as pipelines and LDCs 

located in urban areas, have increasingly turned to electric-powered compressors. 

Gathering companies prefer electric-powered compressors because they can fit in 

smaller spaces than gas-fired compressors, and the companies do not need as 

much compressive power as the large pipelines. For pipelines and LDCs in urban 

areas, environmental restrictions relating to noise and air quality, as well as the 

ready availability of electricity, tip the scales in favor of electricity over natural 

gas. The large pipelines favor gas-fired compressors, because the gas is readily 

available to them and they have large horsepower demands. 

The following chart depicts the mix of generation available for United 

States electricity needs in the summer of 2010, by fuel type.252 It shows that 27.8 

 252 NERC 2010 Summer Reliability Assessment (May 2010) at 10, http://www.nerc.com/ 

files/2010%20Summer%20Reliability%20Assessment.pdf. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

percent of all generation uses gas as the fuel source, and an additional 11.2 percent 

is dual-fueled (mostly gas and diesel oil). 

The Southwest relies heavily on gas-fired generation to meet its peak 

capacity needs. In ERCOT, approximately 57 percent of the available on-peak 

summer and winter capability is from gas-fired generation (with 40 percent solely 

gas-fired and 17 percent having dual-fuel capability with gas as the primary 

fuel).253 In the SPP region, 50 percent of the summer and winter on-peak 

capability is from gas-fired generation, and in WECC, 41 percent. 

In New Mexico, gas-fired generating units consume approximately 70,102 

MMcf annually, representing approximately one percent of total national 

consumption of gas used in the utility sector.254 In Texas, gas-fired generating 

units consume approximately 1,387,421 MMcf of natural gas annually, 

representing approximately 20.2 percent of total national consumption of gas used 

in the utility sector.255 And in Arizona, gas-fired generating units consume 

approximately 261,904 MMcf of natural gas annually, representing approximately 

3.8 percent of total national consumption of gas used in the utility sector.256 

 253 Based on data provided by ERCOT. 

254 EIA, Natural Gas Annual 2009, at 128-129 (Table 58), http://www.eia.doe.gov/ 

oil_gas/natural_gas/data_publications/natural_gas_annual/nga.html. 

255 Id. at 152-153 (Table 70). 

256 Id. at 70-71 (Table 29). 

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Interdependency Effects During the February Event

 

The task force examined data from numerous electric and gas entities to 

gauge the severity that shortfalls in one commodity had on the other during the 

February event. Materials received from natural gas producers indicate that the 

rolling blackouts (or customer curtailments) in ERCOT were a significant cause, 

from 29 to 27 percent respectively, of production shortfalls in the Permian and 

Fort Worth Basins. For pipelines and LDCs, however, the effects of the rolling 

blackouts were negligible.257 

Gas shortfalls caused problems for some generators in Texas, although not 

nearly to the extent as did direct weather-related causes such as equipment failure 

from below-freezing temperatures. In ERCOT, as detailed in the section of this 

report entitled “Causes of the Outages and Supply Disruptions,” the outages and 

derates from inadequate gas supply during the cold weather event totaled 1282 

MW, compared to a peak net capacity reduction of 14,702 MW. While gas supply 

to SRP and EPE was compromised due to problems at the Chevron Keystone 

Storage Facility, EPE’s generating units failed for other reasons, and SRP was able 

to obtain gas from other sources. However, during the 2003 cold weather event, 

there were significant gas curtailments to electric generators in Texas, which 

affected generating capacity. Gas curtailments also caused a loss of generating 

capacity in 1989, although to a lesser extent. 

The task force was cognizant of the possibility that gas shortages may have 

been a less significant factor only because so many generators were forced offline 

for other reasons, and thus unable to take the gas (as was the case with EPE). The 

task force attempted to answer the question of whether there would have been 

adequate gas supplies to ERCOT had its failed gas-fired generators been able to 

take the gas. To do so, the task force tallied and compared the MWs forced 

offline, the amount of gas demand the generators would have imposed on 

suppliers had they been capable of running, and the capacity of the gas supply 

system at the time. 

The task force determined that 5256 MW of generation in ERCOT could 

have imposed demands on the gas supply system had the generating units not 

experienced trips, derates, or failures to start. This number represents the total 

5556 MW of the 55 gas-fired generating units in ERCOT, reduced by 300 MW for 

those generating units connected to a single pipeline that had pressure or gas 

 257 An exception for LDCs supplying gas is the surge effect experienced when electricity 

is restored after an outage, which places instant and simultaneous demand on gas equipment and 

systems. This effect is described in the section of this report entitled “The Event: Outages and 

Curtailments.” 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

quality problems (making it unlikely the generating units could have received gas 

even if they had had no operational difficulties). Each unit was assumed to have a 

9,000 Btu/kWh heat rate. In the aggregate, these units would have added a 

maximum additional gas demand of approximately 1.1 Bcf per day. 

Adding this additional hypothetical demand to the actual peak demand of 

12.5 Bcf per day258 would have imposed total demand on the system of 13.6 Bcf. 

Supply in January was running at 17.7 Bcf per day; these volumes declined during 

the first week of February. On February 2, the worst day from the standpoint of 

ERCOT, supply declined to 16.35 Bcf per day. On February 4, when production 

volumes hit their lowest point for the week, supply declined to 14.08 Bcf per day. 

A comparison of these supply and demand numbers shows that total 

demand (actual demand plus hypothetical demand) would still have been below 

the available supply during the February cold weather event, particularly so on 

February 2, the day rolling blackouts were implemented. The task force’s analysis 

therefore indicates there would have been adequate gas to supply the generators in 

ERCOT that failed for other reasons.259 This conclusion was confirmed by 

knowledgeable industry observers, who were of the opinion that the Texas supply 

of gas would have been adequate had the generators not experienced 

weatherization problems. 

Fuel Switching

 A not insignificant amount of gas-fired generation in the Southwest has fuel 

switching capability. In ERCOT, 16 percent of total generation can fuel switch; in 

SPP, it is seven percent. Within WECC, of those generating units that are directly 

connected to El Paso, Northern Natural Gas, or ONEOK WesTex, 38 have fuel 

switching capability. 

Fuel switching enables a simple or combined cycle generating turbine to 

alternate between fuel sources, typically natural gas and some type of fuel oil. 

 258 The actual demand listed is a worst case scenario, because the calculation was derived 

by adding together the peak demand of each of the three major pipelines in Texas serving gasfired generating units. A more realistic number would probably be demand of approximately 12 

Bcf per day or less. 

259 The excess gas was sold out of state, but had the generators in ERCOT been able to 

use it, they could have gotten it. Since gas prices rose modestly in the region during the event, 

the shippers would very likely have redirected the gas to Texas to take advantage of the higher 

prices, had the generators been able to accept it. This would be true whether or not the contracts 

were interruptible, since a shipper could adjust its purchases and sales to take advantage of the 

pricing differential. 

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Fuel switching can be as simple as a control room operator pushing a button which 

automatically switches to oil, or as complicated as having to remove gas injectors 

and install oil injectors in every position around the boiler, a process that can take 

days rather than minutes. 

It is common for units that switch to an alternate fuel type to experience a 

capacity derate, since normally each unit is designed to most efficiently burn a 

particular fuel. 

The choice to perform fuel switching is primarily based on three factors: 1) 

cost, 2) environmental restrictions, and 3) the availability of natural gas. Running 

the generating unit on alternate fuels, such as fuel oil, may cost up to twice as 

much on a MW basis.260 And environmental and air quality control restrictions, 

which vary by state, may limit the number of hours per year a generator is allowed 

to run on fuel oil. 

Fuel switching capability was a more desirable option in the past, when the 

relative prices of gas and oil fluctuated, making one or the other more economical 

at any given time. Given the decline in natural gas prices, this option has become 

less valuable. 

During the February event, 20 generating units in ERCOT attempted to 

switch fuels, with 15 managing it successfully.261 (This echoed ERCOT’s 

experience during the 2003 cold weather event, when a number of units that 

attempted to switch fuels were unable to do so, and those that did switch 

experienced derates of capacity.262) SRP has nine units capable of switching, and 

EPE has three units capable of switching. None was asked to switch during the 

event, as the units either failed for other reasons or were able to obtain adequate 

gas supply. In SPP, of the three representative entities the task force examined, 

eight generating units have fuel switching capabilities; four attempted to switch 

during the event and ultimately succeeded, although half had initial difficulties. 

 260 Based on information supplied to the task force by an LDC. 

261 A majority of the units that attempted to switch fuels but were unable to do so 

experienced a mechanical failure of some sort in the switching equipment, which could have been 

due to the cold temperatures, inadequate maintenance, lack of regular testing, or the infrequent 

use of the alternate fuel in normal operations. 

262 PUCT 2003 Report at 17. The PUCT recommended that providing financial 

incentives for fuel oil inventories, to be maintained for use by dual-fueled generating units, 

should be considered. 

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Fuel switching raises a number of questions, such as: whether generators 

that have the capability to switch fuels should be required to maintain their 

alternate fuel equipment and stockpile an adequate supply of the alternate fuel, 

whether subsidies or incentives should be instituted to compensate for such 

requirements or to add fuel switching capabilities to those units that do not 

currently have it, and whether units that can switch fuels should be paid to do so in 

order to preserve gas supplies for residential consumers. These are issues that can 

be most fruitfully addressed in forums involving representatives of both the 

electric and natural gas industries operating in the region, as well as the regulatory 

bodies overseeing them. 

Communications

 In 2004, NERC released a report entitled “Gas/Electricity 

Interdependencies and Recommendations,” which summarized the findings of its 

Gas/Electricity Interdependency Task Force (GEITF). The GEITF held a series of 

meetings with representatives of both the electric and gas industries and prepared a 

list of recommendations for NERC’s consideration. The GEITF reported that a 

recurring theme expressed by gas industry participants was concern about 

communications between pipeline operators and entities other than the pipeline’s 

contractual customers. While the pipelines communicate with the LDCs serving a 

generator or with the generator itself, they do not communicate with a regional 

reliability coordinator, apparently due to confidentiality restrictions. The GEITF 

recommended that NERC, in concert with other energy industry organizations, 

formalize communications between the electric industry and the gas transportation 

industry for the purposes of education, planning, and emergency response. 

 Communication failures between gas and electric entities did not seem to 

play a role during the February 2011 event (although there were complaints of 

communication issues between shippers and pipelines). Nonetheless, the electric 

and gas industries might consider revisiting the GEITF recommendations to see if 

procedures should be developed for communications between pipelines and 

reliability coordinators.263

 263 NERC plans to conduct an electric/gas interdependency study in 2011 to reevaluate 

the GEITF recommendations. The study will analyze whether procedures should be developed 

for communications between the electric and gas industries. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

IX. Key Findings and Recommendations 

The facts that came to light in the course of the joint inquiry conducted by 

the staffs of FERC and NERC, as well as the conclusions drawn from them, have 

been presented throughout the body of this report. Because the matters examined 

are complex and detailed, this section presents in summary form the task force’s 

key findings. It also presents recommendations that the task force believes, if 

implemented, could significantly contribute to preventing a recurrence of the 

rolling blackouts and natural gas curtailments experienced in the Southwest during 

the February 2011 cold weather event. 

A. The Electric Industry

Key Findings -- Electric

 During the February event, temperatures were considerably lower (15 

degrees plus) than average winter temperatures, and represented the 

longest sustained cold spell in 25 years. Steady winds also accelerated 

equipment heat loss. However, such a cold spell was not 

unprecedented. The Southwest also experienced temperatures 

considerably below average, accompanied by generation outages, in 

December 1989. Less extreme cold weather events occurred in 2003 

and 2010. Many generators failed to adequately apply and 

institutionalize knowledge and recommendations from previous severe 

winter weather events, especially as to winterization of generation and 

plant auxiliary equipment. 

 While load forecasts fell short of actual load, the forecasts were not a 

factor in the loss of load. ERCOT manually increased its February 1 

and February 2 forecasts by 4000 MW to factor in wind chill, and had 

established sufficient reserves to accommodate both forecasted load and 

the actual load that transpired. The reason blackouts had to be initiated 

was that over 29,000 MW of generation that was committed in the dayahead market or held in reserve either tripped, was derated, or failed to 

start. This was the largest loss of generation in ERCOT’s history, 

including during the prior cold weather load shed event in December 

1989 and the two hot weather load shed events in 2003 and 2006. 

While units of all types (except nuclear generating units) tripped, 

derated, or failed to start in 2011, in ERCOT, gas combined cycle units 

had the highest percentage of failures, compared to their percentage of 

the total fuel mix. 

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 ERCOT and the generators within ERCOT could better coordinate 

generator scheduled outages, both in terms of the total amount of 

scheduled outages at a given time and their location. A substantial 

amount of generation (11,566 MW) was on scheduled outage going into 

the cold weather event. ERCOT’s current Protocols provide that 

requests for scheduled outages submitted earlier than eight days before 

the outage is to begin are automatically approved, unless they would 

violate a Reliability Standard. 

 ERCOT’s fast action in initiating rolling blackouts prevented more 

widespread and less controlled ERCOT-wide blackouts. Had ERCOT 

not initiated manual load shedding, its under-frequency load shedding 

relays would have instantaneously dropped approximately 2600 MW 

(five percent of system load), a loss that could have created further 

system disturbances and resulting generation outages. Load shedding 

by the transmission and distribution operators in ERCOT’s footprint 

was generally carried out in a timely and effective manner. 

 Transmission operators and distribution providers generally did not 

identify natural gas facilities such as gathering facilities, processing 

plants or compressor stations as critical and essential loads. 

 Balancing authorities, reliability coordinators and generators often 

lacked adequate knowledge of plant temperature design limits, and thus 

did not realize the extent to which generation would be lost when 

temperatures dropped. 

 The lack of any state, regional or Reliability Standards that directly 

require generators to perform winterization left winter-readiness 

dependent on plant or corporate choices. While Reliability Standard 

EOP-001 R.4 and R.5 refer to winterization as a consideration in 

emergency plans, these requirements apply only to balancing 

authorities, transmission owners, and transmission operators. 

 Generators were generally reactive as opposed to being proactive in 

their approach to winterization and preparedness. The single largest 

problem during the cold weather event was the freezing of 

instrumentation and equipment. Many generators failed to adequately 

prepare for winter, including the following: failed or inadequate heat 

traces, missing or inadequate wind breaks, inadequate insulation and 

lagging (metal covering for insulation), failure to have or to maintain 

heating elements and heat lamps in instrument cabinets, failure to train 

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operators and maintenance personnel on winter preparations, lack 

of fuel switching training and drills, and failure to ensure adequate fuel. 

 Gas curtailment and gas pressure issues did not contribute significantly 

to the amount of unavailable generating capacity in ERCOT during the 

event. The outages, derates, and failures to start from inadequate fuel 

supply totaled 1282 MW from February 1 through February 5, as 

compared to an overall peak net generating capacity reduction of 14,702 

MW. 

Recommendations -- Electric

PLANNING AND RESERVES 

1. Balancing Authorities, Reliability Coordinators, Transmission 

Operators and Generation Owner/Operators in ERCOT and in the southwest 

regions of WECC 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 February event demonstrates that the generators did 

not adequately anticipate the full impact of the extended cold weather and high 

winds. While plant personnel and system operators, in the main, performed 

admirably during the event, more thorough preparation for cold weather could 

have prevented many of the weather-related outages. 

Capacity margins going into the winter of 2010/2011, for both ERCOT and 

the southwest regions of WECC, were adequate on paper. (ERCOT reported a 57 

percent margin above forecasted winter peak demand, and the southwest regions 

of WECC projected a 105.7 percent margin.) 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 February. 

 

While the probability of a winter event in the predominantly summer 

peaking Southwest 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. 

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2. Planning authorities should augment their winter assessments with 

sensitivity studies incorporating the 2011 event to ensure there are sufficient 

generation and reserves in the operational time horizon. 

Both ERCOT and the Southwest regions of WECC undertake planning 

studies to ensure that sufficient reserves are available to meet seasonal peak loads. 

However, the forecasted peak demand in the winter assessments for 2010/2011 

was not as high as that actually experienced in early February. 

Planners should undertake a sensitivity study, using the 2011 actual 

conditions 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. ERCOT is currently considering a similar 

recommendation, which was presented to its Board of Directors in March, 2011. 

4. ERCOT should reconsider its protocol that requires it to approve 

outages if requested more than eight days before the outage, consider giving 

itself the authority to cancel outages previously scheduled, and expand its 

outage evaluation criteria. 

ERCOT’s Protocols provide that it may not forbid an outage request 

submitted more than eight days prior to the scheduled outage, unless the outage 

would keep ERCOT from meeting applicable Reliability Standards or Protocol 

requirements. The Protocols further limit review of outage requests made earlier 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

than eight days before the outage to the following three things: load forecast, other 

known outages of both generation and transmission, and the results of a 

contingency analysis to indicate whether the outages would cause overloads or 

voltage problems. 

The task force recommends that ERCOT consider lengthening the period 

for which ERCOT may deny an outage request, assuming the conditions for doing 

so are met. (ERCOT is presently considering a Protocol revision to give itself the 

authority to deny an outage request that is not scheduled more than 90 days prior 

to the outage date, a revision which the task force supports.) In addition, ERCOT 

should consider giving itself 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, ERCOT 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 in the 

Protocols, the task force recommends that ERCOT take 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, ERCOT should: 

o Have available to it the design temperatures of all generation 

resources. 

o Take into consideration as an extreme weather event approaches 

which plants will not be available based on their design temperature 

limits. 

o Consider increasing reserve levels during extreme weather events. 

o Commit, for purposes of serving load and being counted as reserves, 

only those plants whose temperature design limits fall within the 

forecasted temperature range. 

o Determine, prior to approving an outage, if the combination of 

previously approved scheduled outages with the proposed scheduled 

outages might cause reliability problems. 

 

5. ERCOT should consider modifying its procedures to (i) allow it to 

significantly raise the 2300 MW responsive reserve requirement in extreme 

low temperatures, (ii) allow it to direct generating units to utilize preoperational warming prior to anticipated severe cold weather, and (iii) allow 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

it to verify 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 Generation 

Owner/Operators should consider developing mechanisms to verify that units 

that have fuel switching capabilities can periodically demonstrate those 

capabilities. 

Sixteen percent of ERCOT’s generation capacity is listed as having fuel 

switching capabilities. During the February 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: 

 Documented time required to switch equipment, 

 Documented unit capacity while on alternate fuel, 

 Operator training and experience, 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

 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. 

The task force determined that a combination of scheduled and forced 

outages of ERCOT’s black start units would have put ERCOT’s ability to restore 

the system in jeopardy, had an uncontrolled blackout not been averted by the 

implementation of load shedding. Balancing Authorities and Transmission 

Operators should take steps to ensure the availability and reliability of their black 

start units during adverse weather and emergency conditions, particularly to 

prevent a gap in this function before 2013, when the provisions of Reliability 

Standard EOP-005-2 on System Restoration from Blackstart Resources becomes 

mandatory. These steps should ideally include auditing Generator 

Owner/Operators, random testing of black start units during temperature extremes 

(both hot and cold), determining the ambient operating temperature limitations of 

the black start units, evaluating the effects of extreme temperatures on 

implementation of the entity’s black start plan; and ensuring that operators are 

trained to start the black start units during extreme weather conditions. ERCOT is 

presently considering Protocol revisions that would provide for unannounced 

testing of black start units and “claw back” payments for black start units that fail 

testing or fail to perform. 

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. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 forecasted 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 forecasted 

weather conditions, and should consider whether to take into account weatherrelated 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. 

Balancing Authorities are permitted to request a forecast of real output 

capability under Reliability Standard TOP-002-02 R15. 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. 

In the case of ERCOT, which does not own the generators in its footprint, 

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 ERCOT’s 

direction. 

10. Balancing Authorities should plan ahead so that emergency 

enforcement discretion regarding emission limitations can be quickly 

implemented in the event of severe capacity shortages. 

Some generators experienced derates during the event due to emission 

limitations. The Texas Commission on Environmental Quality (TCEQ) exercised 

enforcement discretion with respect to its emission restrictions during the event; 

however, this action, which was taken after the TCEQ received requests during the 

event itself, did not come in time to prevent all the emissions-related derates that 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

occurred on February 2. It is recommended that ERCOT work out procedures in 

advance with the TCEQ for the exercise of its enforcement discretion in the case 

of severe weather events, and have an internal procedure in place that delegates 

specific ERCOT personnel as responsible for contacting the TCEQ and other 

environmental regulatory bodies during the early stages of an event, in order to 

inform them of the significance of the situation. 

WINTERIZATION 

11. States in the Southwest 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 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. 

 The state of Texas has provided a starting point for such legislation with SB 

1133, which was signed into law on June 17, 2011. This statute incorporates two 

important components: (1) mandatory reporting of emergency operations 

procedures, and (2) independent review by the PUCT. 

In addition to the matters covered in the Texas statute, the task force 

recommends that planning take into account not only forecasts but also historical 

weather patterns, so that the required procedures accommodate 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 acknowledgement 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. 

NERC staff has 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 

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step in the Reliability Standards development process, proposing modifications to 

the Reliability Standards for Emergency Preparedness and Operations. 

 

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: 

 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 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 its 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. 

 Each Generator Owner/Operator should develop a winter 

preventative 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 program, so that repairs necessary for 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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 cases 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 forecasted freezing weather, inspect the power supply to all heat 

trace circuits, including all breakers and fuses. 

 Each Generator Owner/Operator should, before each winter begins and 

before forecasted 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 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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. 

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: 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

 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 

winter-specific 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. 

 

 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 devices. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

 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 into account the accelerated cooling 

effect of wind), and ensure that temperature requirements are met 

during operations. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

COMMUNICATIONS

21. Balancing Authorities should improve communications during extreme 

cold weather events with Transmission Owner/Operators, Distribution 

Providers, and other market participants. 

During the February event, ERCOT communicated with Transmission 

Owners and Transmission Service Providers (an ERCOT-specific term) 

concerning the initiation of load shedding and the subsequent restoration of 

service. These communications appear to have been made in accordance with 

applicable ERCOT Operating Guidelines and Reliability Standards. However, 

ERCOT and several of its Transmission Service Providers that were responsible 

for curtailing firm load suggested areas for improvement in communications. 

 

Transmission Service Providers are dependent on ERCOT for much of their 

information on ERCOT-wide system conditions, as they do not have information 

regarding generator trips beyond those on their own systems, and can only track 

ERCOT-wide system status by monitoring ERCOT’s posted Physical Response 

Capability levels or monitoring frequency levels. Some of these Transmission 

Service Providers suggested that ERCOT should have communicated concerns 

about deteriorating conditions much earlier than it did. 

A task force appointed by ERCOT’s Board of Directors to look into the 

February 2 rolling blackouts concluded that there was a need for earlier 

dissemination of operational information to Transmission Service Providers and 

Distribution Service Providers (an ERCOT-specific term) during the period 

leading up to a possible emergency, a conclusion with which this task force 

agrees. 

22. ERCOT should review and modify its Protocols as needed to give 

Transmission Service Providers and Distribution Service Providers in Texas 

access to information about loads on their systems that could be curtailed by 

ERCOT as Load Resources or as Emergency Interruptible Load Service. 

Some ERCOT Transmission Service Providers expressed concern that they 

have virtually no information regarding loads on their own systems that may be 

deployed by ERCOT as Load Resources or Emergency Interruptible Load Service 

resources. These loads contract directly with ERCOT, and the Transmission 

Service Provider does not receive information about their status. When these 

loads are shed by ERCOT without prior notification to the Transmission Service 

Providers and Distribution Service Providers, they have the potential to cause 

localized imbalances in line flows, voltages, and other system parameters that may 

be problematic. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

The task force suggests that ERCOT share information about the status of 

these loads with Transmission Service Providers on a daily basis, and study the 

effects of the loss of large blocks of these loads on the transmission grid. 

23. WECC should review its Reliability Coordinator procedures for 

providing notice to Transmission Operators and Balancing Authorities when 

another Transmission Operator or Balancing Authority within WECC is 

experiencing a system emergency (or likely will experience a system 

emergency), and consider whether modification of those procedures is needed 

to expedite the notice process. 

The Task Force observed a lag in communicating a declared system 

emergency in WECC. In one instance, a Reliability Coordinator did not issue an 

EEA 3 declaration until seven minutes after the decision had been made to do so; 

the delayed declaration appeared to have been the first official notice by the 

Reliability Coordinator to other WECC entities of the seriousness of the 

generation failures on the system of the Balancing Authority in question.

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 oftencompressed 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-

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

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.

B. The Natural Gas Industry

Key Findings -- Natural Gas

 Extreme low temperatures and winter storm conditions resulted in 

widespread wellhead, gathering system, and processing plant freeze-offs 

and hampered repair and restoration efforts, reducing the flow of gas in 

production basins in Texas and New Mexico by between 4 Bcf and 5 Bcf 

per day, or approximately 20 percent, a much greater extent than has 

occurred in the past. 

 The prolonged cold caused production shortfalls in the San Juan and 

Permian Basins, the main supply areas for the LDCs that eventually 

curtailed service to customers in New Mexico, Arizona, and Texas. 

 Wellhead freeze-offs normally occur several times a winter in the San Juan 

Basin but are not common in the Permian Basin, which is the supply source 

that LDCs in the Southwest region typically rely upon when cold weather 

threatens production in the San Juan Basin. 

 Electrical outages contributed to the cold weather problems faced by gas 

producers, processors, and storage facilities in the Permian and Fort Worth 

Basins, with producers being more significantly affected by the blackouts; 

however, based on information obtained from a sampling of producers and 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

processing plants in the region, the task force concluded that the effect of 

electric blackouts on supply shortages was less important than the effect of 

freezing temperatures. 

 Although producers in the New Mexico and Texas production areas 

implemented some winterization measures such as methanol injection, 

production was nevertheless severely affected by the unusually cold 

weather and icy road conditions, which prevented crews from responding to 

wells and equipment that were shut in. 

 The extreme cold weather also created an unprecedented demand for gas, 

which further strained the ability of the LDCs and pipelines to maintain 

sufficient operating pressure. 

 The combination of dramatically reduced supply and unprecedented high 

demand was the cause of most of the gas outages and shortages that 

occurred in the region. 

 Low delivery pressures from the El Paso Natural Gas interstate pipeline, 

caused by supply shortages, contributed to gas outages in Arizona and 

southern New Mexico. 

 Some local distribution systems were unable to deliver the unprecedented 

volume of gas demanded by residential customers. 

 No evidence was found that interstate or intrastate pipeline design 

constraints, system limitations, or equipment failures contributed 

significantly to the gas outages. 

 

 The pipeline network, both interstate and intrastate, showed good flexibility 

in adjusting flows to meet demand and compensate for supply shortfalls. 

 Additional gas storage capacity in Arizona and New Mexico could have 

prevented many of the outages that occurred by making additional supply 

available during the periods of peak demand. Natural gas storage is a key 

component of the natural gas grid that helps maintain reliability of gas 

supplies during periods of high demand. Storage can help LDCs maintain 

adequate supply during periods of heavy demand by supplementing 

pipeline capacity, and can serve as backup supply in case of interruptions in 

wellhead production. Additional gas storage capacity in the downstream 

market areas closer to demand centers in Arizona and New Mexico could 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

have prevented most of the outages that occurred by making additional 

supply available in a more timely manner during peak demand periods. 

Recommendations – Natural Gas

1. Lawmakers in Texas and New Mexico, working with their state 

regulators and all sectors of the natural gas industry, should determine 

whether production shortages during extreme cold weather events can be 

effectively and economically mitigated through the adoption of minimum, 

uniform standards for the winterization of natural gas production and 

processing facilities. 

The Texas and New Mexico production basins experienced unusually sharp 

declines due to the prolonged freezing weather of early February 2011. Although 

these areas typically experience occasional freeze-offs during periods of subfreezing weather, and although natural gas producers and processors in those 

regions employ some winterization techniques, to a significant degree those 

measures were inadequate to meet consumer demand during this event. 

Production difficulties were compounded by icy road conditions, which disrupted 

routine maintenance and delayed repairs. 

Some industry representatives stated that producers and processors already 

have strong economic incentives to keep gas flowing at all times, and that 

increased winterization would not have prevented many of the shortfalls that 

occurred in the Southwest production basins in early February 2011. Others stated 

that the levels of winterization typically employed in these areas are designed to 

deal with less severe, more typical winter weather conditions, and that additional 

winterization could protect the system from the effects of unusually harsh weather. 

Many expressed the view that along with increased reliance upon natural gas for 

energy, steps should be taken to improve the reliability of gas supply during 

extreme cold weather events. 

Whether the adoption of uniform winterization standards for natural gas 

facilities is the right way to meet the goal of increased reliability is a complex 

question. Among the issues that need to be resolved are the following: 

 Determining the costs of increased winterization and balancing those 

costs against the need for increased reliability, 

 Determining who should ultimately bear the costs of additional 

winterization, and whether ratemakers would be willing to pass the costs 

of increased reliability along to consumers, 

 Determining whether it is practical to design for very low temperatures, 

which may not recur for years or even decades, 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

 Ensuring that standards are uniformly applied, and determining whether 

state commissions would have adequate resources or authority to 

promulgate and enforce those standards, and 

 Identifying possible incentives for industry that could improve the 

reliability of winter supply without government regulation. 

Because the Commission does not have jurisdictional authority over this 

sector of the natural gas industry for these purposes, we recommend that state 

lawmakers and regulators in Texas and New Mexico investigate whether 

minimum standards for the winterization of gas production and processing 

facilities should be adopted, by way of legislation, regulation, or the adoption of 

voluntary industry practices, and whether such standards would be likely to 

effectively and reliably improve supply during extreme weather events. 

2. The gas and electric sectors should work with state regulatory 

authorities to determine whether critical natural gas facilities can be 

exempted from rolling blackouts. 

The natural gas industry depends in many instances on electric utilities for 

the power that helps move gas from the production fields to end users. Electricpowered instrumentation, compression, pumps, and processing equipment are 

essential links in that process, and in some instances, even the brief, temporary 

loss of electric power can put a gas production, processing, compression, or 

storage facility out of service for long periods of time, especially where weather 

conditions delay access to those facilities. The resulting gas outages can 

contribute to electricity shortages by cutting off or reducing fuel supply to gasfired generating plants. 

Gas producers, processors, pipelines, storage providers, and LDCs should 

identify portions of their systems that are essential to the ongoing delivery of 

significant volumes of gas, and which are dependent upon purchased power to 

function reliably under emergency conditions. State regulatory authorities should 

work with the gas industry and electric transmission operators, balancing 

authorities and reliability coordinators to determine whether such facilities can be 

shielded from the effects of future rolling blackouts. 

3. State utility commissions should work with LDCs to ensure that 

voluntary curtailment plans can reduce demand on the system as quickly and 

efficiently as possible when gas supplies are disrupted. 

One tool available to LDCs faced with supply disruptions during periods of 

high consumer demand is the implementation of voluntary curtailment plans, 

which seek reductions or curtailment from large commercial users. State 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

regulators, who review and approve the voluntary curtailment plans of LDCs, 

should assess whether they are designed and implemented in a way that maximizes 

their potential effect in emergency situations. 

Voluntary curtailment plans should include multiple points of contact for 

large customers and up to date, 24-hour contact information. Where appropriate, 

the plans should provide for pre-event planning, training, and customer education. 

Large customers should be contacted prior to emergencies and efforts should be 

made to explain the circumstances under which reductions or curtailments would 

be sought and to obtain advance commitments for possible reductions, giving 

LDCs a clearer idea of the amount of demand that can be reduced in an 

emergency. While voluntary curtailment does nothing to increase supply, in light 

of the importance of reducing demand when distribution systems are near collapse, 

regulators and the LDCs should ensure that planning for voluntary curtailments is 

as thorough and well-thought out as possible. 

4. State utility commissions should work with balancing authorities, 

electrical generators, and LDCs to determine whether and under what 

circumstances residential gas customers should receive priority over electrical 

generating plants during a gas supply emergency. 

Gas-fired generation provides much needed electrical power during a 

weather emergency, but also consumes large amounts of natural gas. Although 

restoring residential electricity service after a rolling blackout is a fairly simple 

process, restoring gas service after an outage is both labor-intensive and timeconsuming. 

State utility commissions should work with LDCs to identify situations 

where consumption by gas-fired generators could contribute to residential gas 

customer outages, and should consult with those generators and the relevant 

Balancing Authority to determine whether alternative power suppliers or fuel 

supplies could be used in emergency situations. The state commissions should 

also evaluate the relative importance, for human needs customers, of gas-fired 

generation and residential use, and should assess the relative impacts of curtailing 

generating plants versus gas supply to residences. 

5. State utility commissions and LDCs should review the events of early 

February 2011 and determine whether distribution systems can be improved 

to increase flows during periods of high demand. 

In some instances during the winter storm event, LDC distribution systems 

were unable to flow scheduled volumes, suggesting that downstream parties may 

not have had sufficient capacity or facilities to handle historically high demand. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event 

Accordingly, state commissions and distribution companies should determine 

whether system enhancements can be made to improve volume handling capacity, 

such as additional distribution valving, looping, more compression, or 

reconfigured compression. Although such system improvements would probably 

not compensate for the level of supply shortfalls that occurred in early February 

2011, they might allow LDCs to take higher volumes for longer periods of time. 

6. State utility commissions should work with LDCs to determine 

whether the LDC distribution systems can be improved so that curtailments 

can be implemented, when necessary, in a way that improves the speed and 

efficiency of the restoration process. 

The events of early February 2011 demonstrated that once operational 

pressures and line pack begin to fall beyond normal tolerances, little time may be 

available to evaluate, locate, and shut off portions of the pipeline systems of the 

LDCs to avoid system collapse. Regulators should work with LDCs, as part of the 

annual system review process, to determine whether the systems under their 

regulatory authority should be further sectionalized to provide more options when 

involuntary curtailments are necessary. 

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FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

ATTACHMENTS 

Acronyms 

Glossary 

Appendices

Task Force Members 

 Legislative and Regulatory Responses by the States 

Categories of NERC Registered Entities 

Electricity: How it is Generated and Distributed 

Power Plant Design for Ambient Weather Conditions 

Impact of Wind Chill 

Winterization for Generators 

Natural Gas: Production and Distribution 

Natural Gas Storage 

Natural Gas Transportation Contracting Practices 

GTI: Impact of Cold Weather on Gas Production
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

This page intentionally left blank. 
Acronyms 

Page 1 of 2 

AC Alternating Current 

ACE Area Control Error 

ANR ANR Pipeline 

Company 

Bcf Billion Cubic Feet 

Btu British Thermal Unit 

CFE Comisión Federal de 

Electricidad 

CNG Compressed Natural 

Gas 

COP Current Operating Plan 

DC Direct Current 

DC Tie Direct Current Tie 

EEA Energy Emergency 

Alert 

EILS Emergency 

Interruptible Load 

Service 

EPE El Paso Electric 

Company 

ERCOT Electric Reliability 

Council of Texas 

ERO Electric Reliability 

Organization 

FERC Federal Energy 

Regulatory 

Commission 

Hz Hertz 

IMM Independent Market 

Monitor 

ISO Independent System 

Operator 

LDC Local Distribution 

Company 

LNG Liquefied Natural Gas 

LRGV Lower Rio Grande 

Valley 

Mcf Thousand Cubic Feet 

MMcf Million Cubic Feet 

MW Megawatt 

MWh Megawatt Hour 

NGL Natural Gas Liquids 

NMGC New Mexico Gas 

Company 

NERC North American 

Electric Reliability 

Corporation 

OCN Operating Condition 

Notice 

OFO Operational Flow Order 

PNM Public Service 

Company of New 

Mexico 
Acronyms 

Page 2 of 2 

PRC Physical Response 

Capability 

PUCT Public Utilities 

Commission of Texas 

QSE Qualified Scheduling 

Entity 

RMR Reliability Must Run 

SRP Salt River Project 

Agricultural 

Improvement and 

Power District 

SRSG Southwest Reserve 

Sharing Group 

RTO Regional Transmission 

Organization 

RUC Reliability Unit 

Commitment 

SCADA Supervisory Control 

and Data Acquisition 

SPP Southwest Power Pool 

SRSG Southwest Reserve 

Sharing Group 

TRE Texas Reliability 

Entity, Inc. 

TRC Texas Railroad 

Commission 

UFLS Under-Frequency Load 

Shedding 

WECC Western Electricity 

Coordinating Council 
Glossary 

Page 1 of 28 

Active Power - Also known as real power, this is the rate at which work is 

performed or at which energy is transferred, usually expressed in kilowatts (kW) 

or megawatts (MW) when referring to electricity. In the field of electric power, 

the terms “active power” or “real power” are often used in place of the term 

“power” alone to differentiate it from reactive power. (See Reactive Power) 

Allocation of Capacity - A process by which capacity available in a pipeline is 

distributed to parties in the event requests for volume (i.e., nominations) are in 

excess of the available space. Typically the allocation is based on service type, 

contract type and a company's tariff provisions.

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. 

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. 

Ancillary Services - The services necessary to support the transmission of electric 

power from seller to purchaser given the obligations of control areas and 

transmitting utilities within those control areas to maintain reliable operations of 

the interconnected transmission system. These include, but are not limited to, 

voltage support, regulation, reserves, and black start capability.

Aquifer Storage - The storage of gas underground in porous and permeable rock 

stratum, the pore space of which was originally filled with water and in which the 

stored gas is confined by suitable structure, permeability barriers, and hydrostatic 

water pressure. 

Area Control Error (ACE) - The instantaneous difference between a Balancing 

Authority’s net actual and scheduled interchange, plus the instantaneous difference 

between the interconnection’s actual frequency and scheduled frequency and a 

correction for meter error. 

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. 
Glossary 

Page 2 of 28 

Auto-Transformer - A power transformer with a single coil for each electrical 

phase, as opposed to a conventional transformer, which has two coils per phase. In 

an auto-transformer, the entire coil acts as the primary winding while a portion of 

the same coil acts as the secondary winding. 

Automatic Generation Control (AGC) - A feature of a power system’s 

centralized control system that automatically adjusts generation in a Balancing 

Authority Area to maintain the Balancing Authority’s interchange schedule plus 

its Frequency Bias. 

Balancing (Natural Gas) - Equalizing a shipper’s receipts and deliveries of gas 

on a transportation pipeline. Balancing may be accomplished daily, monthly or 

seasonally, with penalties generally assessed for excessive imbalances.

Balancing Authority (BA) - The responsible entity that integrates resource plans 

ahead of time, maintains load-interchange-generation balance within a Balancing 

Authority area, and supports interconnection frequency in real time.

Base Load (Natural Gas) - A given volume of gas used by a LDC or other large 

user, remaining fairly constant over a period of time. Base load does not vary with 

heating degree-days. 

Baseload Generating Units - Electric generating units which produce energy at a 

constant rate, usually at a low cost relative to other generating units available to 

the system. Baseload units are used to meet some or all of a given region’s 

continuous energy demand on a seasonal or daily basis, including at minimum 

load levels, and tend to operate non-stop except for maintenance or forced outages. 

Base Load Storage (Natural Gas) - Storage facilities capable of holding enough 

natural gas to satisfy long term seasonal demand requirements. 

Blade - The component of a steam turbine that is acted upon by the flow of steam. 

Blades in steam turbines are also referred to as “buckets.” Similarly, in gas, or 

combustion turbines, the blades are the components acted upon by the flow of the 

high pressure, high temperature gases produced in the combustor. In both steam 

turbines and combustion turbines, the blades are arranged in multiple stages of 

varying diameter, with many blades per stage. Modern wind turbines, in contrast, 

typically utilize only three long blades. The purpose of the blades is to extract 

energy from the motion of the propelling fluid (steam, combustion gases, or air) 

and convert it into rotational form by direct coupling to a common spinning shaft 

which is in turn used to drive a generator. 
Glossary 

Page 3 of 28 

Boiler - The component of a steam power plant in which water is heated and 

converted into steam. 

British Thermal Unit (BTU) - the measurement of heat released by burning any 

material. The amount of energy necessary to raise the temperature of one pound 

of water by one degree Fahrenheit from 58.5 to 59.5 degrees Fahrenheit under 

standard pressure of 30 inches of mercury at or near its point of maximum density. 

Bulk Electric System - The electrical generation resources, transmission lines, 

interconnections with neighboring systems, and associated equipment, generally 

operated at voltages of 100 kV or higher. Radial transmission facilities serving 

only load with one transmission source are generally not considered to be part of 

the bulk electric system. 

Capacitor Bank - 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. 

Capacity Market - A market where Load Serving Entities purchase generating 

capacity (including adequate reserves) to cover their peak loads. 

Capacity Release (Natural Gas) - A mechanism by which holders of firm 

interstate transportation capacity can relinquish their rights to utilize the firm 

capacity to other parties that are interested in obtaining the right to use that 

capacity for a specific price, for a given period of time and under a specifically 

identified set of conditions. The firm transportation rights may include 

transmission capacity and/or storage capacity. 

Capacity-Short Charge - In ERCOT, a monetary charge to Qualified Scheduling 

Entities (QSEs) who cannot meet their resource commitments when a Reliability 

Unit Commitment (RUC) study (conducted periodically) determines there is 

insufficient generation to meet projected demand, and the costs associated with 

bringing the needed additional generation on-line cannot be fully recovered using 

energy revenue. The capacity-short charge is the mechanism for covering those 

costs. This is done on the basis of settlement intervals. 

Centrifugal Compressor Unit(s) -Compressors that produce pressure by 

centrifugal force from rotation of a compressor wheel that translates kinetic energy 
Glossary 

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into pressure energy of the gas. Centrifugal compressors are commonly used in 

gas transmission systems due to their flexibility. 

Charge - In physics, charge, also known as electric charge, electrical charge, or 

electrostatic charge is a characteristic of an object that expresses the extent to 

which it has more or fewer electrons than protons. A single electron carries an 

elementary charge of negative polarity, whereas a single proton carries the same, 

except of positive polarity. The unit of electrical charge is the coulomb 

(symbolized C) where 1 C is equal to 6.24 x 1018 elementary charges. It is not 

unusual for real-world objects to hold charges of many coulombs. When two 

objects having electric charges are brought into proximity with each other, an 

electrostatic force is manifested between them – attractive if the charges are of 

opposite polarity and repulsive if the charges are of the same polarity. 

Circuit Breaker - In electrical power systems, circuit breakers are used to 

disconnect and reconnect transmission lines, transformers, generators, and other 

facilities from the power system or from each other. Circuit breakers trip to 

interrupt the flow of current when faults develop, de-energizing the faulted facility 

and isolating it from the system. They are also used to switch facilities in or out of 

service. 

Citygate - The point at which a Local Distribution Company receives natural gas 

from an interstate or intrastate pipeline. 

Cold Load Pickup - Phenomenon that takes place when a distribution circuit is 

re-energized following an extended outage of that circuit. Cold load pickup is a 

composite of two conditions: 1) inrush current which reestablishes the magnetic 

fields in motors and transformers and the necessary temperatures in heating coils 

and incandescent lamp filaments and 2) loss of load diversity due to cyclic loads 

which normally cycle randomly with respect to one another, such as refrigerator 

compressors, all restarting at the same time. The inrush current may last up to 

several seconds while the loss of load diversity may persist for many minutes. 

Combined Cycle Unit - This type of electric generating unit consists of one or 

more gas turbines, also referred to as combustion turbines, equipped with heat 

recovery steam generators to capture heat from their exhaust. Steam produced in 

the heat recovery steam generators then drives a steam turbine generator to 

produce additional electric power. A typical arrangement consists of two natural 

gas-fired combustion turbines combined with a single steam turbine, each driving 

its own electrical generator, for a total of three generators. The heat recovery 

aspect of combined cycle units increases the overall efficiency of electric power 

production. 
Glossary 

Page 5 of 28 

Comisión Federal de Electricidad (CFE) - A Mexican governmental entity that 

generates, transmits, distributes and sells electricity to more than 34.2 million 

customers, representing more than 100 million people annually. CFE 

interconnects to ERCOT via two high voltage DC (HVDC) ties and to WECC via 

AC transmission lines at the California border just south of San Diego. 

Compressor or Compressor Units - Mechanical equipment that adds pressure to 

the natural gas stream to enable the flow of natural gas through a pipeline system. 

Compressor Station - A permanent facility that houses compression equipment 

that supplies pressure to move natural gas through pipelines. 

Condensate and Water Return Lines - Plumbing in a generating station that 

captures condensate and used water for recycling or re-use. 

Condenser - In a steam turbine generating station, the condenser is a type of heat 

exchanger that cools the steam exiting the turbine to the point where it condenses 

into water, thereby recovering the high quality feed water for reuse. The cooling 

is accomplished using separate cooling water. Surface condensers use a shell and 

tube assembly wherein the cooling water is circulated in the tubes, and the steam 

and condensate are contained in the tank-like housing, or shell, that surrounds and 

encloses the tubes. 

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. 

Contingency Reserve Level - 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. The Contingency Reserve Level is that level of reserves required 

for the reliable operation of an interconnected power system. 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 
Glossary 

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capacity is necessary to replace capacity and energy lost due to forced outages of 

generation or transmission equipment. 

Contract Pressure (Natural Gas) - The maximum or minimum required 

operating pressure at a natural gas receipt or delivery point, as specified in the 

agreement between a pipeline and its customer.

Control Area - An electric power system or combination of electric power 

systems to which a common automatic control scheme is applied in order to: 1) 

match, at all times, the power output of the generators within the electric power 

system(s) with the load in the electric power system(s); 2) maintain scheduled 

interchange with other Control Areas; 3) maintain the frequency of the electric 

power system(s); and 4) provide sufficient generating capacity to maintain 

operating reserves, all within reasonable limits in accordance with Good Utility 

Practice. 

Controllable Load Resources (CLR) - In ERCOT, CLRs are a type of load 

resource capable of controllably reducing or increasing consumption under 

dispatch control (similar to automatic generation control or AGC) and able to 

immediately respond proportionally to frequency changes (similar to generator 

governor action) to provide the following ancillary services: Up and Down 

Regulation (URS & DRS), Responsive Reserve (RRS), and Non-Spinning Reserve 

(NSRS). 

Cooling Tower - A structure and associated equipment intended to facilitate the 

evaporative cooling of water by contact with air. In steam turbine generating 

stations, cooling water is routed through the cooling tower for cooling after having 

absorbed heat in the condenser.

Cooling Water - In steam turbine generating stations, water that is used in the 

condenser to extract heat from steam exiting the turbine for the purpose of 

condensing that steam back to feed water. The feed water is then cycled back 

through the boiler to make steam again. The cooling water is generally taken from 

a nearby lake (often man-made for this purpose) or river and is distinctly separate 

from the feed water that is used to make steam and which must be specially treated 

to prevent corrosion. Electric generating stations use wholly separate cooling 

water systems to extract heat from the large copper conductors comprising the 

generator stator windings. 

Cooling Water Intakes - The point at which industrial plants, including power 

plants, bring cooling water into their system from lakes, rivers, or other sources. 
Glossary 

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Broadly, the total physical structure and any associated constructed waterways 

used to withdraw cooling water.

Current (Electric) - The rate of flow of electrons in an electrical conductor. The 

symbol for current is “I” and the unit is the ampere, or amp, where one amp is 

defined as one coulomb of charge per second. 

Current Operating Plan (COP) - In ERCOT, a plan by a Qualified Scheduling 

Entity (QSE) reflecting anticipated operating conditions for each of the resources 

that it represents for each hour in the next seven operating days, including resource 

operational data, resource status, and ancillary service schedule. 

Curtailment (Electric) - A reduction in the scheduled capacity or energy delivery 

of an Interchange Transaction. 

Curtailment (Natural Gas) - A method to balance a utility's natural gas 

requirements with its natural gas supply. Customers are typically ranked by 

priority in the utility’s curtailment plan. A customer may be required to partially 

cut back or totally eliminate its take of gas depending on the severity of the 

shortfall between gas supply and demand and the customer's priority.

Day-Ahead Market - A daily, co-optimized market in the 24 hour period before 

the start of the next operating day for ancillary service capacity, certain congestion 

revenue rights, and forward financial energy transactions. 

Day-Ahead RUC (DRUC) - In ERCOT, a Reliability Unit Commitment (RUC) 

process performed for the next operating day. 

Decommitment Payment - In ERCOT, a payment made to a resource committed 

by the Reliability Unit Commitment (RUC) process if the directive to use that 

resource is cancelled prior to its scheduled start time. 

Demand (Electric) - The rate at which electric energy is delivered to or by a 

system or part of a system, generally expressed in kilowatts (kW) or megawatts 

(MW), at a given instant or averaged over any designated interval of time. The 

term “demand” is often used interchangeably with the term “load” with respect to 

electric power systems. 

Depleted Oil and/or Gas Fields - Naturally occurring reservoirs that once held 

deposits of oil and gas, consisting of porous and permeable underground 

formations confined by impermeable rock or water barriers. The working gas 

requirement for this type of storage reservoir is generally about 50% of the total 
Glossary 

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reservoir capacity. Gas is typically withdrawn in the winter season and injected in 

the summer. 

Derate (Electric Generator) - 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. 

Direct Current (DC) Tie - In electric power systems, the term “DC Tie” or, more 

correctly, “HVDC Tie” referring to high voltage DC, is used to describe a 

transmission-level facility that interconnects between two portions of a power 

system, two different power systems, or two different electric power 

interconnections. The DC Tie consists of: (1) a converter station to convert three 

phase AC power to DC; (2) a DC connection to a second converter station; and (3) 

a second converter station that reconverts the DC power back to three-phase AC. 

The DC connection between the two converter stations (step 2 above) may be 

either a long HVDC transmission line or, in the case of “back-to-back” converters 

at the same location, a simple set of bus bars. The power flow in DC ties is not 

free-flowing as it is in AC lines, but rather is controlled precisely by control 

systems on the converters. Unlike AC lines, DC ties can interconnect between 

asynchronous interconnections such as ERCOT, the Eastern Interconnection, and 

the Western Interconnection because concerns about frequency, phase angle, and 

voltage differences are rendered immaterial by the AC-to-DC-to-AC conversion 

process. 

Distribution (Electric) - The function of distributing electric energy to retail 

customers, and all associated physical means of serving that function, including 

substations, low voltage distribution lines, transformers, etc. 

Distribution Provider - As defined by NERC, a Registered Entity that provides 

and operates the “wires”, i.e., distribution lines, transformers, and associated 

facilities, between the transmission system and the end-use customer. For those 

end-use customers who are served at transmission voltages, the Transmission 

Owner also serves as the Distribution Provider. 

Distribution Service Provider - As defined by ERCOT, an entity that owns or 

operates a Distribution System for the delivery of energy from the ERCOT 

Transmission Grid to Customers. 
Glossary 

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Electrical Energy - Electric power generated, transmitted, distributed, and 

consumed over a period of time, expressed in kilowatt hours (kWh), megawatt 

hours (MWh), or gigawatt hours (GWh). 

Electric Reliability Council of Texas, Inc. (ERCOT) - ERCOT is an 

Independent System Operator (ISO) that manages the flow of electric power to 23 

million customers in Texas representing 85 percent of the state’s electric load and 

75 percent of its land area. ERCOT is registered with NERC to serve the 

following roles: Balancing Authority, Interchange Authority, Planning Authority, 

Reliability Coordinator, Resource Planner, and Transmission Service Provider. It 

is also jointly registered with other entities as a Transmission Operator.

Electric Reliability Organization (ERO) - The Energy Policy Act of 2005 

required the creation of an independent Electric Reliability Organization (ERO) to 

be certified by FERC and tasked with developing and enforcing mandatory 

reliability standards applying to the bulk power system. (See Energy Policy Act of 

2005, Pub. L. No. 109-58, section 102.) 

Electromagnetic Induction - The creation of a voltage in a conductor due to a 

relative movement between the conductor and a magnetic field. Electromagnetic 

induction is the basic principle of operation of generators. 

Emergency Interruptible Load Service (EILS) - In ERCOT, EILS is an 

emergency load reduction service designed to decrease the likelihood of the need 

for firm load shedding. It is provided by qualified loads that make themselves 

available for interruption in an electric grid emergency. Customers meeting EILS 

criteria may bid to provide the service through their Qualified Scheduling Entities 

(QSEs). EILS is called upon during an Energy Emergency Alert (EEA) Level 2B 

to assist in maintaining or restoring system frequency. EILS is not an Ancillary 

Service. 

Energy - See Electrical Energy. 

Energy Emergency Alert (EEA) - NERC Reliability Standard EOP-002-2.1 

prescribes the use of an energy emergency alert (EEA) procedure when a load 

serving entity is unable to meet its customers’ expected energy requirements. 

These energy emergencies are declared by the load serving entity’s Reliability 

Coordinator, and are categorized by level of severity, i.e., EEA1, 2, or 3, with 

level 3 being the most severe. ERCOT defines EEA as an orderly, predetermined 

procedure for maximizing use of available resources and, only if necessary, 

curtailing load during an emergency condition while providing for the maximum 

possible continuity of service and maintaining the integrity of the ERCOT system.
Glossary 

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Energy Imbalance Service (EIS) - EIS is provided when a difference occurs 

between the scheduled and the actual delivery of energy to/from the transmission 

system over a single hour. The market participant must purchase this service from 

the transmission provider or make comparable alternate arrangements with another 

market participant who will purchase this service from the transmission provider. 

Energy-only Market (Electric) - A market for electric energy that pays resources 

only for delivered energy and ancillary services, and does not pay for installed 

capacity (ICAP). 

Energy-only Resource Adequacy Mechanism - A mechanism that allows realtime energy prices to rise in times of scarcity in order to provide incentives for 

investment in peaking as well as base-load generation. 

E-Tag - Electronic Tagging, or e-Tag, is used to schedule an interchange 

transaction in a wholesale electricity markets. NERC and/or Regional Entities 

(such as WECC) collect all e-Tag data in near real-time to assist Reliability 

Coordinators in identifying transactions to be curtailed to relieve overload when 

transmission constraints occur. NERC defines an interchange transaction as “an 

agreement to transfer energy from a seller to a buyer that crosses one or more 

Balancing Authority area boundaries.” 

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. 

Firm Service (Natural Gas) - Transportation service on a firm basis means that 

the service is not subject to a prior claim by another customer or another class of 

service and receives the same priority as any other class of firm service. 

Flow Line - Flow lines carry the fluids or natural gas from the wellhead to and inbetween individual vessels in separation, treating, heating, dehydrating, 

compression, pumping or other processing equipment generally located at or near 

the well site.

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 - The removal from service availability of a generating unit, 

transmission line, or other facility for emergency reasons. This can be done 

automatically, as in the case of tripping, manually, as in the case of forced 
Glossary 

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shutdowns, or by withholding a generating unit, transmission line, or other 

equipment from returning to service due to unresolved problems. 

Frequency - The rate, in terms of time, at which a periodic pattern repeats itself. 

In electric power systems, frequency is measured in cycles per second, or Hertz 

(Hz). The symbol is “F”. The nominal, or base, frequency for power systems in 

North America is 60 Hz. 

Frequency Bias - A weighting factor applied to the difference between the 

Interconnection’s actual frequency and scheduled frequency during the calculation 

of a Balancing Authority’s Area Control Error (ACE). The weighting factor 

determines how strongly a Balancing Authority will respond to deviations from 

the scheduled frequency. Larger Balancing Authorities will usually have a larger 

Frequency Bias. 

Frequency Deviation - Broadly, a change in the frequency of an electrical 

interconnection. More typically, sudden changes that result in the frequency of the 

interconnection going outside the normal bounds of 59.95 Hz to 60.05 Hz due to 

the unexpected loss of a significant amount of generation or load. 

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). 

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. 

 

Generator Operator - An entity that operates a generating unit or a fleet of 

generating units and performs the functions of supplying energy and 

interconnected operations services to a power system. 

Generator Owner - An entity that owns and maintains a generating unit or a fleet 

of generating units. 

Generator Runback - The intentional rapid reduction of the output level of an 

electric generating unit or an entire generating station, either manually or 
Glossary 

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automatically via plant controls, due to any of a variety of problems in the plant 

that limit the plant’s capacity to generate power, or problems on the transmission 

system external to the plant which limit the capability of the system to accept the 

plant’s power output. 

 

Good Utility Practice - Any of the practices, methods and acts engaged in or 

approved by a significant portion of the electric power industry during the relevant 

time period, or any of the practices, methods and acts which, in the exercise of 

reasonable judgment in light of the facts known at the time the decision was made, 

could have been expected to accomplish the desired result at a reasonable cost 

consistent with good business practices, reliability, safety and expedition. Good 

Utility Practice is not intended to be limited to the optimum practice, method, or 

act to the exclusion of all others, but rather to be acceptable practices, methods, or 

acts generally accepted in the region. 

 

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.

Hertz - The unit of frequency equal to one cycle per second. 

Hockey Stick Bidding - A pricing strategy during a supply shortage whereby a 

trader offers to sell a small quantity of energy at a price well above marginal cost, 

in order to manipulate prices upward.

Hourly RUC (HRUC) - In ERCOT, any Reliability Unit Commitment (RUC) 

executed after the Day-Ahead RUC (DRUC). 

Human Needs Customers - Customers such as residential users, hospitals, and 

nursing homes, who use natural gas for essential human needs. 

Hydrate Crystals - Crystals of hydrates formed under certain pressure and 

temperature conditions by hydrates and water present in natural gas. Hydrate 

crystals can form when the temperature is above the melting temperature of ice 

and can block natural gas wells, gathering systems, and pipelines. 

Import Limit - The maximum level of electric power that can flow into a power 

system or portion of a power system over a transmission path or paths without 
Glossary 

Page 13 of 28 

violating facility thermal ratings, voltage ratings, transient stability limits, or 

voltage stability limits either in real-time or post contingency, i.e., after the loss of 

a generator, transmission line, or other facility. 

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. 

ISOs in the U.S. include the California ISO, ISO New England, the New York 

ISO, PJM, the Midwest ISO, and ERCOT. These ISOs dispatch generation in 

their respective geographic territories. 

Induction Machine - A rotating electromagnetic machine using alternating 

current that may be a generator or a motor. When a generator, the induction 

machine’s rotor is driven at a speed greater than synchronous speed. When a 

motor, the induction machine’s rotor is driven at a speed less than synchronous 

speed. Induction generators are rarely used for large scale power generation. 

Induction motors, on the other hand, are the most common type of AC motor. 

Induction machines absorb reactive power and cannot be used to produce reactive 

power (as a synchronous machine can). 

Insulator - A material with a high resistance to the flow of electric current. More 

broadly, mechanical supports and spacers constructed of insulating materials. 

Electrically speaking, an insulator is the opposite of a conductor. 

Interchange - Electrical energy transfers that cross Balancing Authority 

boundaries. 

Interconnection - In North America, any one of the four major electric system 

networks – Eastern, Western, Quebec, and ERCOT. These operate 

asynchronously with respect to one another. 

Interruptible Service - Service on an interruptible basis means that the capacity 

used to provide the service is subject to a prior claim by another customer or 

another class of service and receives a lower priority than such other classes of 

service. 

Interruptible Responsive Reserve - In ERCOT, Interruptible Responsive 

Reserve is provided by load resources that are automatically interrupted when 

system frequency decreases to 59.7 Hz. The total amount of Interruptible 

Responsive Reserve procured for a given hour is limited to one half of the 

Responsive Reserve Service required for that hour. 
Glossary 

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Inverter - A converter designed and operated to convert DC power to AC power. 

In power systems, inverter generally refers to high voltage DC (HVDC) 

converters. 

Island (Electrical) - An electrically isolated portion of an interconnection.. The 

frequency in an electrical island must be maintained by balancing generation and 

load in order to sustain operation. Islands are frequently formed after major 

disturbances wherein multiple transmission lines trip, or during restoration 

following a major disturbance. 

 

Joule-Thomson Effect - The cooling that occurs when a compressed gas is 

allowed to expand in such a way that no external work is done. The effect is 

approximately 7 degrees Fahrenheit per 100 psi for natural gas. 

Lateral Line - A pipe in a gas distribution or transmission system that branches 

away from the central and primary part of the system.

Line Pack - Natural gas occupying all pressurized sections of the pipeline 

network. Introduction of new gas at a receipt point “packs” or adds pressure to the 

line. Removal of gas at a delivery point lowers the pressure (unpacks the line). 

Line Trip - This refers to the automatic disconnection of a transmission line by its 

circuit breakers. Line trips are initiated by protective relays and are designed to 

protect the power system when a short circuit, or fault, occurs on a line by 

isolating the faulted line from the system. 

Liquefied Natural Gas (LNG) - Natural gas (primarily methane) that has been 

liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric 

pressure. 

Long Haul Pipeline - A transportation pipeline that transports natural gasa 

significant distance (hundreds of mile or more) from the production area. 

Load - See Demand (Electric). 

Load Acting as Resource (LaaR) - This term, discontinued by ERCOT when 

they transitioned from a Zonal Market to a Nodal Market on December 1, 2010, 

was replaced by the term Load Resource (see below). 

Load Resource - In ERCOT, Load Resources provide ancillary services for either 

Responsive Reserve Service (RRS) or Non-Spinning Reserve Service (NSRS). 

There are two types of Load Resources – Controllable Load Resources (CLRs) 
Glossary 

Page 15 of 28 

and Non-Controllable Load Resources (NCLRs). “Controllable” refers to the 

capability to control the load remotely from the ERCOT control center rather than 

solely at the end-use customer location (or by its Qualified Scheduling Entity 

(QSE)).

Load Service Entity - An entity that secures energy and transmission service (and 

related interconnected operations services) to serve the electrical demand and 

energy requirements of its end-use customers. 

Load Shedding - 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. (See Rolling Blackouts.) 

 

Local Distribution Companies (LDC) - Any firm, other than a natural gas 

pipeline, engaged in the transportation or local distribution of natural gas and its 

sale to customers that consume the gas. 

Magnetic Field - The invisible lines of force between the north and south poles of 

a magnet. A magnetic field is created when electric current flows through a 

conductor. 

Make-Whole Charge - In ERCOT, a charge made to a Qualified Shedding Entity 

(QSE) for a resource to recapture all or part of the revenues received by a QSE 

that exceed the Make-Whole Payment for a resource (see below). 

Make-Whole Payment - In ERCOT, a payment made to a Qualified Scheduling 

Entity (QSE) for a resource to reimburse it for allowable startup and minimum 

energy costs of a resource not recovered in energy revenue when a resource is 

committed by the Day-Ahead Market (DAM) or by a Reliability Unit 

Commitment (RUC). 

Maximum Allowable Operating Pressure - The maximum operating pressure at 

which a pipeline system may be operated safely. 

Mercaptans - A group of strong-smelling chemical compounds added to natural 

or LP gases as a safety measure, to warn of leaks.

Metering (Electric) - A meter is a device for measuring and displaying an 

electrical quantity. For example, meters are used to measure power flows, voltage, 

current, frequency, etc. The term “metering” generally refers to a group of meters 
Glossary 

Page 16 of 28 

associated with a given facility, and the information from those meters transmitted 

to and displayed in a control room or control center. 

Methanol - A light volatile flammable poisonous liquid alcohol used especially as 

a solvent, antifreeze, or denaturant for ethyl alcohol, and in the synthesis of other 

chemicals. 

Nomination - A request for a physical quantity of natural gas under a specific 

purchase, sales or transportation agreement, or for all contracts at a specific point. 

A nomination will continue for specified number of days or until superseded by 

another service request for the same contract.

North American Energy Standards Board - A non-profit, private standards 

development organization established in January 2002 to develop voluntary 

standards and model business practices designed to promote more competitive and 

efficient natural gas and electric service. 

Nodal Market (Electric) - Prices are assessed at points (i.e., nodes) where 

electricity enters or leaves the grid. Transmission lines throughout the grid may 

be subject to congestion rents, which means generators may receive different 

prices based on how they contribute to or relieve congestion on the grid. ERCOT 

transitioned from a zonal to a nodal market on December 1, 2010. Their nodal 

market calculates transmission costs from the point of generation from roughly 

4,000 delivery points. Nodal pricing is intended to provide a more detailed and 

accurate picture of transmission and generation than zonal pricing. ERCOT’s 

nodal system reduces the time interval for which the market-clearing price is 

calculated to five minutes (from fifteen minutes in their former zonal market). 

Non-Controllable Load Resources (NCLRs) - In ERCOT, these represent loads 

that provide selected Ancillary Services, but that do not have the capability of 

being switched or controlled directly from the EROCT control center. (Compare 

Controllable Load Resources) 

Non-Spinning Reserve Service - In ERCOT, this refers to generation resources 

capable of being ramped to a specified output level within thirty minutes or load 

resources that are capable of being interrupted within thirty minutes. The 

generation resources must be capable of running at a specified output level for at 

least one hour, and the load resources must similarly be capable of remaining out 

of service for at least one hour.
Glossary 

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Operating Condition Notice (OCN) - In ERCOT, this is the first of four possible 

levels of communication issued (by ERCOT) in anticipation of a possible 

emergency condition. 

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. 

Operational Balancing Agreement - A contract that specifies the procedures that 

will be used between two interconnected natural gas pipelines in order to manage 

variances or imbalances at major interconnect points. 

Operational Flow Order (OFO) - A notice to natural gas pipeline users designed 

to protect the operational integrity of the pipeline. OFOs require shippers to take 

action to balance their supply with their customers’ usage on a daily basis within a 

specified tolerance band. Shippers may deliver additional supply or limit supply 

delivered to match usage. 

 

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 - As defined by NERC, the highest hourly integrated Net Energy For 

Load (generation plus imports minus exports) within a Balancing Authority area 

occurring within a given period (e.g., day, month, season, or year), or the highest 

instantaneous demand within the Balancing Authority area. 

Peak Load Storage (Natural Gas) - Storage that provides high-deliverability of 

gas supplies to the market over short periods of time. 

Peaking Unit or Peaking Power Plant - Peaking plants operate primarily during 

times when load or demand increases rapidly to a maximum level and remains 

there for only a short time, e.g., on hot summer afternoons when air conditioning 

causes electricity usage to reach its highest level in the daily cycle. Peaking plants 

are often powered by natural gas, but they can also be powered by water at 

hydroelectric dams or by fuel oil. These plants can be brought online and taken 

offline quickly, in response to changing demand. 
Glossary 

Page 18 of 28 

Phase (Electrical) - In AC power systems, power is generated, transmitted, and 

distributed using three virtually identical sets of (1) coil windings in generators 

and transformers, (2) conductors in overhead and underground transmission and 

distribution lines and busses, (3) electrical poles and contacts in circuit breakers 

and switches and (4) other power equipment such as capacitor banks, reactors, 

etc., known as phases, and often identified by the letters A, B, and C. The three 

individual phase windings of a typical generator stator are arranged so that they’re 

evenly spread out around the circular / cylindrical design/construction, each 

oriented one third of a turn apart (120 degrees) from the other two. As the rotor 

spins, its magnetic field sweeps through each of these windings sequentially as it 

completes a single rotation. The voltage, current, and power associated with each 

phase are therefore separated in time from the other two phases by virtue of this 

sequence. This method is much more efficient than a single phase approach not 

only for generating power, but also for its transmission and distribution. 

Physical Responsive Capability (PRC) - In ERCOT, this is defined as the total 

amount of system wide On-Line capability that has a high probability of being 

able to quickly respond to system disturbances. It can be made up of generation 

and load resources. 

Pigging - The practice of using pipeline inspection gauges or ‘pigs’ to perform 

various operations on a pipeline without stopping the flow of natural gas in the 

pipeline. 

Planning Reserve Margin - Planning reserve margin is designed to measure the 

amount of generation capacity available to meet expected demand through the 

planning horizon, which can range from the upcoming season to a ten-year period. 

It is calculated as the difference between resources and peak demand, divided by 

peak demand to arrive at a percentage figure. 

Poles - The opposite ends of a magnet where the field is most concentrated, 

designated as the north and south poles. In a synchronous generator, the magnetic 

poles are established by DC current passing through the field winding on the rotor 

which is essentially the coil of an electromagnet. Separately, in AC electrical 

equipment, particularly in switches and circuit breakers, poles refer to the contact 

assemblies associated with a particular phase. For example, it is common to refer 

to pole A, B, or C of a three phase disconnect switch. (See Phase) 

Potomac Economics, Ltd. - The Independent Market Monitor (IMM) for 

ERCOT. 
Glossary 

Page 19 of 28 

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. 

Processing Plant - A surface installation designed to separate and recover natural 

gas liquids such as propane, butane, ethane, or natural gasoline from a stream of 

produced natural gas through the processes of condensation, absorption, 

adsorption, refrigeration, or other methods, and to control the quality of natural 

gas marketed or returned to oil or gas reservoirs for pressure maintenance, repressuring, or cycling. 

Production Separator - An item of production equipment used to separate liquid 

components of the well stream from gaseous elements. 

Qualified Scheduling Entity (QSE) - In ERCOT, a Market Participant that is 

qualified for communication with ERCOT for Resource Entities and Load Serving 

Entities (LSEs) and for settling payments and charges with ERCOT. QSEs submit 

schedules on behalf of Resource Entities or LSEs such as retail electric providers 

(REPs). QSEs must submit daily schedules for their bilateral transactions with 

total generation and demand and bid curves for zonal balancing up and balancing 

down energy. The schedules for generation and demand are required to be 

balanced so that supply equals demand. QSEs also bid for ancillary services. 

Ramp or Ramp Rate (for Interchange Schedules) - The rate, expressed in 

megawatts per minute, at which the interchange schedule is attained during the 

ramp period. 

Ramp or Ramp Rate (for Generator Output) - The rate, expressed in 

megawatts per minute, that a generator changes its output, or is expected to change 

its output. 

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.
Glossary 

Page 20 of 28 

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.” 

Reciprocating Compressor Unit(s) - Also known as “positive displacement” 

compressors, reciprocating compressors operate by trapping a certain volume of 

natural gas within the compressor and reducing the volume. The high-pressure 

gas is then released through the discharge valve into the pipeline. Piston-operated 

reciprocating compressors fall within the category of positive displacement 

compressors. These compressors have a fixed volume and are able to produce 

high compression ratios. 

Rectifier - A converter designed and operated to convert AC power to DC power. 

Electrically speaking, rectifiers are the opposite of inverters. High voltage DC 

(HVDC) converter stations contain large numbers of high power rectifiers. 

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 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. 

Regulation - The ability to maintain a quantity within acceptable limits. For 

example, frequency regulation is the control or regulation of the system frequency 

to within a tight bandwidth around 60 Hz. Voltage regulation is the control of a 

voltage level within a set bandwidth. In power systems operations, regulation 

often refers broadly to changing the output level of selected generators to match 

changes in system load. 
Glossary 

Page 21 of 28 

Regulator, Pressure - A device that maintains the pressure in a fluid flow line, 

less than its inlet pressure within a constant band of pressures, regardless of the 

rate of flow in the line or the change in upstream pressure. 

 

Relay Misoperation - Any unintentional operation of a protective relay when no 

fault or other abnormal condition has occurred.

Reliability Must Run (RMR) Unit - A unit that must run for operational or 

reliability reasons, regardless of economic considerations. ERCOT specifies that 

an RMR unit would not otherwise be operated unless it is necessary to provide 

voltage support, stability or management of localized transmission constraints 

under first contingency criteria where market solutions do not exist. 

Reliability Unit Commitment (RUC) - In ERCOT, a process to ensure that 

adequate resource capacity and ancillary service capacity are committed in the 

proper locations to serve the forecasted load. ERCOT conducts at least one DayAhead RUC (DRUC) and at least one Hourly RUC (HRUC) before each hour of 

the operating day, but additional RUCs are conducted when needed to evaluate 

and resolve reliability issues. 

Reserve Sharing Group - A group whose members consist of two or more 

balancing authorities that collectively maintain, allocate, and supply operating 

reserves required for each balancing authority’s use in recovering from 

contingencies within the group. 

Resource Entity (RE) - In ERCOT, Resource Entities either own or control a 

generation resource or behave as a load resource that can comply with ERCOT 

instructions to reduce electricity usage or provide an ancillary service. Each RE 

must also be represented by a Qualified Scheduling Entity (QSE), which 

establishes a control interface with ERCOT. 

Responsive Reserve Services (RRS) - As defined by ERCOT, an ancillary 

service that provides operating reserves that is intended to: (1) arrest frequency 

decay within the first few seconds of a significant frequency deviation on the 

ERCOT transmission grid using primary frequency response and interruptible 

load, (2) help restore frequency to its scheduled value to return the system to 

normal, (3) provide energy or continued load interruption during the 

implementation of an Energy Emergency Alert (EEA), and (4) provide backup 

regulation. RRS can be provided by generation or by load resources having 

Interruptible Responsive Reserve capability. 
Glossary 

Page 22 of 28 

Restoration - The process of returning generators and transmission system 

elements and restoring load following an outage on the electric system. 

Reticulated Pipelines - Natural gas pipelines with highly networked, web-like 

transmission lines, with many possible transportation paths for natural gas supplies 

to reach the desired marketplace. 

Rolling Blackouts - Also known as rotating outages, these are controlled, 

temporary interruptions of service to customers, most commonly initiated by 

switching off selected distribution circuits intended to reduce load during times of 

capacity shortfalls due to significant forced outages of generation and/or 

transmission facilities. The service interruptions are transferred from one group 

(or block) of customers to another over time so that no one group bears the entire 

burden of the necessary reduction in load. 

Rotor - The rotating component of a generator attached to the spinning shaft of 

the generator. In the large synchronous generators that are predominant in electric 

power systems, the rotor winding acts as an electromagnet that produces the 

magnetic field used to induce voltage in the stator windings. 

RUC Clawback Charge - In ERCOT, money returned by a Qualified Scheduling 

Entity (QSE) to ERCOT for a resource that was committed by the RUC process 

when the resource’s start-up and minimum energy costs are lower than those 

allowed by the prevailing RUC guaranteed payment. 

RUC Make-Whole Payment - In ERCOT, a payment made to a Qualified 

Scheduling Entity (QSE) for a resource that was committed by the RUC process 

when the resource’s start-up and minimum energy costs are less than revenues 

received. 

Salt Cavern - An underground natural gas storage cavern which has been 

developed in a salt dome by the solution mining process.

Scarcity Pricing Mechanism - A pricing mechanism based on the idea that under 

scarcity conditions, generating units will receive higher compensation for 

producing electricity. The additional revenue is intended to provide an incentive 

for investment in new generation facilities, and to promote overall system 

reliability. Under this mechanism, when available supply falls below a 

predetermined threshold, the price of additional power rises significantly. 

Scheduled Frequency - For power systems in North America, the scheduled 

frequency is normally 60.00 Hz. During periods of time error correction, which 
Glossary 

Page 23 of 28 

may last several hours, the scheduled frequency in a given interconnection is set to 

59.98 Hz to slow down clocks that use synchronous motors when they are running 

fast, and to 60.02 Hz to speed them up when they are running slow The fact that 

the clocks are running fast or slow is an indication that system frequency averaged 

slightly higher or lower than 60.00 Hz over a long duration, signaling the need for 

a correction. 

Sine Wave - The graphical representation of a mathematical function that 

describes the smooth, symmetrical, and periodic variation of a quantity that 

oscillates in magnitude or amplitude. In AC electric power systems, the voltage 

and current are characterized by sine waves having a frequency of 60 Hz. These 

waveforms, starting from a zero baseline, traverse a path that increases to a crest 

(positive maximum), then falls back to zero, continues downward to a trough 

(equal but opposite to the crest, i.e., in the negative direction), and back to zero in 

one-sixtieth of a second. 

Sluicing/Service Water Systems - A system used to remove bottom ash from 

many coal-fired boilers. 

Southwest Power Pool (SPP) - A Regional Transmission Organization serving 

members in Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New 

Mexico, Oklahoma, and Texas (non-ERCOT). SPP is connected to and is part of 

the Eastern Interconnection. 

Southwest Reserve Sharing Group (SRSG) - A pool of electric load-serving 

entities in Arizona, New Mexico, Nevada, southern California, and El Paso, Texas 

that have entered into an agreement to share contingency reserves. SRSG is a 

NERC Registered Entity that administers certain requirements on behalf of its 

members related to disturbance control and emergency operations. SRSG is 

connected to and is part of the Western Interconnection. 

Spinning Reserve - Unloaded generation capacity that is synchronized and 

available to serve additional demand. 

Stability - The ability of an electric power system to maintain a state of 

equilibrium during normal and abnormal system conditions or disturbances. 

Instances of instability are serious because they have the potential to cause 

widespread outages in the power system, and possibly even in the entire 

interconnection. 

Static VAR Converter / Compensator (SVC) - A combination of shunt reactors 

and shunt capacitors whose switching is precisely controlled by power electronics 
Glossary 

Page 24 of 28 

to automatically manage reactive power injections and withdrawals from the 

power system to help maintain proper transmission voltage. 

Stator - The stationary component of a motor or generator surrounding but not 

making physical contact with the spinning rotor in the typical cylindrical 

design/construction. 

Substation - A site that houses circuit breakers, disconnect switches, transformers, 

reactors, capacitors, and other equipment serving as an electrical hub in the power 

system, especially at interfaces between different voltage levels. The prefix “sub” 

distinguishes substations from generating stations. A central control house is often 

provided to house control and protective equipment. 

Supervisory Control and Data Acquisition Systems (SCADA) - A system of 

remote control and telemetry used to monitor and control a power system or a 

natural gas transportation or distribution system. 

Synchronize - The process of bringing two electrical systems together by closing 

a circuit breaker at an interface point when the voltages and frequencies are 

properly aligned. Also, when generators are brought on-line, they are said to be 

synchronized to the system. 

 

Synchronous - To be in-step with a reference. The rotor of a synchronous 

machine, be it a motor or a generator, spins in unison with the power system in 

terms of frequency (see Synchronous Speed, below). 

Synchronous Speed - The speed at which the rotor of a synchronous generator 

must rotate in order to stay in synchronism with the rotating magnetic field of the 

system. The synchronous speed is determined by the frequency of the power 

system and the number of magnetic poles in the rotor. For example, the 

synchronous speed of a two pole steam-turbine generator in a 60 Hz system is 

3600 revolutions per minute (rpm), while the synchronous speed of a 24 pole 

hydro generator is only one-twelfth of that, or 300 rpm. 

 

System (Electric Power) - A combination of generation, transmission, and 

distribution facilities, equipment, and components. 

System Operator - An individual at a control center (Balancing Authority, 

Transmission Operator, Generator Operator, Reliability Coordinator) whose 

responsibility it is to monitor and control that electric system in real time. 
Glossary 

Page 25 of 28 

System Operating Limit (SOL) - The value of any of a number of electrical 

quantities such as real power flow (in MW), total power flow (real plus reactive) 

(in MVA), voltage (in kV), current (in amperes) or frequency (in Hz) that satisfies 

the most limiting of the prescribed operating criteria for a specified system 

configuration to ensure that established reliability criteria are satisfied. 

Telemetry - Equipment for measuring a quantity (amperes, volts, MW, etc.) and 

transmitting the result via a telecommunication system to a remote location for 

indication and/or recording. 

Texas Reliability Entity (TRE) - Texas Reliability Entity, Inc. is authorized by 

NERC to develop, monitor, assess, and enforce compliance with NERC Reliability 

Standards within the geographic boundaries of the ERCOT region. In addition, 

TRE has been authorized by the Public Utility Commission of Texas (PUCT) and 

is permitted by NERC to investigate compliance with the ERCOT Protocols and 

Operating Guides. TRE is independent of all users, owners, and operators of the 

bulk power system. 

Thermal Insulation - Any material which slows down or retards the flow or 

transfer of heat. 

Transformer - A type of electrical equipment in the power system that operates 

on electromagnetic principles to increase (step up) or decrease (step down) 

voltage. 

Transient Flow or Unsteady State Flow - The process which involves changes 

within the control volume with time. 

Transmission - An interconnected group of lines and associated equipment 

operated at high voltage levels in the range of 100 kV to 765 kV in North America 

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 Operator - The entity responsible for the reliability of its “local” 

transmission system, and that operates or directs the operations of the transmission 

facilities. 

Transmission Owner - The entity that owns and maintains transmission facilities, 

including, but not limited to, overhead and underground transmission lines, 

substations, transformers, circuit breakers, capacitor banks and busses. 
Glossary 

Page 26 of 28 

Transmission Service Provider (TSP) - As defined by NERC, an entity that 

administers the transmission tariff and provides transmission service to 

transmission customers under applicable service agreements. ERCOT specifies 

that TSPs own or operate transmission facilities. 

Treatment Plant - A plant designed primarily to remove undesirable impurities 

from natural gas to render the gas marketable. Examples of these impurities are 

water, water vapor, sulfur compounds, carbon dioxide, nitrogen and helium. 

Turbine - A rotating mechanical device driven by the force of a working fluid. 

The working fluid is typically steam, water, combustion gases or, in the case of 

wind turbines, air. 

Under Frequency Load Shedding (UFLS) - The automatic disconnection or 

tripping of customer load based on a decline in system frequency. The set points 

are predetermined. For example, a utility may trip 5% of their connected load if 

frequency falls below 59.3 Hz, an additional 10% if it falls below 58.9 Hz, and a 

final 10% if it falls below 58.5 Hz. The purpose of UFLS is to arrest the 

frequency decline accompanying major system disturbances generally involving 

the sudden loss of large amounts of generation or multiple transmission line 

tripping that results in the formation of an electrical island in which the remaining 

generation is inadequate to supply the load, thereby forestalling a complete system 

collapse. 

Under Voltage Load Shedding (UVLS) - The tripping of customer load based on 

a decline in system voltage. For example, a utility may trip 5% of their connected 

load if voltage falls below 92% of nominal and an additional 10% of their load if 

voltage falls below 90% of nominal. The purpose of UVLS is typically to avoid a 

voltage collapse, but it can also be used to avoid overloading transmission 

facilities during contingency conditions when other transmission facilities trip or 

are forced out of service. 

Unit Commitment - The process of selecting which generating units will be 

placed on line to serve the load and reserve requirements. 

Verbal Dispatch Instruction - In ERCOT, a dispatch instruction issued by 

operators in the control center to a generating unit or units, load resource, or their 

Qualified Scheduling Entities (QSEs) orally over the telephone, as opposed to one 

issued in writing or issued automatically by a control system and delivered 

electronically via telecommunications. 
Glossary 

Page 27 of 28 

Vertically Integrated Utility - An electric utility company or a federal, state, or 

municipal agency that owns and operates all aspects of the power system in its 

franchise service territory, i.e., generation, transmission, and distribution. The 

ownership of certain facilities may be shared or held wholly by others, but the 

vertically integrated utility still controls the power system in the territory. 

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). 

Well Freeze-offs - Natural gas flow blockages resulting from water vapor freezing 

or the formation of crystal hydrates in the gas stream. 

 

Wellhead - The assembly of fittings, valves, and controls located at the surface 

and connected to the flow lines, tubing, and casing of the well so as to control the 

flow from the reservoir. 

Wellhead Choke - Points at the wellhead where flow and pressure are primarily 

controlled. 

Western Electricity Coordinating Council - The Regional Entity responsible for 

coordinating and promoting bulk electric system reliability in the Western 

Interconnection. 

 

Wheeling (Natural Gas) - The transportation of customer-owned gas by a 

transmission company for the customer at a pre-determined cost to the customer.

Windbreaks - Temporary or permanent structures intended to obstruct, or serve as 

a barrier against, the wind for the comfort and safety of people and/or the 

protection of property or equipment. 

 

Wind Chill Factor - The term “Wind Chill Factor,” is often used to explain the 

additional heat loss people experience through convection cooling when exposed 

to the wind. Whenever there is a temperature difference at a surface, e.g., the 

difference between normal body temperature and ambient air at a lower 

temperature on the surface of human skin, heat is conducted across the surface 

from the warmer body to the cooler air. In the process, the layer of air on the 

surface is warmed and forms a thermal boundary which tends to slow the rate of 

heat loss. Wind accelerates the heat loss by literally sweeping away that boundary 

layer and replacing it, continuously, with air at the ambient temperature. This 

acceleration of heat loss caused by the wind makes people to feel that the air 

temperature is colder than it actually is. This feeling is quantified by assigning a 
Glossary 

Page 28 of 28 

stationary air temperature, known as the Wind Chill Temperature, which yields an 

equivalent perception of cold. 

Zonal Market - A market for electric energy divided into regional pricing zones. 

Generators within a zone receive the same price for the power they provide, and 

transmission lines crossing zonal boundaries are assessed additional costs due to 

market congestion when the power flowing through them reaches operational 

constraints. 
Appendix: Task Force Members 

FERC Staff 

Office of Administrative Litigation 

James Ballard 

Pamela Swinson-Okhomina 

Office of Electric Reliability 

David Cole 

Justin Cunningham 

Kent Davis 

Kenneth Githens 

Donald Hargrove 

Nick Henery 

Loye Hull 

Raymond Orocco-John 

Monica Taba 

Daniel Taft 

Richard Waggel 

Office of Energy Market 

Regulation 

Adam Bednarczyk 

Julie Graf 

James Sarikas

John Yakobitis

Office of Energy Policy & 

Innovation 

Pamela Silberstein 

Office of Energy Projects 

Joseph Caramanica 

Michael McGehee 

Office of Enforcement 

Ahuva Battams 

Todd Brecher 

Gregory Campbell 

Gloria Cloteykine 

Catherine Collins 

Neil Dyson

Christopher Ellsworth 

Sidney Gerson 

Robert Hartwell 

Kenneth Kohut 

Kathryn Kuhlen 

Gary Mahrenholz 

James Meade 

Cristina Melendez 

Roger Morie 

Michelle Norman 

Thomas Pinkston 

Heather Polzin 

Eric Primosch 

Charles Reusch 

Janette Richardson 

Timothy Shear 

Gabriel Sterling III 

Paul Varnado 

Lee Ann Watson 

Young Yoo 

Office of External Affairs 

Judy Eastwood 

Mark Hershfield 

Sandra Waldstein 

Office of the General Counsel 

Julie Greenisen 

Renee Wright 

NERC Staff 

Eric Allen 

Bob Cummings 

G. Michael Curley 

Tom Galloway 

Robert Kenyon 

Mark Lauby 

Steve Masse 

Earl Shockley 

Jule Tate 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

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Appendix: Legislative and Regulatory Responses by the States 

Page 1 of 6 

. 

The natural gas and electricity shortages that occurred in the Southwest in 

early February 2011 seriously affected three states: Arizona, New Mexico and 

Texas.1

 Each state took different regulatory and legislative actions in response to 

the events. As part of its inquiry, the task force contacted state regulators and 

followed subsequent legislative and regulatory developments. The following 

section describes the actions taken by each state. 

Arizona 

In Arizona, approximately 19,000 customers in the Tucson and Sierra Vista 

areas lost gas service on February 3, 2011. Most of those customers had their 

service restored within four days.2

 The Arizona Corporation Commission (ACC), 

which among other things, regulates public utilities in the state, took the lead in 

reviewing the circumstances surrounding the gas outages.3

 One commissioner 

met with Southwest Gas Corporation representatives on February 3,4

 and another 

sent data requests to four impacted pipelines on February 16, 2011 5

On March 2, 2011 the ACC held an open meeting on the Southern Arizona 

gas outages, with witnesses from Southwest Gas Corporation and El Paso Natural 

Gas Company testifying. At the hearing, representatives from both companies 

stated that cold weather was the primary reason for the outage, as demand far 

outweighed supply during the record-low cold temperatures. 

 

1 The task force contacted regulatory staff with the Public Service Commission of Nevada and 

the California Public Utilities Commission, who informed us that they did not experience a 

substantial, direct impact from the February 2011 gas supply shortages, and that no related 

inquiries or proceedings were underway in their states. 

2

 See Alex Dalenberg, ACC Meeting will Delve into SW Gas Outage, Arizona Daily Star (Feb. 13, 

2011). 

3

 The Arizona legislature did not hold hearings or take any legislative actions in response to the 

outages. 

4 See Letter from Commissioner Barbara Burns to the Chairman and Commissioners of the 

Arizona Corporation Commission, Docket No. G-00000C-11-0081 (Feb. 11, 2011), available at

http://images.edocket.azcc.gov/docketpdf/0000123284.pdf (last visited Aug. 5, 2011). 

5 See Letter from ACC Commissioner Sandra Kennedy to Southwest Gas Corporation; El Paso 

Natural Gas Company; UNS Gas, Inc.; and Transwestern Pipeline Company, LLC, Docket No. 

G-00000C-11-0081 (Feb. 7, 2011), available at http://images.edocket.azcc.gov/ 

docketpdf/0000123172.pdf (last visited Aug. 5, 2011). 
Appendix: Legislative and Regulatory Responses by the States 

Page 2 of 6 

The ACC held two follow up meetings, on April 6, 2011 and April 7, 2011, 

to gather information from customers affected by the outages.6 No further action 

has taken place in the ACC proceeding. 

New Mexico 

More than 30,000 customers lost gas service in New Mexico on February 2 

and 3, 2011, some for as long as a week. Shortly thereafter, a New Mexico State 

Senator asked the state’s Attorney General to look into the causes of the outages,7

and the legislature announced that it would hold hearings. On February 11, 2011, 

a hearing was held before the full New Mexico Senate, which heard testimony 

from some of the individuals who lost gas service and from representatives of 

New Mexico Gas Company (NMGC), El Paso Natural Gas Company, and the 

New Mexico Public Regulation Commission (PRC). 

 

On February 14, 2011, the New Mexico Senate directed the PRC to 

convene a task force to investigate how and why New Mexico consumers lost 

natural gas service and to make recommendations on how to prevent such loss of 

service in the future.8

 

On March 16, 2011, Governor Susana Martinez signed a bill9

 into law that 

created a state task force to investigate the causes of the outages and to make 

recommendations on how to prevent similar outages in the future.10 As of the date 

of this report, the report from the Natural Gas Emergency Investigation Legislative 

Task Force is pending. 

 

6 See Tucson Residents Tell Commissioners About Freezing Nights and No Natural Gas Service, 

Associated Press, (Apr. 8, 2011). 

7 See State Senator Carlos Cisneros, Senator Calls on AG to Immediately Investigate Gas 

Outage (Feb. 8, 2011), available at http://www.democracyfornewmexico.com/democracy

_for_new_mexico/2011/02/sen-carlos-cisneros-requests-immediate-investigation-into-gasoutage-by-ag.html (last visited Aug. 5, 2011). 

8

 SM 30 (Engrossed), 2011 Regular Session (NM, 2011), available at http://www.nmlegis.gov/

Sessions/11%20Regular/final/SM030.pdf (last visited Aug. 5, 2011). 

9

 HB 452 (Engrossed), 2011 Regular Session (NM, 2011), available at http://www. 

nmlegis.gov/Sessions/11%20Regular/final/HB0452.pdf (last visited Aug. 5, 2011). 

10 See House Executive Message No. 2 (Mar. 16, 2011) available at http://www.governor. 

state.nm.us/uploads/FileLinks/7bbb779a53dd4071933247333d38f22c/House%20Executive%20

Message%202.pdf (last visited Aug. 5, 2011). 
Appendix: Legislative and Regulatory Responses by the States 

Page 3 of 6 

 

The United States Senate Committee on Energy and Natural Resources held 

a field hearing in New Mexico on February 21, 2011 to receive testimony 

regarding the natural gas service disruptions in New Mexico and the reliability of 

regional energy infrastructure.11 The Committee heard testimony from three 

different panels, and sent follow up questions to the Federal Energy Regulatory 

Commission.

The PRC opened its investigation into the outages on February 11, 2011.12 

In its order opening the inquiry, the PRC directed NMGC, Public Service 

Company of New Mexico, El Paso Electric Company, and Southwestern Public 

Service Company to provide testimony responding to specific questions within 30 

days of the order.13 

At the same time, the PRC also initiated a non-docketed proceeding entitled 

the NMPRC Informal Task Force Investigation into Severe Weather Cascading 

Events. The Informal Task Force, which included representatives of several New 

Mexico utilities,14 PRC staff, the state Attorney General’s Office, several 

municipalities, and the general public, was charged with developing a summary of 

the weather event, identifying the causes, determining how to mitigate the impact 

of future events, and reviewing the policies and rules of the PRC and other New 

Mexico agencies.15

On May 3, 4, and 5, 2011, the PRC held hearings on the outages, hearing 

testimony from gas company representatives and other parties, including 

11 See Recent Natural Gas Service Disruptions in New Mexico and Reliability of Regional Energy 

Infrastructure before the Senate Energy and Natural Resources Committee, 112th Congress (Feb. 

21, 2011) available at http://energy.senate.gov/public/index.cfm?FuseAction=Hearings. 

Hearing&Hearing_ID=169bb12f-e360-3d3f-378c-4a762ddf0b56 (last visited Aug. 5, 2011). 

12 See Press Release, Public Regulation Commission, NMPRC initiates investigation into Natural 

Gas Delivery Failure (Feb. 10, 2011), available at http://www.nmprc.state.nm.us/news/pdf/2011-

02-10-gasinvestigation.pdf (last visited Aug. 5, 2011). 

13 In the Matter of an Investigation into New Mexico Gas Company’s Curtailments of Gas 

Deliveries to New Mexico Consumers, Order Initiating Investigation and Setting Hearing, New 

Mexico Public Regulation Commission, Case No. 11-00039-UT (Feb. 15, 2011), available at

http://164.64.85.108/infodocs/ 2011/2/PRS20156381DOC.PDF (last visited Aug. 5, 2011). 

14 The utilities are Public Service Company of New Mexico, Southwestern Public Service 

Company, El Paso Electric Company, NMGC, Zia Natural Gas Company, and Raton Natural Gas 

Company. 

15 February 2011 Severe Cold Weather Investigations & Status, Presentation before the Natural 

Gas Emergency Investigation Legislative Task Force (July 25, 2011) at pp. 1-2. 
Appendix: Legislative and Regulatory Responses by the States 

Page 4 of 6 

 

representatives of the affected municipalities. Since then, the parties have 

submitted additional written testimony and briefs to the PRC. As of the date of 

this report, the PRC’s investigation is still pending. 

Texas 

With several million consumers affected by electrical blackouts, the State 

of Texas was severely impacted by the extreme weather events of early February. 

Two regulatory agencies in Texas have jurisdiction over the industries in question 

– the Public Utilities Commission of Texas (PUCT) (which has primary 

jurisdiction over the electrical power industry) and the Texas Railroad 

Commission (TRC), whose jurisdiction includes the natural gas industry. 

The PUCT reacted at once to the electric outages, asking the state’s 

independent energy market monitor on February 4, 2011 to investigate whether 

power generators, pipeline companies or others broke market rules.16 

The PUCT also directed the Texas Reliability Entity, Inc. (TRE) to 

investigate the Electric Reliability Council of Texas (ERCOT) Energy Emergency 

Alert Level 3 that occurred on February 2, 2011. At the same time, the PUCT 

asked El Paso Electric Company to investigate and report back on the weatherrelated issues surrounding this event. 

On February 8, 2011, the TRC held the first state hearing on the outages. 

One of the witnesses, the TRE, addressed the impact of the rolling blackouts on 

natural gas service.17 

On February 15, 2011, the Texas Senate’s Committee on Natural Resources 

and Committee on Business and Commerce jointly convened a hearing to discuss 

the causes of the rolling blackouts.18 The hearing included testimony from the 

PUCT, the TRC, the Texas Commission on Environmental Quality, ERCOT, and 

the Office of Public Utility Counsel. The House Committee on State Affairs also 

held a hearing on the causes of the rolling blackouts on February 17, 2011. 

16 See Rebecca Smith, Texas to Probe Rolling Blackouts, Wall Street Journal (Feb. 7, 2011). 

17 See Press Release: Railroad Commission Emergency posted item to be discussed at 1:30 P.M 

today, Texas Railroad Commission (Feb. 8, 2011), available at http://www.rrc.state.tx.us/ 

pressreleases/2011/020811.php (last visited Aug. 5, 2011). 

18 See Chris Tomlinson, Texas Senate Investigates Power Outages, The Associated Press (Feb. 

16, 2011). 
Appendix: Legislative and Regulatory Responses by the States 

Page 5 of 6 

 

Prompted by the hearings, the legislature enacted a bill to address the 

perceived causes of the rolling blackout.19 On June 17, 2011, that bill was signed 

into law.20 

The law directs the PUCT to prepare a “weather emergency preparedness 

report on power generation weatherization preparedness.” 21 Under the law, the 

PUCT must review the emergency operations plans it currently has on file,22

determine the Texas electricity grid’s ability to operate continuously during 

extreme weather events in the upcoming year, consider the upcoming year’s 

forecasted weather patterns, and recommend improvements to emergency 

operations plans to ensure electric service reliability.23 In addition, the law 

permits the PUCT to require entities to update their emergency operations plan 

when it does not contain information sufficient to determine whether that entity 

can perform during adverse weather. The law also permits the PUCT to adopt 

rules implementing the legislation.24 

On April 21, 2011, the Independent Market Monitor reported that “there 

was no evidence of market manipulation or market power abuse” within the 

ERCOT region.25 The Independent Market Monitor similarly determined “that the 

ERCOT real-time and day-ahead wholesale markets operated efficiently and the 

outcomes are consistent with the ERCOT energy-only wholesale market design.”26 

19 SB 1133, 82 Leg., Reg. Sess. (TX, 2011), available at http://www.capitol.state. 

tx.us/tlodocs/82R/billtext/pdf/SB01133I.pdf#navpanes=0 (last visited Aug. 5, 2011). 

20 Another bill was introduced which would have required the PUCT to develop a process for 

obtaining emergency reserve power generation capacity, but it was not considered during the 

legislative session. HB 1986, 82 Leg., Reg. Sess. (TX, 2011), available at http://www. 

capitol.state.tx.us/tlodocs/82R/billtext/pdf/ HB01986I.pdf#navpanes=0 (last visited Aug. 5, 

2011). 

21 SB 1133, 82 Leg., Reg. Sess. (TX, 2011), available at http://www.capitol.state.tx.us/ 

tlodocs/82R/billtext/pdf/SB01133I.pdf#navpanes=0 (last visited Aug. 5, 2011). 

22 P.U.C. Subst. R. 25.53(c)(2) (TX, 2011). 

23 S.B. 1133, 82 Leg., Reg. Sess. (TX, 2011), available at http://www.capitol.state.tx.us/tlodocs/ 

82R/billtext/pdf/SB01133I.pdf#navpanes=0 (last visited Aug. 5, 2011). 

24 Id. 

25 Investigation of the ERCOT Energy Emergency Alert Level 3 on February 2, 2011, Potomac 

Economics LTD. (April 21, 2011), available at http://www.puc.state.tx.us/files/IMM_Report_ 

Events_020211.pdf at 2 (last visited Aug. 5, 2011). 

26 Id.
Appendix: Legislative and Regulatory Responses by the States 

Page 6 of 6 

 

On May 13, 2011, the TRE issued a report on whether ERCOT Protocols 

and Operating Guides were followed during the period leading up to the Energy 

Emergency Alert event.27 The TRE concluded that event “was caused by either 

insufficient or ineffective preparation of generating facilities for prolonged 

freezing weather.”28 The report went on to find that “ERCOT Market Participants 

committed potential violations of the ERCOT Protocols and Operating Guides in 

connection with the event.”29 The TRE will conduct additional investigations as 

necessary and forward information to the PUCT for further action, as 

appropriate.30 

Also, on May 13, 2011, PUCT staff issued a report on El Paso Electric 

Company’s activities during the weather event.31 PUCT staff did not identify any 

violations of the Public Utility Regulatory Act or the PUCT’s Substantive Rules.32 

The report, however, did conclude that “designed cold weather tolerances of El 

Paso Electric Company’s current generation equipment and/or weatherization 

preparation were inadequate to prevent failures in the conditions during the event 

timeframe.”33

27 Protocol and Operating Guide Compliance Report of the ERCOT Emergency Alert (EEA) 

Level 3 on February 2, 2011, Texas Reliability Entity, Inc. (May 13, 2011), available at

http://www.puc.state.tx.us/files/TX_RE_EEA_Protocol_Comp_Report.pdf (last visited Aug. 5, 

2011). 

28 Id. at 1. 

29 Id. 

30 Id.

31 Report on El Paso Electric Company Weather-Related Issues in February 2011, Staff of the 

Public Utilities Commission of Texas (May 2011), available at http://www.puc.state.tx.us/ 

files/EPE_Report_05-13-11.pdf (last visited Aug. 5, 2011). 

32 Id. at 4. 

33 Id. at 1. 
Appendix: Categories of NERC Registered Entities 

Page 1 of 3 

All entities that 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 

load-interchange-generation balance within 

BA area, and supports interconnection 

frequency in real-time. 

Distribution 

Provider 

DP Provides and operates the “wires” between 

the transmission system and the end-use 

customer. For those end-use customers 

who are served at transmission voltages, the 

Transmission Owner also serves as the DP. 

Thus, the DP is not defined by a specific 

voltage, but rather as performing the 

distribution function at any voltage. 

Generator Operator GOP The entity that operates generating unit(s) 

and performs the functions of supplying 

energy and interconnected operations 

services. 

Generator Owner GO Entity that owns and maintains generating 

units. 

Interchange 

Authority 

IA The responsible entity that authorizes 

implementation of valid and balanced 

Interchange Schedules between Balancing 

Authority Areas, and ensures 

communication of Interchange information 

for reliability assessment purposes. 

Load-Serving 

Entity 

LSE Secures energy and transmission service 

(and related interconnected operations 

services) to serve the electrical demand and 

energy requirements of its end-use 

customers. 

Planning Authority PA The responsible entity that coordinates and 

integrates transmission facility and service 

plans, resource plans, and protection 

systems. 
Appendix: Categories of NERC Registered Entities 

Page 2 of 3 

Purchasing-Selling 

Entity 

PSE The entity that purchases or sells and takes 

title to energy, capacity, and interconnected 

operations services. PSE may be affiliated 

or unaffiliated merchants and may or may 

not own generating facilities. 

Reliability 

Coordinator 

RC The entity that is the highest level of 

authority who is responsible for the reliable 

operation of the bulk power system, has the 

wide area view of the bulk power 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 RC 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. 

Reserve Sharing 

Group 

RSG A group whose members consist of two or 

more Balancing Authorities that 

collectively maintain, allocate, and supply 

operating reserves required for each BA’s 

use in recovering from contingencies within 

the group. Scheduling energy from an 

adjacent BA to aid recovery need not 

constitute reserve sharing provided the 

transaction is ramped in over a period the 

supplying party could reasonably be 

expected to load generation in (e.g., ten 

minutes). If the transaction is ramped in 

quicker, (e.g., between zero and ten 

minutes) then, for the purposes of 

disturbance control performance, the areas 

become a RSG. 

Resource Planner RP The entity that develops a long-term 

(generally one year and beyond) plan for 

the resource adequacy of specific loads 

(customer demand and energy 

requirements) within a PA area. 
Appendix: Categories of NERC Registered Entities 

Page 3 of 3 

Transmission 

Owner 

TO The entity that owns and maintains 

transmission facilities. 

Transmission 

Operator 

TOP The entity responsible for the reliability of 

its local transmission system and operates 

or directs the operations of the 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 PA area. 

Transmission 

Service Provider 

TSP The entity that administers the transmission 

tariff and provides transmission service to 

transmission customers under applicable 

transmission service agreements. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

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Appendix: Electricity - How It Is Generated and Distributed 

Page 1 of 11

Electricity is one of the most widely used forms of energy in the 

industrialized world. According to the U.S Energy Information Administration, in 

2009 the U.S. electric utility net generation was 2,372,776 gigawatt hours. Table 

1 shows the share of net electricity generation by energy source in the United 

States. 

Energy Source Net Generation (%) 

Coal 44.5 

Nuclear 20.2 

Natural Gas 23.3 

Hydro 6.8 

Oil (Petroleum) and other 1.6 

Renewables 3.6 

Table 1: Share of net electricity generation in 2009 in the U.S. 

(Source: U.S. Energy Information Administration) 

Electric power is produced at generating stations and transmitted via 

transformers, transmission lines, switching devices and protection and control 

equipment for delivery to end users. The electric power system as shown in figure 

1 is an integrated system made up of generation, transmission and distribution 

subsystems. 

Figure 1 – Basic structure of the electric system (NERC) 

Generation 

Generating plants produce electricity by burning fuels such as oil, coal, 

natural gas, or lignite to create steam that drives a turbine, which in turn drives a 

turbine generator shaft. In a coal-fired plant (figure 2), coal is ground by 

pulverizers into fine powder, mixed with pre-heated air and injected into a 

combustor, where it is ignited. The hot combustion gas rises through the boiler 

and heats water that enters the steam generator. The partially vaporized water 

enters the steam drum, where steam is separated from the water. The remaining 
Appendix: Electricity - How It Is Generated and Distributed 

Page 2 of 11

water cycles through the boiler again, and through tubes lining the furnace walls. 

The steam is passed through another section of the boiler known as the 

superheater, where the temperatures are increased to well above boiling. 

Figure 2 – Typical drum-type coal/lignite boiler plant 

(PJM Generation Basics) 

The superheated steam, now at very high pressure, passes through a high 

pressure turbine (shown in figure 3), causing the turbine to spin and turning the 

shaft of an electrical generator. After passing through the high pressure turbine, 

the steam is piped back to the boiler to be reheated, then enters an intermediate 

pressure turbine and low pressure turbine before it passes through a condenser, 

where the steam is converted back to water, which is usually cycled back to the 

steam generator for reuse. The mechanical energy generated by the spinning 

generator shaft is converted to electrical energy for delivery to the electric power 

system. 
Appendix: Electricity - How It Is Generated and Distributed 

Page 3 of 11

Figure 3: Typical coal burning generating plant with 

cooling tower (Department of Energy) 

In nuclear generating stations, steam is also used to drive a turbine. 

However, the energy required to produce the steam is derived from nuclear fission, 

typically fueled by uranium. 

Wind turbines use blades to collect the energy of the wind. As wind blows, 

it flows over the blades, causing them to turn. The blades are connected to a gear 

box with a drive shaft that turns an electric generator to produce electricity. 
Appendix: Electricity - How It Is Generated and Distributed 

Page 4 of 11

In hydroelectric plants, the gravitational force of water flowing downhill 

drives the turbine generator shaft (as shown in figure 4). The mechanical energy 

of the spinning shaft is then converted to electrical energy. 

Figure 4: Typical hydroelectric generator 

(Energy Information Administration) 

Electric energy can also be produced by simple cycle or combined cycle 

combustion turbines or internal combustion engines, which usually burn natural 

gas or fuel oil. The combustion turbine drives an electric generator to produce 

electricity. One advantage of combustion turbines is that they can be started 

quickly, making them suitable for emergencies and during peak periods, when 

demand for electricity is at its highest. 

A combined cycle combustion turbine is shown in figure 5. Note: a simple 

cycle combustion turbine plant does not include a heat recovery steam generator 

(HRSG), steam turbine, and a second generator as depicted in figure 5. 
Appendix: Electricity - How It Is Generated and Distributed 

Page 5 of 11

Figure 5: Combined cycle turbine generator with steam generator and HRSG 

(Washington State University) 

Conversion of Mechanical Energy to Electrical Energy 

A generator works on the principle of electromagnetic induction, 

discovered by scientist Michael Faraday between 1831 and 1832. Faraday 

discovered that the flow of electric charges could be induced in a coil of wire by 

passing a magnet through the coil. This movement creates a voltage difference 

between the two ends of the wire or electrical conductor, which in turn causes the 

electric charges to flow, thus generating electric current. 

 

Every modern generator consists of two main components: the rotor (the 

moving part) and the stator (the stationary part). In an AC generator, the rotor 

spins inside the stator. A mechanical device is used to spin or turn the rotor. With 

every rotation, the changing magnetic field creates a current in the stator windings. 

A generator does not actually make electrical energy. Instead, it uses mechanical 

energy supplied to it to cause the movement of electric charges present in the wire 

of the stator windings, thereby generating an electric current that is supplied to the 

grid. A generator is akin to a water pump, which causes the flow of water but 

does not actually create the water flowing through it. 

Most large power generators are three-phase generators and have three 

windings (A, B and C phases), one winding for each phase. In a three-phase 
Appendix: Electricity - How It Is Generated and Distributed 

Page 6 of 11

generator, a rotor rotates at the center of the three windings creating the changing 

magnetic field. Each one of the winding sets produces a voltage. Each phase 

voltage has a 120o phase angle separation from the other two phase voltages as 

shown in figure 6. The waveform of the induced voltages is a sine wave (also 

shown in figure 6) in which each phase voltage periodically reverses direction. 

The current produced from this generator is known as alternating current (AC). 

Figure 6: Three-phase generator diagram & waveform 

(Electric Power Research Institute) 

Figure 7: Three-phase power generator 

(Electric Power Research Institute) 

 There are two general types of AC generator: synchronous and 

asynchronous. The terms synchronous and asynchronous refer to the relationship 

between the generator rotor’s speed of rotation and the power system speed. 

Power system speed (or synchronous speed) is the speed of rotation of the AC 

electrical system to which the generator is connected. When a generator is 

connected to the power system, the rotating magnetic field of the generator is 

synchronized with the rotating magnetic field that already exists in the three-phase 

system. An AC generator can be designed to rotate in-step, or in synchronism, 
Appendix: Electricity - How It Is Generated and Distributed 

Page 7 of 11

 

with the power system’s rotating field. This type of AC generator is called a 

synchronous machine. Most utility power generators and most large motors are 

synchronous machines. 

 An AC generator’s rotor can also be designed to rotate slower or faster than 

synchronous speed. This type of machine is called an asynchronous machine. 

Most small AC motors are asynchronous machines. Induction machines – 

alternating current machines in which power is supplied to the rotor by means of 

electromagnetic induction – are the most common type of asynchronous machines. 

Most wind turbines use induction generators. 

 Synchronous machines are the most common type of generator used for 

large-scale power production, and can be used to produce both active1

 and reactive 

power

2

. This is in contrast to conventional induction machines, which cannot 

produce reactive power, only active power. The latest design for wind turbine 

generators, however, includes sophisticated power electronic interfaces and 

controls that allow these units to inject or absorb reactive power from the grid, as 

well as providing frequency response, inertial response, etc. 

Transmission 

 Electricity from generators is stepped up to higher voltages by means of a 

generator step-up transformer for transportation in bulk over transmission lines. 

Operating the transmission lines at high voltage (100,000 to 765,000 volts) 

reduces electricity losses from conductor heating and allows power to be 

transported economically over long distances. The higher the voltage, the lower 

the current flow needed to transmit the same amount of power. Since losses are 

related to high current flow, lowering the current lowers the losses. Transmission 

lines are interconnected at switching stations and substations to form a network of 

lines and stations called a power grid. Electricity flows through the interconnected 

network of transmission lines from the generators to the loads in accordance with 

the laws of physics, along paths of least resistance. When power arrives near a 

load center, it is stepped down to lower voltages by means of step-down 

transformers, usually located at substations throughout the system. These 

substations contain other equipment such as communication, control, protection 

1

 Active Power is the useful or working energy supplied by a power source. It is used to 

perform work such as lighting a room or heating a building or turning a motor shaft. 

2

 Reactive Power is used to support the magnetic and electric fields necessary to operate 

power system equipment. Reactive power is never consumed by the power system and is stored in 

the electrical and magnetic fields that exist in the system. 
Appendix: Electricity - How It Is Generated and Distributed 

Page 8 of 11

and metering equipment. The Bulk Power System (BPS) is predominantly an AC 

system, as opposed to a direct current (DC) system, because of the ease and low 

cost with which voltages in AC systems can be converted from one level to 

another. 

 Three-phase AC power is normally transmitted by overhead AC circuits, 

which consist of aluminum conductors with a reinforcing steel core suspended 

from metal towers by porcelain insulators, as shown in figure 8. Underground 

transmission circuits can also be used, but are used less frequently than overhead 

circuits due to the costs involved, as well as the associated reduction in current 

carrying capacity. Transmission cables installed underground must be insulated, 

increasing cost and limiting the current carrying capability of the system. 

High Voltage Direct Current (HVDC) systems are usually employed for special 

purposes, including the transmission of large blocks of power from remote sources 

to load centers or interconnection to systems that operate at different frequencies. 

A DC transmission system consists of a two conductor line connecting two AC 

systems. A rectifier at one end of the line converts the AC voltage to a constant 

DC value and an inverter at the other end reconverts the DC into AC. 

Figure 8: Transmission tower (National Grid) 

 While the power system is commonly referred to as “the grid,” there are 

actually three distinct power grids or interconnections in the United States. Figure 

9 shows the various interconnections. The Eastern Interconnection includes the 

eastern two-thirds of the continental United States and Canada from Saskatchewan 

east to the Maritime Provinces. The Western Interconnection includes the western 
Appendix: Electricity - How It Is Generated and Distributed 

Page 9 of 11

third of the continental United States (excluding Alaska), the Canadian provinces 

of Alberta and British Columbia, and a small part of Mexico near the California 

border. The third interconnection comprises most of the state of Texas. The three 

interconnections are electrically independent from each other except for a few 

small DC ties. Within each interconnection, electricity is produced the instant it is 

used, and flows over virtually all transmission lines from generators to loads. The 

frequency at which the various interconnects were designed to operate is 60 Hz. 

Figure 9: North American interconnections (NERC) 

System Frequency

 If the total demand from customers is not in balance with the available 

generation, the electrical frequency of an entire interconnection will deviate from 

60 Hz. The target frequency is referred to as the scheduled frequency. When the 

actual frequency deviates from the scheduled frequency, a frequency deviation has 

occurred. For example, if the scheduled frequency is 60 Hz but the actual 

frequency is 59.95 Hz then a -0.05 Hz frequency deviation has occurred. When 

the supply of generation to the transmission system is inadequate, the frequency 

falls below 60 Hz. When too much generation is supplied to the transmission 

system, the frequency rises above 60 Hz. Individual power systems within an 

interconnection work together to maintain the frequency within a narrow band 

around the 60 Hz nominal frequency. 

 Under normal conditions, the power system frequency in a large 

interconnection (such as the Eastern Interconnection) varies approximately ±0.03 

Hz from the scheduled value. If the scheduled frequency is 60 Hz, the normal 

range is 59.97 to 60.03. These variations are normal and constantly occur due to 

the varying nature of the interconnection’s load. However, large downward, or 

negative, frequency deviations can trigger automatic load shedding schemes in 

most areas, designed to reestablish the necessary balance between generation and 
Appendix: Electricity - How It Is Generated and Distributed 

Page 10 of 11

load. Depending on the region, automatic under-frequency load shedding usually 

begins when the frequency declines to levels of 59.3 to 59.7 Hz. Distribution 

loads are typically shed in various size blocks before generating units start to trip. 

System Voltage

 The maintenance of voltage within a narrow range is critical to utility 

customers. Transmission voltage fluctuations of more than ten percent can affect 

the overall stability of the transmission system. Entities that experience sustained 

voltage fluctuations equal to or greater than ten percent must file a report with 

NERC.3

 Capacitor banks, Static VAR Compensators, load tap changing 

transformers, phase shifters, and voltage regulators are used to control system 

voltage. Low voltage conditions are usually caused by the loss of critical 

transmission or generation facilities and may result in the overload of adjacent 

circuits, which could require bringing power in over tie lines. 

Load Balancing

 An electric power system must have enough generating capacity to supply 

expected peak load demand plus a reserve margin to accommodate forced outages 

of generating units. Operating reserves also are necessary to regulate and respond 

to unanticipated events such as load forecast errors. 

 Large frequency deviations from the scheduled value occur when there is a 

significant mismatch between total load demand and total generation. The 

frequency rise or decay will in most cases be halted by the action of the speed 

governors on generators which respond to frequency changes and automatically 

adjust generation to meet demand. Governor action is supplemented by the 

Automatic Generation Control (AGC) system which over a period of several 

minutes brings the frequency and interchange (energy transfers that cross 

Balancing Authority boundaries) back to schedule. 

 AGC can be a very effective tool during system restoration. The primary 

function of AGC is to make continuous and automatic adjustments to the output of 

selected generators in a way that meets load demand and the established 

interchange schedule at the desired operating frequency. AGC software is 

normally designed to control a defined portion (within the Balancing Authority 

boundaries) of the interconnected system. To accomplish the AGC control 

function, control parameters are continuously monitored. The control parameters 

 3

 Reliability Standard EOP-004-1 (Disturbance Reporting). 
Appendix: Electricity - How It Is Generated and Distributed 

Page 11 of 11

consist of an actual frequency reading and all tie-line MW flows to neighboring 

Balancing Authority areas. These control parameters are selected and normally 

fixed for the portion of the system being controlled. A key assumption to the 

typical AGC control strategy is that the power system is operating in an 

interconnected mode. 

Distribution 

 Some larger industrial and commercial customers take service at 

intermediate voltage levels (4,000 to 115,000 volts), but most residential 

customers take their electrical service at 120 and 240 volts. Residential customers 

receive power via overhead or pad mounted transformers supplied by distribution 

feeders from substations. The transformers step down the voltage from a typical 

voltage of 13,000 volts to 120/240 volts. The lines carrying the power to a 

business or residence usually terminate at an electric meter owned and maintained 

by the distribution company. The meter records the energy consumed by the end 

user and is read periodically by the distribution company to monitor energy usage 

and for billing purposes. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

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Appendix: Power Plant Design for Ambient Weather Conditions 

Page 1 of 6 

 

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 can generally 

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. 

Enclosed coal fired power plant in the northeastern 

United States (Allegheny Energy)1

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

may fall below freezing, generation 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). 

1 Available at http://www.industcards.com/st-coal-usa-wv.htm (last visited Aug. 10, 2011). 
Appendix: Power Plant Design for Ambient Weather Conditions 

Page 2 of 6 

 

Non-enclosed coal fired power plant in the southern 

United States (Luminant)2

Common Freezing Problems 

 Some power plant components and systems are susceptible to freezing. 

Any power station system that uses water, air (which can contain moisture), or 

rotating machinery (which uses lubricating oil) can develop operational problems 

or trip off-line as a result of sub-freezing temperatures, unless adequate cold 

weather protection is in place. 

 Instrumentation - Instrumentation provides operational data necessary for 

process monitoring and control systems. Freezing often may occur not in 

the instrumentation itself, but in the sensing lines that run from piping, 

pressure vessels, and tanks that contain water or steam. The sensing lines 

are filled with a static water column that, if frozen, will send incorrect data, 

possibly resulting in unit trips, load rejection, unit runback schemes, or 

incorrect operator actions. Critical instrumentation sensing lines that are 

susceptible to freezing include lines used to monitor boiler steam drum 

water level, deaerator pressure, feedwater heater water levels, and various 

critical cooling water flows (generator, turbine oil cooling, etc.). 

 Feedwater systems - The condensate and boiler feedwater systems for 

steam-cycle generation units utilize water from the condenser and add heat 

(through a series of feedwater heaters) and pressure (through condensate 

and boiler feedwater pumps) to increase cycle efficiency before the water 

enters the boilers. Piping, pressure vessels, and valves contained in these 

systems are all susceptible to freezing. This is especially true of generation 

units that are not in operation at the onset of freezing temperatures, due to 

static water in the feedwater systems. In addition, the reverse osmosis 

2 Available at http://www.powermag.com/environmental/Luminants-Oak-Grove-Power-Plant-EarnsPOWER-s-Highest-Honor_2877_p2.html (last visited Aug. 10, 2011). 
Appendix: Power Plant Design for Ambient Weather Conditions 

Page 3 of 6 

equipment, demineralizers, filters, and storage tanks often found in 

condensate make-up water systems are susceptible to freezing. 

Cooling Water Systems 

 Cooling Water Intakes - Steam cycle power plants require large quantities of 

cooling water, often supplied by rivers or lakes. Water drawn from a river or 

lake is filtered through trash racks and circulating water screens to remove tree 

branches, debris, and fish. When temperatures drop below freezing, ice can 

clog racks and screens, limiting the flow of cooling water. Water intakes can 

also become clogged by fish kills during extreme cold weather, as happened in 

Texas in 1989. 

 Cooling Towers - Cooling towers lower the temperature of water used in the 

cooling process so that it can be reused (reducing the amount of water taken 

from lakes and rivers) or discharged at lower temperatures. Cooling towers 

use mechanically induced draft or natural draft designs. Mechanical cooling 

towers (box) have fans mounted on the top to draw air through the water as it 

falls over trays to remove the heat gained in the steam condenser. Natural draft 

cooling towers are of the familiar, hyperbolic design that can be seen at many 

large coal and nuclear power plants. During extended periods of freezing 

temperatures, ice can accumulate on the trays in the towers and affect 

operations or damage the unit. 

 Equipment Cooling Water - Various equipment and systems in power plants 

require cooling water to stay operational. These include turbine lubricating oil 

coolers, generator/hydrogen coolers, pump and fan bearings, and air 

compressors. Freezing of the piping, valves, and instrumentation sensing lines 

in these systems can cause derates or outages. 

 Sluicing/Service Water Systems - Sluicing water is used to remove bottom ash 

from coal-fired boilers. Icing problems in the bottom ash removal system can 

interfere with ash removal and may lead to derates or outages. Service water is 

used for various wash down systems and fire protection systems. Loss of 

service water due to freezing should not affect unit capacity, but could affect 

equipment protection systems. 

 Wastewater Systems - Various power plant systems that use water can create 

waste streams that must be treated for contaminants before re-use or discharge. 

Those systems include boiler blowdown, cooling tower blowdown, various 

cooling systems, bottom ash sluicing water, and service water systems. 
Appendix: Power Plant Design for Ambient Weather Conditions 

Page 4 of 6 

Freezing of valves and piping on these systems can result in the accumulation 

of wastewater, which could affect other systems. 

 

Emission Reduction Systems 

 Sulfur Dioxide Removal Systems - Among the methods available to reduce 

and remove sulfur dioxide from emission flue gas on coal plants, the 

predominant technology has been use of wet lime or limestone scrubbers. 

Lime or limestone contains calcium oxide, which when mixed (slaked) with 

water forms calcium hydroxide. Calcium hydroxide is sprayed through the 

flue gas to produce a chemical reaction to form calcium sulfite or sulfate 

(gypsum). As the waste product is processed, it contains less and less 

water, which is then reused in the scrubber. The scrubbing and waste 

processes require many runs of piping and instrument/control locations, 

many of which are susceptible to freezing. Freezing problems on piping 

runs or sensing lines could cause scrubber chemistry problems, tank 

overflows, etc., which could lead to derates or unit shutdowns if the plant is 

unable to stay within permitted emission limits. 

 Nitrogen Oxides Reduction Systems - As with sulfur dioxide systems, 

numerous technologies are available to reduce nitrogen oxides in fossil fuel 

plants. Many of these technologies use water in the emissions reduction 

process. These systems are susceptible to freezing that can lead to failure 

in the emissions reduction process, resulting in derates or unit shutdowns. 

Control Air Systems, Control Drives, Valve Actuators, Valves 

 Freezing in Control Air Systems - Air is compressed and used to operate 

pneumatic control valves, boiler damper control drives, and various other 

pneumatic controls in the plant. Moisture in the air can condense and 

accumulate in lines, air receivers, and component control mechanisms. If 

moisture is not removed (through use of air dryers and air receiver blowdowns), these pneumatic controls can freeze and cause equipment controls 

to malfunction or fail, which can in turn cause a unit shutdown or limit the 

unit’s output. 

 Sluggish Valve Operation - When exposed to severe cold weather, the 

operation of valves and control valves can become sluggish. This can lead 

to instability in boiler or turbine controls and ultimately lead to a unit trip. 
Appendix: Power Plant Design for Ambient Weather Conditions 

Page 5 of 6 

 Lubricating Oil - Various types and grades of lubricating oil and grease are 

used in power plants on rotating machinery and other moving parts. As the 

temperature decreases, the lubricating properties and viscosity of these oils 

change, possibly affecting operation of the equipment. 

Fuel 

 Coal - Severe cold weather can limit or prevent the transfer of coal into a 

plant. Coal in Texas (lignite) typically contains between 30 and 40% 

moisture. When temperatures are low enough to freeze moisture in the 

coal, the coal may slide on conveyor belts or block belt transfer points, 

chutes, and crushers, limiting supply. 

 Natural Gas Supply - Freezing weather can cause gas valves to 

malfunction, adversely affecting gas supply to the units. 

 Fuel Oil - During cold and freezing weather, fuel oil supplies in storage can 

gel without the appropriate additives. Gelled fuel oil can affect pump and 

burner performance, which in turn affects the unit’s output. Some types of 

fuel oil must be heated before they can be used in cold weather. 

Steam Drum Level Measurements 

One of the most critical measurements made on a drum type steam boiler is 

the water level in the main drum. Too high a water level can result in water being 

Drum Level 

Transmitter 

Differential 

Pressure 

Sensing 

Lines 
Appendix: Power Plant Design for Ambient Weather Conditions 

Page 6 of 6 

injected into the boiler tubes or steam turbine, damaging the boiler tube or turbine 

blade. Too low a water level or no water can result in overheating the drum or 

boiler tubes, leading to drum or boiler tube damage.  

The steam drum in a southern plant can be located outside, near or at the 

top of the boiler. During the February 2011 cold weather event many of the plants 

had problems with freezing in the drum level water level regulating system. 

A typical drum level measurement system works by maintaining the 

differential pressure between the steam side and water side of the drum to a 

constant value. The drum level transmitter monitors and regulates this 

differential pressure by controlling the amount of water being added or removed 

from the drum. On a normal drum, the water level is controlled to approximately 

plus or minus 2 inches of the desired level. 
Appendix: Impact of Wind Chill 

Page 1 of 2 

Wind Chill Factor 

The term “Wind Chill Factor,” is often used to explain the additional heat 

loss people experience through convection cooling when exposed to the wind. 

Whenever there is a temperature difference at a surface, e.g., the difference 

between normal body temperature and ambient air at a lower temperature on the 

surface of human skin, heat is conducted across the surface from the warmer body 

to the cooler air. In the process, the layer of air on the surface is warmed and 

forms a thermal boundary which tends to slow the rate of heat loss. Wind 

accelerates the heat loss by literally sweeping away that boundary layer and 

replacing it, continuously, with air at the ambient temperature. This acceleration 

of heat loss caused by the wind makes people feel that the air temperature is colder 

than it actually is. This feeling is quantified by assigning a stationary air 

temperature, known as the Wind Chill Temperature, which yields an equivalent 

perception of cold. 

The polar explorer and geographer Paul Siple first used the term “wind 

chill” in 1939. During the second expedition of Admiral Richard Byrd, Siple and 

his partner Charles Passel conducted experiments at Little America, Antarctica, to 

determine the time required to freeze water in plastic vials exposed outside in the 

wind. They developed a formula for relating heat loss to wind speed and air 

temperature, expressed in units of atmospheric cooling-watts per square meter. 

Later, the formula was modified to allow computation of a wind chill equivalent 

temperature. 

Wind Chill Temperature is only defined for ambient temperatures at or 

below 50 degrees Fahrenheit and wind speeds above 3 mph. Bright sunshine may 

increase the wind chill temperature by 10 to 18 degrees. 

Wind Chill Effect on Inanimate Objects 

The Wind Chill Factor, per se, applies only to human beings and animals. 

The only effect wind chill has on inanimate objects, such as car radiators and 

water pipes, is to more quickly cool objects to the current air temperature. Objects 

will not cool below the actual air temperature. For example, when the temperature 

outside is -5 degrees and the Wind Chill Temperature is -31 degrees, a car’s 

radiator will not get any colder than -5 degrees. Similarly, if the ambient 

temperature is above freezing, stationary water in piping exposed to the wind will 

not freeze, no matter how strongly the wind may blow. 
Appendix: Impact of Wind Chill 

Page 2 of 2 

Wind Chill Effect on Industrial Plants 

Industrial plants, including electric generating stations, can nevertheless be 

affected by the accelerated rate of heat loss, or cooling, caused by air movement. 

During the hot summer months, this cooling effect can help prevent temperatures 

from exceeding equipment operating limits. For this reason, many plants in 

warmer climates are of an open-air design, without walls or enclosures. In the 

winter, however, the enhanced cooling from the unimpeded flow of air can cause 

freezing problems. 

On cold days when the outside temperature drops below freezing, sustained 

high winds can quickly and continuously remove the heat radiating from boiler 

walls, steam drums, steam lines, and other equipment in an electric generating 

station, causing ambient temperatures to drop below freezing in spite of the heat 

being produced by the facility. If stationary water lines, such as those used for 

differential pressure measurement, are exposed to the wind under those conditions, 

they can freeze if they lack adequate freeze protection such as heat tracing and 

insulation. Wind screens and enclosures can slow the rate of heat loss caused by 

high winds, while at the same time acting to contain heat supplied by supplemental 

space heaters at critical locations. 

Wind Chill Effect on Electric Demand or Load 

The accelerated cooling effect of the wind affects buildings and homes 

throughout the community, and can significantly increase demand for electric 

power. In particular, buildings that are not well insulated, with frequently opened 

doors or drafty windows, can experience higher rates of heat loss on windy days, 

increasing the demand for heating energy. 

During the February 2011 weather event, ERCOT engineers and operators 

concluded, based on archived historical data, that the forecasted wind speeds 

would significantly increase the load on the system. They therefore increased the 

conventional load forecast by 4000 MW to account for the added load created by 

high winds combined, with low temperatures. 
Appendix: Winterization for Generators 

Page 1 of 8 

Extreme cold weather can cause generators to fail for many reasons, 

including the failure or absence of heat tracing on key components, missing or 

inadequate wind breaks, inadequate insulation, lack of supplemental heating 

devices, human error, or inadequate training, maintenance, or preparation. As 

discussed below, effective winterization programs incorporate both physical 

components and operational processes to protect generating plants from freezing 

weather. 

Physical Components of Winterization 

Physical freeze protection is accomplished by three primary components: 

 Heat tracing – the application of a heat source to pipes, lines, and 

other equipment that must be kept above freezing; 

 Thermal insulation – the application of insulation material to inhibit 

the dissipation of heat from a surface; and 

 Windbreaks – temporary or permanent structures erected to protect 

components from wind. 

Generators use other temporary measures to prevent freezing in plants, including 

installing space heaters, draining non-essential water lines, and placing small heat 

lamps in cabinets. 

Heat Tracing

Types of Heat Tracing Cable 

Electric heat tracing involves the application of heat to the outside of pipes 

or other lines to maintain proper operating temperature. A heat tracing system is 

typically made up of the following: (i) heat tracing cable wound around the pipe; 

(ii) a thermostat that measures ambient air temperature; (iii) thermal insulation; 

and (iv) a power source. The failure of any of these components can result in 

frozen instrumentation. 

There are five main types of heat trace cable. “Self-regulating” cable 

automatically increases power to produce additional heat as the temperature falls. 

It can be used on metal or plastic components for freeze protection, temperature 

maintenance, and foundation heating, and is typically found on sensing lines and 

other ancillary components. However, it cannot be used on surfaces that have 

high surface temperatures. 
Appendix: Winterization for Generators 

Page 2 of 8 

“Power-limiting” heat tracing is similar to self-regulating heat tracing in 

that it increases power and heat as temperatures drop, and decreases power as 

temperatures rise. It is specifically designed to produce high temperatures and to 

be used on high surface temperature fixtures. 

“Parallel constant watt” heat tracing cable consists of a continuous series of 

short, independent heating circuits that maintain a consistent output of heat for up 

to several hundred feet. One benefit of this type of cable is that if one of the 

independent circuits fails, the rest of the cable will continue to operate. However, 

the length of the cable is limited, based upon the distance between the circuits, 

making it impractical for certain situations. 

A “series constant watt” heat tracing cable is designed specifically for 

components that need longer circuit length. These cables are made of highresistance wire that is powered at a particular voltage to generate heat. However, a 

break anywhere along the cable will result in failure of the entire heat tracing 

installation. 

Another common type is “mineral insulated” heat tracing cable, which is 

typically used to maintain high temperatures, or in locations where it will be 

exposed to high temperatures. Mineral insulated cable is also used to provide heat 

over long distances, and is often used to protect high temperature steam lines.

Power Supply 

Each heat tracing cable must be connected to a power source. In a typical 

installation, several cables covering one component of a generating unit will be 

connected to a freeze protection electric panel that contains circuit breakers or 

fuses for the various circuits. Depending on the size and layout of the generating 

unit, it may have dozens of freeze protection panels. These panels are often 

equipped with visual displays that indicate when the system is energized and when 

the heat tracing is activated. Images 1 and 2 are examples of the inside and 

outside of a new freeze protection panel. 
Appendix: Winterization for Generators 

Page 3 of 8 

 Figure 1: Freeze Protection Figure 2: Freeze Protection 

 Panel Interior Panel Exterior 

 

 As can be seen in the example above, lights on the front of the panel 

indicate the status of the freeze protection system. Such indicator lights must be 

regularly monitored and tested by plant employees, since control room personnel 

are not always able to monitor panels remotely. 

 The failure of a freeze protection panel during cold weather can cause heat 

trace cables connected to that panel to fail. Failure to properly maintain or inspect 

the panel can cause corroded connections to go unnoticed and go unrepaired, 

possibly resulting in a short circuit that shuts off power to other panels. 

Figure 3: Corroded Freeze Protection Panel 
Appendix: Winterization for Generators 

Page 4 of 8 

Thermostats 

Although the panel is always energized, heat tracing cables are turned on 

only when low temperatures call for freeze protection. Power to the cable is 

supplied either by a contactor (wherein two metal plates, usually separated, are 

pressed together to power the cables), or by a solid state controller. In most cases 

the system is turned on by a thermostat located at the panel. In some cases plants 

initiate freeze protection procedures at certain specific temperatures, and in some 

instances, the heat tracing must be turned on manually by plant personnel. 

Thermal Insulation

A layer of thermal insulation is placed on top of the heat tracing that is 

installed on a pipe. This insulation is similar to home insulation, but is composed 

of different materials. A weatherproof skin is typically applied as an external 

layer to protect the insulation and heat trace from damage. 

Figure 4: Insulated Piping with Heat Tracing 

 Thermal insulation plays a significant role in freeze protection, particularly 

in windy conditions, by preventing rapid heat loss. However, even small gaps in 

insulation have been known to result in frozen lines. 
Appendix: Winterization for Generators 

Page 5 of 8 

Exposed 

Sensing Line 

Figure 5: Gap in Insulation 

In addition to the pipe itself, valves, flanges, traps and fittings should be insulated 

to the extent possible. Non-insulated valves, like those pictured below, can cause 

pipe to freeze if enough surface area is exposed to freezing wind conditions. 

Figure 6: Exposed valves emerge from thermal 

insulation and are not heat traced 

Windbreaks

The third major component to winterization is windbreaks. Windbreaks are 

temporary or permanent structures used to prevent wind from blowing directly 

over exposed components and dissipating heat at an increased rate. 
Appendix: Winterization for Generators 

Page 6 of 8 

Figure 7: Temporary windbreak created with scaffolding and tarpaulin 

Other Winterization Efforts

In addition to the three major winterization techniques, generating stations 

sometimes use other freeze protection measures. These include keeping water 

flowing to reduce freezing, draining liquids from valves, purging drained lines of 

water with compressed air, and installing space heaters in enclosed areas to raise 

ambient air temperatures. 

Winterization Processes 

Although designing freeze protection systems for exposed areas is critical 

to cold weather operation, preparation for freezing conditions is equally important. 

In order to achieve good freeze protection, a generator must know what areas are 

likely to freeze, and must take steps to ensure that appropriate procedures are put 

in place. The following paragraphs describe some of the steps that can be taken to 

prepare for winter, and discuss how the proper use of checklists can help plant 

managers implement effective winterization measures. 

Winter Preparation

Preparation for winter weather should begin well before its arrival, and 

many generator operators in Texas and the Southwest start their winterization 

programs in the fall of each year. These procedures include verifying that 

installed heat tracing is working, components are properly insulated, space heaters 

are operational, fuel switching can be initiated, and instrument systems are free of 

moisture. Many generators also verify that their inventory of freeze protection 

equipment – such as heat lamps, heat guns, propane torches, tarps, de-icing 
Appendix: Winterization for Generators 

Page 7 of 8 

material, fuel, insulation, sand, and extension cords – is adequate for the upcoming 

season. Timeliness is an important aspect of pre-winter preparation – it should 

begin early in the season so that there is time to make necessary repairs before 

cold weather hits. 

In addition to pre-season preparation, generating stations typically have a 

set of procedures that are initiated whenever a winter storm is expected. Much of 

the work that is done before a storm arrives is similar to pre-season preparation. 

However, the pre-storm procedures may include calling in additional operators 

and maintenance personnel, moving motor vehicles into garages, draining nonessential water lines, and moving portable heaters into position. 

As winter weather sets in, generating stations may adjust their operations to 

protect against freezing conditions. Such changes may include switching 

instrument air to nitrogen backup, warming up standby boilers every two hours, 

opening bypass valves on steam traps, and rotating pumps every two hours. 

 A critical component of winterization plans is the opportunity for postwinter critiques and reports on lessons learned. Applying lessons learned is 

sometimes done informally but some generators go further, requiring plant 

managers to conduct post-winter meetings to identify necessary improvements and 

to file written reports on the plant’s performance during the winter season. 

 

Checklists

In order to ensure that all of the plant-specific tasks are properly completed, 

many generator operators create checklists for plant personnel to follow. 

Although the form of such checklists may vary depending on the size of the plant 

and the types and locations of the generating units, effective checklists tend to 

have certain characteristics. 

Good checklists are sufficiently detailed to allow plant operators and 

maintenance personnel to adequately prepare for and deal with cold weather 

events. For example, a checklist may specify who is responsible for assigning 

personnel to freeze protection duty, or may identify specific tasks triggered by 

different freeze alert levels. 

A checklist can be broken down not only by task, but also by area and by 

individual components or areas to be checked. For example, the checklist can 

specify which particular lines should be drained and which vents should be closed. 
Appendix: Winterization for Generators 

Page 8 of 8 

A list that is lacking in detail and that only includes general tasks such as 

turning off vent fans or checking boiler and duct air heater enclosures will not be 

effective. Plant employees might understand which components should be 

included in such general references, but non-specific descriptions are inadequate 

to ensure that all systems are identified and checked. 

 Checklists can also offer generating stations the ability to audit their 

performance in implementing winterization. A common feature of effective 

checklists is a requirement that employees initial and date the checklist for each 

task completed. Not only does this provide confirmation that the tasks were 

completed, but it also holds operators and maintenance staff accountable for their 

performance. 
Appendix: Natural Gas – Production and Distribution 

Page 1 of 9 

What Is Natural Gas? 

Natural gas is a highly compressible, naturally occurring mixture of 

hydrocarbons, principally containing methane, that migrate upward through geological 

formations until the migration is halted by a physical barrier that allows the natural gas to 

accumulate in the small pore spaces within a geological formation, or reservoir. The 

physical barrier is a non-permeable formation that is known as a reservoir seal or 

caprock. The type of formation where the natural gas can accumulate, which can include 

sandstone, coal as well as shale, depends upon the location of deposition of the original 

organic material and the geologic formations that lie above. To access the natural gas 

that has accumulated within the reservoir, drilling companies will drill down to the 

formation using drilling rigs that punch into the formation using drill bits and long string 

pipes to bring the natural gas to the surface at the well site. 

(Energy Information Administration) 

While in the ground, the natural gas is under high pressure. When these 

formations are produced, the natural differential in pressure, between the high pressure in 

the formation and lower pressure at ground level, can provide the driving force to move 

the gas to the surface. The company in charge of producing the natural gas, by allowing 

the natural gas to flow from the subsurface formation up to the surface, will drill several 

wells to maximize its ability to produce the natural gas while maintaining the integrity of 

the reservoir within the geological formation to ensure a long and active production life. 

As part of the natural gas stream that reaches the surface and is produced from the 

wellhead, there are many other gas constituents other than methane. Heavier 

hydrocarbons, such as ethane, propane, butane, and pentane plus, are also produced along 

with the methane-rich gas stream. After production, these heavy hydrocarbons or natural 

gas liquids (NGLs) can be removed through processing and sold separately from the 

natural gas. Other gases, such as hydrogen, carbon dioxide, nitrogen, oxygen, sulfur, and 

hydrogen sulfide, are also produced, and most of the gases will be removed from the 
Appendix: Natural Gas – Production and Distribution 

Page 2 of 9 

natural gas stream through the use of treating plants. Unlike NGLs, some of these gases 

are undesired impurities with little or no commercial value. 

Another common byproduct of natural gas production is water. Just as natural gas 

can migrate through geologic formations and into reservoirs, water and crude oil can 

follow the same process. Water that accompanies natural gas is removed through the use 

of dehydration facilities located at or near the wellhead.1

 The water is then commonly 

injected back into the outer limits of the reservoir’s geological formation to help produce 

additional natural gas from the reservoir by displacing the natural gas from the pore 

spaces within the geologic formation and push the natural gas toward the producing 

wells. Unless water is removed from the gas stream, it can freeze in the pipeline and 

stop the flow of gas from the wellhead. 

(Environmental Protection Agency) 

Over time, multiple wells are drilled into the formation in order to maximize 

production of natural gas in the reservoir. After each well is tested and examined by the 

production company, the wells are connected through a series of pipelines increasing in 

diameter as more gas is gathered and transported through the gathering pipeline. 

 1 The dehydration of natural gas usually involves one of two processes – absorption or 

adsorption. Absorption occurs when the water vapor is taken out by a dehydrating agent. 

Adsorption occurs when the water vapor is condensed and collected on the surface. The 

absorption process requires a chemical with an affinity for water, such as glycol, which is the 

most commonly used dehydration agent. After absorbing the water, the glycol falls out of 

solution to the bottom of the tank where the water-rich glycol is removed. The adsorption 

process is a physical-chemical process in which the gas is concentrated on a surface of a solid or 

liquid to remove the impurities. Natural Gas Supply Association, Processing Natural Gas, 

available at http://www.naturalgas.org/ naturalgas/processing_ng.asp (last visited Aug. 5, 2011); 

Saeid Mokhatab, William A. Poe & James G. Speight, Handbook of Natural Gas Transmission 

and Processing 262 (Elsevier 2006). 
Appendix: Natural Gas – Production and Distribution 

Page 3 of 9 

 

Depending upon the impurities in the natural gas stream, the pipeline will funnel the 

natural gas stream to processing and treatment plants. The treatment plants are used to 

remove impurities and other objectionable material usually before the natural gas stream 

is transported to the processing facilities. 

The natural gas stream often contains other contaminants that must be removed 

before the natural gas stream is delivered to downstream pipelines. Some of these 

contaminants are hydrogen sulfide, carbon dioxide and other sulfur-based impurities, 

which are sometime referred to as “acid gas.”2

 When hydrogen sulfide combines with 

water in the natural gas stream, sulfuric acid forms. Similarly, carbon dioxide that 

combines with oxygen forms carbonic acid. These acid gases can cause damage which, if 

left unchecked, could lead to pipeline failure.3 

The processing plants typically remove NGLs through a refrigeration process that 

involves a form of rapid cooling of the natural gas stream. Two types of this cooling 

process are mechanical refrigeration, as used in lean oil absorption, and turbo-expander 

or cryogenic process. The technology used will depend upon the age of the processing 

facilities as well as the desired result. Mechanical refrigeration is a process whereby the 

natural gas stream is chilled by a vapor compression refrigeration process, similar to the 

process used by a refrigerator or an air conditioner, but producing much colder 

temperatures. This is coupled with the use of glycol as an absorption fluid that combines 

with the NGLs and falls out of the gas stream. In the cryogenic process, the high 

pressure natural gas stream is rapidly expanded by decreasing the pressure. This process 

causes the gas stream to cool rapidly (Joule-Thomson Effect)4

 to temperatures that will 

cause the NGLs to move from a gaseous phase to a liquid phase. The NGLs fall out of 

the gas stream and are collected for sale and additional processing. The residual gas, 

from which the NGLs have been removed, is transferred to a downstream pipeline for 

transmission to end users. Both of the above processes are effective means for 

recovering NGLs and for reducing the possibility that NGLs will condense and fall out of 

the gas stream as liquids that could cause damage to downstream equipment. 

2

 Natural gas containing hydrogen sulfide is considered “sour” gas while natural gas 

without hydrogen sulfide is considered “sweet” gas. Id. at 261. 

3

 Frøydis Eldevik, Safe Pipeline Trasmission of CO2, Pipeline & Gas J., April 2011, Vol. 

238 No.4, p. 3, available at http://www.pipelineandgasjournal.com/safe-pipeline-transmissionco2?page=3 (last visited Aug. 5, 2011). 

4

 Joule-Thomson Effect is the change in temperature or cooling effect resulting from the 

rapid expansion of pressurized natural gas through a valve. 
Appendix: Natural Gas – Production and Distribution 

Page 4 of 9 

After treating and processing, the natural gas can be transported to market centers 

by the intrastate and interstate pipeline system. This network is made up of more than 

210 pipeline systems with over 305,000 miles of varying diameter pipeline, 1,400 

compressor stations, and 400 underground storage facilities, all connecting the various 

natural gas production areas, both onshore and offshore, to multiple markets throughout 

the United States.5

Types of pipeline systems 

The interstate pipelines can divided into two types of systems – long-haul and 

reticulated. Long-haul pipelines receive natural gas supplies from producers and 

 5

 U.S. Energy Information Administration, About U.S. Natural Gas Pipelines – 

Transporting Natural Gas, available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/ 

analysis_publications/ngpipeline/index.html (last visited July 20, 2011). 
Appendix: Natural Gas – Production and Distribution 

Page 5 of 9 

processors and transport it across hundreds of miles to market areas outside the 

production areas. Reticulated pipelines resemble a spider web that overlays both the 

supply areas and the market areas, and typically have multiple lines that can change 

direction of gas flow through the system, depending upon market needs. 

Pipeline Design 

A natural gas pipeline system can be as simple as a single diameter pipe receiving 

gas from one source and transporting it to a single delivery point, or as complex as a 

network of multiple diameter pipes covering hundreds of miles with compressor stations, 

storage facilities, and numerous receipt and delivery points. In order to move natural gas 

supplies from the supply areas to the market areas, a pipeline must be designed to 

transport the required volume of gas supplies, while maintaining system pressures along 

the length of the pipeline necessary to serve its shippers. 

The design of all pipeline systems starts with the same basic idea, the need to 

transport a specific volume of natural gas from at least one supply source to a specific 

destination while maintaining contractual delivery pressure obligations. Due to frictional 

loss resulting from the gas flow, the pressure of the gas stream will decrease. 

Compressor stations are designed to re-pressurize the gas stream in order to overcome the 

pressure losses associated with movement of gas in a pipeline. Compressor stations are 

above-ground facilities where the pipeline connects with large individual compressor 

units through various smaller pipelines or “yard piping” as well as meter and regulation 

equipment. Compressors are mechanical devices that increase the pressure of the gas 

stream. After the gas stream has been re-pressurized, the gas re-enters the pipeline for 

further transmission to downstream markets. Compression facilities are needed along the 

length of the pipeline, and are typically placed at 40 to 60 mile intervals. 

Compressors are split into two basic parts, the compressor and the driver, or 

motor. The motor, which can be fueled by electricity or gas-fired, powers the compressor 

unit that compresses the gas. The two types of compressors that are most commonly used 

by the interstate natural gas companies are centrifugal and physical displacement or 

reciprocating compressors. Centrifugal units are turbines that spin at high rates of speed 

to compress and accelerate the gas stream. These compressors are used to accommodate 

high flow rates at high pressures. Most interstate pipeline systems use centrifugal 

compressor units on their mainlines. The following is an illustration of a centrifugal 

compressor and gas-fired motor. 
Appendix: Natural Gas – Production and Distribution 

Page 6 of 9 

(Solar Turbines Incorporated (a Caterpillar Company)) 

The gas stream enters the inlet or suction side of the compressor unit, where it is 

forced through the rotating turbines at high speed and exits the compressor at the 

discharge side, moving back into the transmission pipeline. With gas-fired compressor 

motors, a small amount of natural gas is funneled from the gas stream at the suction side 

to provide fuel for the motor. 

Reciprocating units increase the pressure of the gas stream by compressing or 

reducing the volume of the gas through the use of pistons within a cylinder similar to the 

pistons in a car engine. These compressors can be found on interstate pipelines’ mainline 

systems, which need to compress gas volumes with greater pressure differentials. 

Storage facilities also utilize reciprocating compressors to inject gas supplies received 

from pipeline systems at pressures ranging from 500-1,000 psig, into storage caverns at 

pressures that can exceed 2,000 psig. Just like the motors used by gas-fired centrifugal 

compressors, a small amount of natural gas is taken from the gas stream to provide fuel. 

Reciprocating Compressor Cylinder Assembly (machinerylubrication.com)6

 

 6

 “Reciprocating Compressor Basics,” available at http://www. 

machinerylubrication.com/Read/775/reciprocating-compressor (last visited Aug. 5, 2011). 
Appendix: Natural Gas – Production and Distribution 

Page 7 of 9 

 

Line pack 

Line pack is the volume of gas in the pipeline at a given point in time. Pipeline 

operators use line pack to maintain system operating pressures while accommodating the 

system’s highly variable load requirements. 

Most gas supplies enter a pipeline system at a relatively even hourly rate, or about 

1/24th of the total amount of gas per hour (4.17 percent per hour) for the entire day, also 

known as “steady-state” conditions.7 On the demand side, deliveries rarely leave the 

system at an even hourly rate. Deliveries are not constant primarily due to variations in 

demand caused by inlet and outlet flow changes, non-performance of receipt or delivery 

points, scheduled or unscheduled maintenance, and compressor startups and shutdowns.8 

Flow conditions that vary over time are known as transient flow conditions. Depending 

upon the flexibility provided by the interstate pipeline within its tariff or contract with the 

customer, the hour rates for gas delivery could be 5 percent and even up to 8 percent per 

hour. These hour rates are equivalent to a 20 hour to a 12.5 hour day, or simply stated, 

the customer can take the entire scheduled and confirmed quantity of gas for the entire 

24-hour gas day in as little as 20 to 12.5 hours. Managing these transient loads could not 

be done without actively managing system line pack. 

In order to prepare for the upcoming gas day, the pipeline operator will increase 

system pressures by increasing the use of available compression horsepower at 

compressor stations strategically located along the pipeline system. The increase in 

pressure will allow the pipeline operator to “pack” the pipes with additional gas from 

other portions of the pipeline system located closer to the supply points. Further, 

depending upon demand forecasts for the upcoming gas day, customers will often 

increase their receipts in order to ensure that they will be able to meet their load 

requirements. Unlike electricity, which is added to the transmission lines 

instantaneously, natural gas must be physically moved through the pipeline from the 

supply areas to the market areas for delivery. Depending upon the length of the pipeline 

system, this physical transportation of gas from the supplier to the end user can take days. 

Most interstate pipeline systems move gas at speeds between 20 and 30 mph. If the 

pipeline has its origin in the Gulf of Mexico and the destination is the New York City 

market area, 1,500 miles away, the gas will need roughly two days to travel that distance 

7

 Steady-state flow conditions exist when the gas volumes both received into and 

delivered out of the pipeline system are equal at every moment in time while the pipeline is 

operating at a constant pressure and temperature. For example, a pipeline is said to operate under 

steady-state conditions when 1/24th of the gas volumes are entering the system every hour while 

simultaneously 1/24th of the gas volumes are leaving the pipeline system every hour. Gas 

volumes going into the system must equal the gas volumes leaving the system to be considered 

steady-state conditions. 

8

 Saeid Mokhatab, William A. Poe & James G. Speight, Handbook of Natural Gas 

Transmission and Processing 414 (Elsevier 2006). 
Appendix: Natural Gas – Production and Distribution 

Page 8 of 9 

 

at 30 mph. This is why it is critical for pipeline systems to receive gas supplies 

nominated, scheduled and confirmed in order to replace the system line pack in a timely 

manner. 

Maximum Allowable Operating Pressure 

The Maximum Allowable Operating Pressure (MAOP) is one of the many design 

assumptions that will limit either a pipeline’s design capacity or peak day capacity. The 

MAOP, which represents the maximum pressure at which a pipeline may operate its 

system,9

 is an operational or safety-based constraint that protects the integrity of the 

pipeline system while defining an upper capacity limit. As such, the MAOP will act as a 

physical constraint10 that the pipeline companies’ system design engineers must address 

with each pipeline expansion project before the Commission. 

When a pipeline company files an application to add a new service or to expand 

its existing facilities, it will look to the Commission’s regulations (18 C.F.R. §

157.14(a)(7)-(9)(vi)) for guidance. Under these regulations, the pipeline company is 

required to provide to the Commission flow diagrams reflecting “Daily Design Capacity” 

and “Maximum Capabilities” for both its existing and proposed facilities. Currently, 

most of the interstate pipeline companies justify the need for facility augmentation 

through the use of a steady-state model of their respective systems while operating under 

design peak day flow conditions. These models are designed to meet the pipeline’s firm 

contractual obligations while maintaining: (1) the volumetric requirements of its existing 

firm shippers; (2) the minimum contractual delivery pressure obligations; (3) controlling 

pressures located at critical points on their system; and (4) the full utilization of the 

existing available capacity through the use of all available compression horsepower along 

the path of the new service. 

Implicit in the pipeline companies’ design process is the need to maintain actual 

operating pressures at or below the MAOP in order to maximize throughput levels on 

their respective systems. From the design perspective, this is a relatively simple task. In 

most cases the pipeline’s design capacity is based upon maximum utilization of 

compression facilities while transporting gas volumes between primary contractual 

9

 In its November 14, 2002 comments in Docket No. PL02-9-000, the Office of Pipeline 

Safety (OPS) stated that the purpose of setting regulatory standards for determining pipeline 

MAOP is to “prevent pipeline failure that could result from excess operating pressure, startup and 

shutdown.” OPS defines MAOP as the maximum pressure at which a pipeline or pipeline 

segment may operate. The Office of Pipeline Safety, Comments in Response to Open Forum at 

the Natural Gas Markets Conference Oct. 25, 2002, Docket No. PL02-9-000 at 4 (filed 

11/14/2002); see also 49 C.F.R. § 192.3. 

10 Physical constraint, or pipeline bottleneck, is a point on a system where the existing 

facilities are inadequate to accommodate 100 percent of the flowing capacity of the upstream 

pipeline facilities. 
Appendix: Natural Gas – Production and Distribution 

Page 9 of 9 

 

receipt and delivery points. Under these specific design assumptions, maintaining 

operating pressures at or approaching the MAOP will ensure that existing shippers will 

receive their gas requirements.11 However, as previously discussed, the changing load 

requirements and the capacity release market could potentially reduce the pipeline’s 

ability to maintain optimum operating pressures to meet new demands on its system if the 

new loads are not proximate to the traditional markets. The potential impact of new 

markets could reduce the operational flexibility of the pipeline by reducing the operating 

pressure. If the pipeline cannot maintain historical operating pressures that are necessary 

to meet the requirements of its shippers, the throughput capacity of the pipeline will be 

reduced. 

11 Scheduled and unscheduled maintenance is not incorporated into the pipeline’s design 

capacity. As a result, required maintenance will reduce the pipeline’s ability maximize 

throughput capacity and could prevent the pipeline from meeting its firm contractual 

requirements. 
FERC/NERC Staff Report on the 2011 Southwest Cold Weather Event

This page intentionally left blank. 
Appendix: Natural Gas Storage 

Page 1 of 6 

Natural gas, like many other sources of energy, can be stored during periods of 

low use and called upon during periods of greatest demand. There are over 400 

underground storage facilities, eight LNG import facilities and over 100 LNG peaking 

facilities located throughout the U.S.1

Base load vs. Peak load Storage Facilities 

Storage facilities are designed to meet either base load or peak load requirements. 

Base load storage is designed to meet seasonal demand that exceeds the average 

deliverability of the pipeline system. Base load storage facilities have sufficient capacity 

to meet the long-term seasonal demand requirements for the pipeline’s market areas. 

Historically, these storage facilities were used by the pipeline’s customers to inject 

natural gas supplies into the storage facility during periods of low system use, such as the 

non-heating season (when gas prices are low), which typically runs from April 1 through 

October 31. These gas volumes were then withdrawn to meet base load requirements 

during the heating season, which usually runs from November 1 through March 31.2

 

 1

 United States Energy Information Administration, About U.S. Natural Gas Pipelines – 

Transporting Natural Gas, available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/ 

analysis_publications/ngpipeline/index.html (last visited July 20, 2011). 

2

 This trend has changed in the last decade as newer and more efficient natural gas-fired 

electric generation facilities have replaced higher emission oil-burning facilities. As a result, 

more natural gas is needed during the spring and summer months to meet increased electrical 

demand for the summer cooling season. Now, instead of having one peak season, market areas 

served by some pipelines may have two peak periods, during both the summer and winter 

months. 
Appendix: Natural Gas Storage 

Page 2 of 6 

Base load storage facilities are usually large depleted oil or gas reservoirs that have 

relatively low withdrawal rates. They can provide a steady flow of natural gas and 

typically have turnover rates of once a year due in part to the length of time necessary to 

replenish the gas supplies. Depleted gas reservoirs are the most common type of base 

load storage facilities. 

Peak load storage facilities, on the other hand, are designed to operate at high 

rates of withdrawal. These facilities are used to meet peak load requirements that can call 

for large amounts of gas over short periods of time. Peak load facilities are much smaller 

than base load facilities but can be quickly replenished – in some cases within days or 

weeks. 

Different Types of Underground Storage Facilities 

Three types of reservoirs or geological formations are used as underground 

storage facilities – aquifers, depleted reservoirs, and salt caverns. All of these formations 

must be developed or reworked in order to create the space necessary to provide the 

storage service. Natural gas is injected slowly into the formation through the use of 

compression facilities in order to build up the reservoir pressure necessary to allow the 

natural gas to flow freely from the storage facility directly into the downstream pipeline 

systems. Toward the end of the withdrawal season, when the prevailing reservoir 

pressures fall below the operating pressures of downstream pipeline systems, 

compression equipment that was used to inject gas volumes into storage is used to repressurize the gas stream so that gas from storage can be moved downstream into the 

pipeline systems. 

Not all of the natural gas in storage facilities can be withdrawn. In order to 

maintain the integrity of the formation and to prevent migration of water into the 

reservoir, some natural gas must be left in the reservoir. This is typically called “base 

gas” or “cushion gas.” Similar to line pack in a natural gas pipeline, base gas is the 

volume of gas left in the reservoir to provide the pressure needed to extract the remaining 

gas. The gas that is withdrawn from the storage field is referred to as “working gas.” 

The amount of working gas within the reservoir represents the storage capacity of the 

facility. 
Appendix: Natural Gas Storage 

Page 3 of 6 

Types of Underground Natural Gas Storage Facilities (FERC) 

Depleted Reservoirs 

Depleted gas reservoirs are the most commonly used formations for storage 

reservoirs. These formations are formerly producing gas reservoirs that have had all of 

the economically recoverable natural gas extracted, and which can be readily converted 

from production to storage. However, to maximize the usefulness of the facility, the 

reservoir should be located near a market area (for base load or peaking facilities) or a 

supply area, (to supplement supply when production is interrupted). The reservoir also 

must be located near a mainline pipeline facility. Most depleted gas reservoirs are 

located in production areas, leaving aquifers and salt caverns as the only option for 

storage development in other areas. 

Aquifers 

Aquifers are underground porous, permeable rock formations that act as natural 

water reservoirs. A porous rock formation has small spaces between the grains of rock 

where natural gas, oil and water can be found. A permeable formation is one where 

liquid can flow through small channels that connect the small pore spaces within the 

formation. Aquifers are the least desirable and most expensive types of natural gas 

storage facilities for the following reasons: 

 

 The geological formations are not as well known as depleted reservoirs, 

which are explored during the development and production process. 

Accordingly, there is a significant cost associated with developing and 

studying the geological characteristics of an aquifer in order to determine 

its suitability as a storage reservoir. 

 Aquifers do not have in place the facilities and equipment associated with 

a producing gas reservoir, such as extraction equipment, pipelines, 

dehydration facilities, and compressors. Aquifers may also produce large 
Appendix: Natural Gas Storage 

Page 4 of 6 

volumes of water as natural gas is withdrawn from storage, increasing 

costs. 

 Development of an aquifer as a gas storage facility can take twice as long 

as development of a depleted reservoir facility. 

Salt Caverns 

A salt formation is a naturally occurring deposit of salt that may exist in 

two forms: salt domes and salt beds. Salt domes are formations that have migrated 

through sedimentary geological formations to form large domes of salt. These 

domes can be a mile wide and 30,000 feet thick. Salt domes most often used as 

salt caverns are generally found about 6,000 feet beneath the surface. Salt beds 

are not as thick or as deep – these formations are usually less than 1,000 feet thick 

and are less stable than salt domes, but both formations are well suited to natural 

gas storage. 

 Salt Cavern Underground NG Salt Cavern Leaching 

 Storage Reservoir (Oregon National Laboratory) 

 (Energy Information Administration) 

Salt caverns are developed by drilling into the salt formation and circulating large 

amounts of water under high pressure to dissolve and extract the salt, leaving a large 

void. This process is known as “salt cavern leaching.”3

 Once created, the salt cavern 

offers an underground vessel-like structure that can provide very high rates of delivery. 

 3

 Salt Cavern Storage, What is Salt Cavern Storage? available at 

http://www.saltcavernstorage.com/what-is-salt-cavern-storage.html (last visited July 20, 2011). 
Appendix: Natural Gas Storage 

Page 5 of 6 

Salt caverns provide another operational benefit, in that they can operate with less base 

gas than depleted reservoirs and aquifers. 

(Oregon National Laboratory) 

Because salt cavern storage reservoirs are typically much smaller than depleted 

gas reservoirs, they cannot hold the volumes necessary to meet base load storage 

requirements. However, because the deliverability of the salt caverns is typically much 

higher, gas stored in these facilities can be more quickly withdrawn and replenished than 

gas stored in any other type of facility. 

LNG and LNG Peak Shaving Facilities 

Liquefied natural gas (LNG) is natural gas that is stored and transported in liquid 

form at -260 degrees Fahrenheit. In liquefied form, the gas volume is reduced by a factor 

of 610. This reduction in volume makes the transportation and storage of liquefied 

natural gas more practical. 

In order to introduce LNG into the pipeline system, the LNG must be warmed and 

re-gasified. This is done at specially built re-gasifier terminals attached directly to the 

interstate pipeline grid or to LDC distribution systems. 

LNG can also be produced on a much smaller scale at liquefaction facilities, 

which receive natural gas directly from the pipeline system, convert it to liquid form, and 

store it in above ground facilities until needed to meet peak load requirements. These 

facilities are referred to as “peak shaving” plants. 
Appendix: Natural Gas Storage 

Page 6 of 6 

LNG Peak shaving plant (Energy Information Administration) 
Appendix: Natural Gas Transportation Contracting Practices 

Page 1 of 6 

Interstate natural gas pipeline rates for transportation of natural gas may be 

based on distance transmitted (zone matrix) or on a “postage-stamp” basis, where 

all consumers pay the same rate regardless of distance transmitted. Natural gas 

pipelines’ tariffs may contain rates based on a function of the volume reserved for 

a particular buyer (a set capacity charge) and a variable based on the pipeline 

volume actually consumed by the buyer (a commodity charge). Gas is sold by 

unit of energy, not by volume. Prices are usually stated in price per unit of energy, 

such as dollars per million British thermal units (Btu), rather than price per unit 

volume, such as dollars per thousand cubic feet (Mcf). Interstate natural gas 

transportation tariffs are often priced per thermal unit or energy unit, not on a 

volumetric basis. 

The wholesale market is composed of both the natural gas commodity 

market and the transportation market. Since 1984, when FERC Order No. 436 

was issued, large numbers of industrial customers, electric generators, and end use 

customers have been buying gas from parties other than the pipelines or LDCs. 

After the issuance of FERC Order No. 636 in 1992, the industry witnessed a 

dramatic growth in the use of marketers to provide gas, arrange transportation, or 

provide both services to LDCs, industrials, retail users, and electric generators. 

Gas customers use marketers in a variety of ways. LDCs, which hold firm 

transportation rights on a single pipeline, can use the marketer to obtain and 

deliver gas to an interconnect point on that pipeline, and the LDC can use its firm 

transportation service to deliver that gas to its citygate delivery point. Other 

customers, such as industrials, may employ a marketer to acquire gas and 

interstate transportation service to deliver the gas to the industrial’s citygate 

delivery point. Increasingly, marketers are offering additional services to 

customers such as asset management services, where the marketer manages 

capacity for LDCs, as well as providing price hedging, financing, and risk 

management services. 

The transportation market also has developed to provide shippers with 

alternative means of acquiring capacity. Shippers can choose either short or longterm services from the pipeline or can acquire capacity from other shippers 

through the capacity release mechanism. 

The use of released capacity has made possible the development of virtual 

pipelines. A virtual pipeline can be created when a marketer or other shipper 

acquires capacity on interconnecting pipelines and schedules gas supplies across 

the interconnect, creating in effect a new pipeline between receipt and delivery 

points not on a single pipeline company’s system. 
Appendix: Natural Gas Transportation Contracting Practices 

Page 2 of 6 

Nominations, Confirmations, and Scheduling 

The North American Energy Standards Board (NAESB) is an independent, 

industry-supported entity whose primary purpose is to set business standards 

across the industry. The Commission’s standards relating to nominating, 

confirming, and scheduling gas across the interstate pipeline system were 

developed by industry representatives in conjunction with NAESB. The 

nomination, confirmation, and scheduling processes control the movement of gas 

across the interstate pipeline system. 

Nominations

A nomination is a request for service under any transportation agreement 

by a gas purchaser (referred to as the shipper) to transport gas from a specified 

receipt point to a specified delivery point over a specific time period. In short, a 

nomination is the request for space in a pipeline to ship gas. Pipelines use the 

nomination process to coordinate and reconcile gas from different shippers on 

their pipelines. 

A shipper purchases capacity on a pipeline by entering into a service 

agreement with that pipeline. For example, a shipper may have a firm 

transportation agreement with Pipeline A for 100,000 dekatherms (DTH) per day 

of service. Since the agreement is firm in nature, as opposed to interruptible, the 

shipper pays for that full capacity whether it uses it or not, and has priority for that 

capacity on the pipeline. 

On a given day, the shipper may not need the full 100,000 DTH of 

capacity, but might need, for instance, 75,000 DTH to meet its needs. The shipper 

will thus nominate 75,000 DTH for that day, and the pipeline can then schedule 

the unused 25,000 DTH of available pipeline capacity to another shipper as 

interruptible transportation. 

The industry-standard gas day begins each day at 9:00 AM central time, 

and runs for 24 hours. In order to standardize nominations across the interstate 

pipeline system, FERC has implemented four time cycles where shippers may 

nominate gas (or change their nominations) over the course of each gas day. 

These nomination cycles follow the NAESB standards. While this is the 

minimum number of nomination cycles that a pipeline must have in its tariff, some 

pipelines offer more nomination options. 

The first of the four standard nomination times is the “timely nomination 

cycle.” Under the timely nomination cycle, shippers must make their nominations 
Appendix: Natural Gas Transportation Contracting Practices 

Page 3 of 6 

by 11:30 AM the day before the gas is to flow. The pipeline will acknowledge 

receipt of the nomination by 11:45 AM and will issue its final confirmations by 

3:30 PM and post scheduled quantities by 4:30 PM. Gas under the timely 

nomination cycle will flow at 9:00 AM the following morning, which is the 

beginning of the gas day. 

The second nomination cycle – which also occurs prior to gas flow – is the 

“evening nomination cycle.” Shippers must make their nominations for this cycle 

by 6:00 PM the day before gas flows, and the pipeline will acknowledge receipt of 

the nomination by 6:15 PM, issuing its final confirmations by 9:00 PM and 

posting scheduled quantities by 10:00 PM. Gas under the evening nomination 

cycle will flow at 9:00 AM the following morning. During the evening 

nomination cycle, the firm shipper can adjust his nomination to his full contractual 

capacity for the next day, taking precedence over, or “bumping,” an interruptible 

shipper’s nomination. 

The two remaining cycles are known as intra-day nomination cycles, since 

they occur while gas is flowing during the same gas day. Under the intraday 1 

nomination cycle, shippers must make their nominations by 10:00 AM on the gas 

day. The pipeline will acknowledge receipt by 10:15 AM, issue its final 

confirmations by 1:00 PM, and post scheduled quantities by 2:00 PM. Gas under 

the intraday 1 nomination cycle will flow at 5:00 PM on that gas day. The same 

bumping procedures apply to the intraday 1 nomination cycle. The intraday 1 

nomination cycle is the first opportunity for shippers to adjust their gas flows 

during the gas day. 

For the intraday 2 nomination cycle, shippers must make their nominations 

by 5:00 PM, and the pipeline will acknowledge receipt of the nomination by 5:15 

PM, issue its final confirmations by 8:00 PM, and post scheduled quantities by 

9:00 PM. Gas nominated under the intraday 2 nomination cycle flows at 9:00 PM 

on the same gas day. 

Bumping rights do not apply to the intraday 2 nomination cycle. FERC 

implemented this no-bumping rule for the intraday 2 nomination cycle because 

shippers bumped this late in the gas day would be unlikely to be able to arrange 

alternative transportation. 

Confirmations

Once a nomination is received by the pipeline or the party providing the 

requested service, the nomination must be confirmed. The confirmation process 

verifies that (a) the shipper agrees to supply the nominated quantity to the pipeline 
Appendix: Natural Gas Transportation Contracting Practices 

Page 4 of 6 

for transportation, and (b) the pipeline agrees to transport the nominated quantity, 

based on the availability of capacity. The confirmation process provides a degree 

of assurance to the parties that gas will be delivered, and is also important for 

record keeping purposes. 

Scheduling

For each nomination cycle, once the shippers nominate gas on a particular 

pipeline, it is the pipeline’s responsibility to schedule the gas. Scheduling refers to 

the process by which nominations are consolidated by receipt point and by 

contract, and verified by upstream and downstream parties. If there is enough 

capacity to accommodate all nominations, then all nominated quantities will be 

scheduled. If the nominated capacity exceeds the available capacity on a pipeline, 

quantities will be allocated according to what is referred to as scheduling 

priorities. Shippers with a higher priority service will receive their capacity before 

shippers with a lower priority service. 

 Scheduling priorities for each pipeline are set forth in that pipeline’s tariff. 

Although scheduling priority specifics may differ from pipeline to pipeline, all 

follow a general priority model. In general, primary firm shippers are given 

highest priority. Firm shippers are shippers that have entered into firm 

transportation agreements with pipelines. Firm shippers reserve a volume of 

capacity on a pipeline and pay for that capacity whether they use it or not. Each 

transportation agreement specifies a primary receipt and delivery point for service 

under the agreement. In some cases, the agreements may set forth multiple 

primary receipt and delivery points that can be used. When the shippers take 

service under the primary receipt and delivery points set forth in the agreement, 

they are considered primary firm shippers, and receive the highest priority of 

service. 

In general, secondary firm shippers are given the second highest service 

priority. Under FERC policy, shippers may use receipt and/or delivery points for 

service other than the primary points set forth in their agreements, but only if 

capacity is available at those points. These alternate points are referred to as 

secondary points. In general, when a firm shipper takes service under secondary 

receipt and/or delivery points, that shipper no longer has the highest priority of 

service, but rather the second highest service priority. These secondary firm 

shippers get their gas scheduled after the primary firm shippers. 

Interruptible shippers are generally given the third highest priority service. 

Interruptible service is service that is not guaranteed. Whereas firm shippers pay 

for the capacity whether they use it or not (and are given highest priority on that 
Appendix: Natural Gas Transportation Contracting Practices 

Page 5 of 6 

capacity), interruptible shippers only pay for transportation capacity when it is 

used. 

Pipelines implement various methods for allocating interruptible capacity. 

One method is to schedule interruptible nominations pro rata, whereby all 

shippers with interruptible capacity have a proportional share of their capacity 

scheduled. Another method is based on economic ranking, where shippers who 

pay more for their interruptible capacity receive priority over shippers who pay 

less. A particular pipeline’s practices for scheduling interruptible capacity will be 

set forth in the priority provisions of its tariff. 

Nominations and Scheduling on Intrastate Natural Gas Pipelines 

 The NAESB standards do not apply to intrastate pipelines, which follow 

their own scheduling practices. Only thirteen percent of the member companies of 

the Texas Pipeline Association that responded to an informal poll reported that 

they accept electronic nominations, and none indicated that they follow the 

NAESB standards. 

In Texas, intrastate pipelines schedule gas transportation five days a week, 

with no weekend scheduling. Some intrastate pipelines do not schedule volumes at 

particular delivery points on their systems, but instead accept nominations from 

customers, typically LDCs, that can have hundreds of delivery points. These 

customers do not schedule volumes at a particular point, but submit a nomination 

that covers all of their points, with the right to obtain delivery at any of them. 

The Commission requires major non-interstate pipelines to post scheduled 

volumes no later than 10:00 PM central time the day before gas is to flow. This 

deadline occurs after interstate natural gas pipelines are required to post their 

evening cycle schedule confirmations by receipt and delivery point. 

Imbalances 

A point imbalance is the difference between the volume of gas that is 

scheduled to flow at a receipt or delivery point, and the volume of gas that actually 

flows through the point (typically determined by meters). A transportation 

imbalance is the difference between net receipts under a specific agreement (total 

receipts minus any fuel receipts), and total deliveries made under a specific 

agreement. When an imbalance occurs on a pipeline system, the pipeline must 

resolve that imbalance to keep all parties whole. There is no single method 

pipelines use to handle system imbalances. Instead, each pipeline resolves 
Appendix: Natural Gas Transportation Contracting Practices 

Page 6 of 6 

imbalances in accordance with the imbalance provisions set forth in its FERC 

NGA Gas Tariff. 

Operational Balancing Agreements 

An operational balancing agreement (OBA) is a contract between two physically 

interconnected parties specifying the procedures to be used in processing 

imbalances or differences in hourly flows between the parties. An OBA ensures 

that a shipper, once it has properly nominated and had its gas confirmed, will not 

be subjected to imbalance penalties resulting from the transfer of gas between the 

pipelines. In Order No. 587-G, the Commission adopted a requirement that each 

interstate pipeline enter into an Operational Balancing Agreement at all points of 

interconnection between its system and the system of another interstate or 

intrastate pipeline. That requirement is codified in section 284.12(b)(2)(i) of the 

Commission’s regulations. 
Appendix: GTI Report

1 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Impact of Cold Weather on Gas Production in the Texas

and New Mexico Gas Production Regions of the United

States During early February, 2011

Winterization Document

Prepared for Federal Energy Regulatory Commission

Prepared by Gas Technology Institute

Kent F. Perry

July, 2011
Appendix: GTI Report

2 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Table of Contents                       Page

Introduction                     5

The Phenomena of Wellhead Freezing and Cold Weather Impact on Gas Production  

Operations                     5

Potential for Freezing ‐ Within the Reservoir, Wellbore and Wellhead       6

Potential for Freezing ‐ Gas Well Production Facilities Located at or Near the Wellhead    9   

Potential for Freezing ‐ Gas Gathering System Including Compressor Stations and  

Gas Processing Plants                   11

Prevention of Wellbore, Wellhead and Production Facilities from Freezing – General  

Discussion and Description                 16

Alternatives to Cold Weather Control Techniques           25

Discussion of Gas Hydrates Formation               26

Gas Quality Considerations and Gas Processing             28

Discussion of Cost Implications to Winterize Gas Wells – Per Well Cost and Per Field Cost

Cold Weather Production Equipment                 30   

      

References                     37
Appendix: GTI Report

3 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figures                                        Page

          

Figure 1 ‐ Schematic of Gas Reservoir (Barnett Shale as example), Wellbore

and Wellhead Flow Paths to Production Facilities       7

Figure2 ‐ Gas Well Producing Location with Typical Equipment for Gas Production                                   

Operations– Does Not Include Gas Processing or Compressor Station       10

Figure3 ‐ Gas Flow Diagram – Dry Gas from Dehydration Facilities through Gas Compression

and Gas Processing Plant                 12

Figure 4 ‐ Natural Gas Compressors within the U.S. Natural Gas System       13

Figure 5 ‐ Fully Enclosed, Insulated and Heated Compressor; For Cold Weather  

Environments                       14

           

Figure 6 ‐ Flowchart for A Gas Processing Facility – Illustrates the Complexity Of the  

Process and the Many Steps That Can Be Required             16

Figure 7 ‐ Methanol Injection Pump Utilized to Inject Methanol into a Wellhead

and/or Flow Line to Prevent Freezing and Hydrate Buildup         18

Figure 8 ‐ Fiberglass Housing Surrounding Production Equipment at Gas Storage

Field in Midwest United States                 19

Figure 9 ‐ Gas Wellhead with Insulation on Flow line to Protect Freezing       20

Figure 10 ‐ Gas Production Wellhead and Production Equipment In  

Northern Region of United States Winterized for Cold Weather Operations     21

Figure 11‐ Pipeline Pig Inside of Cut out Section of Pipeline           22

Figure 12 ‐ Pipeline Pig Launch and Receiving Station           23

Figure 13 ‐ Typical Wellhead in Warm Climate             25

Figure 14 ‐ Hydrate Photos – Inset is the Water‐Methane Hydrate Structure     27

Figure 15 ‐ Methane Hydrate Phase Diagram             28

Figure 16 ‐ Barnett Shale Gas Development Area near Dallas, TX         31
Appendix: GTI Report

4 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Tables                                      Page

        

Table 1 – Points of Freezing Potential in the Reservoir, Wellbore and Wellhead     16

Table 2– Potential for Freezing – Gas Well Production Facilities Located at or Near

the Wellhead                     10

Table 3 – Barnett Shale Gas Compositions               29

Table 4 ‐ Winterization Equipment Cost for a Gas Well Located in a Cold Climate     33

Table 5 – Cumulative Cost for Winterizing Gas Wells – Variable Well Counts and  

Individual Well Equipment Cost.                 35

Table 6 – Itemization of Capital and Operating Expenses for a Typical Gas Well     36
Appendix: GTI Report

5 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Introduction

Colder‐than‐normal weather during the first week in February led to the biggest non‐hurricane natural

gas supply disruption in the United States since at least 2005.  

Due to a combination of well freeze‐offs (gas flow blockages resulting from water vapor freezing in the

gas stream) and other temperature‐related well failures, processing plant shutdowns, electric power

outages, and pipeline operational issues, estimated daily natural gas production fell from about 62

billion cubic feet per day (Bcfd) to less than 57 Bcfd, a decrease of 8%. (Ref. 1)

The cold weather likely impacted thousands of natural gas wells in Texas and Louisiana, home to one‐

third of U.S. gas production. Because it rarely freezes in these southern U.S. latitudes gas wells aren’t

built to withstand the phenomenon called "well head freeze off." That’s when the small amount of

water produced alongside the natural gas crystallizes inside pipelines, completely blocking off the flow

and shutting down the well.

In particular, along with the cold weather came severe icing conditions.  Icy roads inhibited the

movement of water hauling trucks in particular and the ability to access wellheads.  The result was that

fail safe switches on water and condensate storage tanks at wellheads and at compressor stations

were activated.  The fail safe switches are designed to shut down operations to prevent spills. (Ref. 2)

This report focuses on gas well winterization technology that is deployed in colder climates and

discusses to what degree they might be applied to the impacted production areas (Texas and New

Mexico) addressed with this study.  

The Phenomena of Wellhead Freezing and Cold Weather Impact on Gas 

Production Operations

Freezing is a potential and serious problem starting at the production wellhead through the last point

in the customer delivery system.  The occurrence of freezing is continuously reduced each step of the

way, but care must be taken at each and every step to assure smooth operational conditions and

satisfied consumers at the end of the line.  Freezing not only affects the wellhead and gas pipeline but

is also a significant contributor to measurement errors, instrumentation upsets or failures and other

regulation equipment that can be found at compressor stations, gas processing plants, regulator

stations and other critical points of operation.  (Ref. 3)

Many criteria can have an impact on the freezing issue including:

 Gas quality and composition

 Wellhead and wellbore design and configuration

 Piping designs, regulation or restriction points
Appendix: GTI Report

6 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

 Instrument take‐off points

 Other  

Three areas will be reviewed as to the potential for freezing due to cold weather conditions:

1. The reservoir, wellbore and wellhead environment.

2. The gas well production facilities located at or near the wellhead.

3. The gas gathering system including compressor stations and gas processing plants.  

Potential for Freezing ‐ Within the Reservoir, Wellbore and Wellhead

Natural gas resides in geologic formations for time periods of millions of years (geologic time).  Over

this extended time period the gas becomes saturated with water. The volume of water that natural gas

can carry as water vapor is a function of pressure, temperature and gas composition.  Figure 1 is a

schematic of a gas reservoir (Barnett shale in this example), its gas quality, reservoir conditions and gas

flow pathway from the reservoir to the surface.  The gas flows from the reservoir through perforations

in the pipe (casing) and then up through the production tubing, through the wellhead and then to

production facilities.   
Appendix: GTI Report

7 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 1 – Schematic of Gas Reservoir (Barnett Shale as example), wellbore and wellhead flow paths

to Production Facilities, (Ref. 4&5) (Figure from GTI)  

Under the Barnett example reservoir conditions the gas can hold as much as 181 lbs of water per mmcf

of natural gas.  For production operations, 7 lbs of gas per mmcf is considered to be dry gas, or at least

dry enough for safe and efficient transportation of the gas without undo problems due to water fallout

or freezing.  Many natural gas compositions include not just methane CH4 but also heavier

hydrocarbons such as ethane and propane.  In the Barnett example, the composition of well #2

contains over 11% ethane and 5% propane.  The existence of these heavier hydrocarbons can facilitate

the formation of hydrates (a combination of hydrocarbons and water that form ice under conditions

well above freezing).  Hydrates are discussed in more detail later but for this discussion can be thought

of as ice capable of reduction or complete blockage of gas flow. (Ref. 4 &5)   

As the gas flows up the production tubing and nears the surface it experiences a drop in pressure and

can also be cooled by gas expansion (Joule Thompson effect) and exposure to cold ambient

temperatures at the surface.  The Joule‐Thomson rule of temperature effect as a result of pressure

reduction is such that temperature will decrease approximately 7 degrees Fahrenheit for every 100 psi
Appendix: GTI Report

8 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

pressure reduction. As an example, if you can have gas flowing at 60 degrees Fahrenheit and 700 psi

and you may have no evidence of freezing.  If you pass through a flow choke and cut the pressure to

225 psi, the flowing temperature at the point of regulation will drop 33 degrees to approximately 27

degrees Fahrenheit.  If the gas stream is saturated with water vapor and condensate, you will quickly

experience freezing. The gas stream is the same, but conditions have changed and icing problems can

impact your operations. (Ref. 3 &4)   

The presence of ice or hydrates can not only shut off the pipeline, but can also alter measurement.  If

ice forms on the rim of the orifice plate, the flow measurement will be in error as a result of the

reduced orifice diameter.  If ice forms in the instrumentation supply lines, controllers will cease to

function causing a loss of control of the system. Ice can block off sensing ports and other vital

instrument readings.  Once the ice begins to thaw, problems are still going to be present. On the initial

start‐up of a new or cold well, probes, intrusive instruments and orifice plates should have been

removed from the pipeline.  Large balls of ice traveling down the pipeline can do physical damage to

the pipeline itself and to any object protruding into the pipeline such as sample probes, temperature

probes, meters, orifice plates and similar intrusive devices. After the flowing stream has stabilized and

temperature conditions are above the hydrate point, these items can be safely re‐installed. (Ref. 3 &4)   

The likely areas for icing and/or hydrate buildup and the typical solution for these problems as applied

in cold weather climates are described in Table 1.  See also Figure 1.  

Table 1 – Points of Freezing Potential in the Reservoir, Wellbore and Wellhead (Ref.4)    

Point of Freezing

Potential

Cause of Freezing Solution

Near Surface 

Wellbore 

As the natural gas travels from the

reservoir to the surface, cooling can

occur due to gas expansion and

exposure to colder temperatures near

the surface.

Methanol is injected into the flow

stream at the wellhead.  The flow of

methanol is down the wellbore

annulus and then is carried up the gas

flow stream through the wellhead

preventing freezing.

Wellhead 

including 

Wellhead Valves

At the wellhead a change in flow path

size can change causing an increase in

velocity and cooling.  Well head also

exposed to surface weather conditions.

Solution is as above, methanol

injection.  In some cases the wellhead

can be completely enclosed in a small

building or “hut”, insulated and

heated, but methanol is the most

practiced solution.  

Wellhead Chokes  Wellhead chokes are points at the

wellhead where flow and pressure is

primarily controlled. Significant pressure

As above with methanol application.

Also, wellhead design should consider

choke points and avoid wherever
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9 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

drop often occurs and expansion cooling

can be severe.  This cooling combined

with cold ambient temperatures can

cause significant freezing issues.  

possible.  

Potential for Freezing – Gas Well Production Facilities Located at or Near

the Wellhead

The basic flow of natural gas from a wellhead through the processing equipment and to the gas sales

distribution system is illustrated in Figure 2.  Note that this is described as a typical configuration

keeping in mind that variations to equipment placement and metering occur dependent upon the

number of wells, their proximity to each other, well ownership and other factors.

Referencing Figure 2, when gas leaves the wellhead it sometimes flows through a line heater which will

warm the gas, any gas condensate and water within the flow stream, mitigating freezing and

facilitating the separation of these three phases. (Line heaters are not always deployed in warmer

production climates unless large flow volumes requiring pre‐heating before separation of phases are

experienced).  The flow stream next enters the production separator (sometimes described as a heater

treater) where gravity, heat and flow through mesh material separate the gas condensate from gas and

from water.  The condensate and water flow to storage tanks through liquid meters in some cases, or

alternatively volumes are measured directly within the storage tank. These liquids are marketed by

truck or pipeline in the case of condensate and the water sent to disposal facilities by truck or pipeline

dependent on volumes and distances.  

The gas flow stream exits the top of the production separator and flows to the dehydration unit.  It is

noted that the gas, while free of liquid phase water and condensate at this stage, is still saturated with

liquid vapors notably water.  Gas flows into a dehydration unit for removal of water or dehydration of

the gas, drying it to normally 7 lbs/mmcf or less allowing for transport without freezing and water

fallout issues.  The normal dehydration process utilizes glycol which absorbs the water from the gas

leaving the hydrocarbons within the flow stream.  The glycol when saturated with water is sent to a

glycol reboiler that through application of heat boils off the water.  The dry gas is now metered and

flows to the gas gathering system.  (Ref. 4&6)   
Appendix: GTI Report

10 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 2 – Gas Well Producing Location with Typical Equipment for Gas Production Operations – Does

not Include Gas Processing or Compressor Station. Production Equipment is Equipped with Fail Safe

Devices to Shut‐in Production to Avoid Spillage and Equipment Damage ‐ (Ref. 4&6). (Figure from

GTI)

The likely areas for icing and/or hydrate buildup and the typical solution for these problems as applied

in cold weather climates are described in the following Table 2.  See also Figure 2.

Table 2– Potential for Freezing – Gas Well Production Facilities Located at or Near the Wellhead.

(Ref. 3, 4&6)  

Cause of Freezing Solution Utilized in Colder Gas

Production Regions

Flow lines from 

wellhead to line 

heater. If no line 

heater (common in 

warmer regions) 

Exposure to low surface temperatures,

gas has cooled due to expansion, gas

contains water and heavier

hydrocarbons which are prone to

freezing or hydrate development.  

Methanol injection, line heating,

maintaining level flow lines to avoid

liquid build‐up, and limit choking

points.  Additional protection is

usually required including insulating
Appendix: GTI Report

11 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

then flow line to 

separator. 

flow lines, wrapping with heat tape or

glycol tubing under the insulation.  

Production 

Separator

The production separator has

equipment and instrumentation that

can be impacted by cold weather. Gas,

water and condensate flow throughout

the unit.  It is exposed to surface

temperatures.  

The unit is sometimes placed in a

heated housing unit or hut.

Alternatively, a cold weather version

needs to be utilized. The cold weather

unit is designed such that all piping

and potential freeze instruments are

internalized to the unit or insulated.  

Gas Flow lines to 

Dehydration 

Facilities 

If exposed these lines, which are still

carrying water saturated gas and other

hydrocarbons are prone to freezing and

hydrate formation. This can take place

in a particularly exposed portion of the

line or at a bend or reduction in line

size.  

Sometimes these lines can be buried if

it is some distance to the dehydration

facility. This alone may not be

adequate and insulation and heating

may be required.  A methanol

injection point can be designed into

the flow scheme if a particular area

becomes a problem.    

Flow Line to Sales 

Meter and Meter

The gas flowing to the sales meter has

now been dried and is much less prone

to freezing.  The gas however can still

be comprised of ethane and higher

hydrocarbons as well as CO2 or N2 or

other constituents.  Depending on

conditions of T & P Hydrates can still

form despite dry (water content) gas.  

Hydrate control can be achieved

through application of heat, housing

the meter and protecting from

weather, methanol injection and

other techniques described for

managing wet gas freezing.

Condensate and 

Water Lines and 

Storage Tanks. 

The lines to the storage tanks are at low

pressures and the water is usually brine

so freezing and hydrates are not as

much of an issue. Depending on fluids

and climate however some freezing can

occur. If this takes place in the flow

lines it can disrupt the separator

causing production shut‐in.  

These lines can be insulated or in

severe conditions heated with electric

tape or glycol tubing. The tanks

themselves do not normally present a

problem.  

Potential for Freezing ‐ Gas Gathering System Including Compressor

Stations and Gas Processing Plants.

After natural gas leaves the wellhead and wellhead production site it continues flow downstream

through the natural gas system (Figure 3).   Along the way, gas compression is required to maintain

pressure and gas processing is applied to further dry the gas and remove heavy hydrocarbon

components.  Each is discussed further in this section.  
Appendix: GTI Report

12 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 3 – Gas Flow Diagram – Dry Gas from Dehydration Facilities through Gas Compression and Gas

Processing Plant.  (Figure from GTI and ABB Oil and Gas and Duke Energy Canada)

Compression ‐ After the natural gas stream leaves the dehydration facility it will at times flow through

a compression facility or single compressor. The purpose of this is to boost the pressure of the gas such

that it is able to flow into a sales line that is at higher pressure.   The natural gas industry utilizes a large

number and wide variety of compressors.  Overall greater than 45,000 compressors are in place in the

United States (Figure 4) (Ref. 7).
Appendix: GTI Report

13 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Compressor

Station

Compressor

Station

 Production

32,000 Compressors

 Processing

5,000 Compressors

Transmission & Storage

 8,500 Compressors

 Distribution

 0 Compressors

Compressor

Station

Figure 4 – Natural Gas Compressors in the U.S. Natural Gas System (Ref. 9) (Diagram from Wikimedia

Commons)

Compression facilities range from small single compressors to large facilities handling large volumes of

gas at aggregation points. The compression facilities within a producing gas field will change with time

due to several factors:

 The drilling of new wells over time introduces increased gas volumes in a gas producing region.

 Existing wells will decline in gas production volumes over time reducing gas volumes.

 Gas flowing from the wellhead is initially at high pressure but then declines as gas is produced.

This decline can be very rapid for the newer gas shale wells being developed, requiring

compression facilities to be installed at appropriate points to keep wells flowing.   

 The older well flow rates (at low pressure) will be reduced by the high pressure new wells in the

absence of compression facilities.  It is under these circumstances that new and sometimes

remotely located compressors are installed.

The overall effect of these changing conditions is that compressors may need to installed, removed or

resized based on the many factors impacting their size and number requirements.   

The impact of cold weather on compressor stations can vary.  Compressors stations all have safe guard

instrumentation that senses temperature, pressures and flow rates.  If pressure, as an example, gets

too high or too low, the compressor will shut itself down to prevent expensive damage.  These

instrumentation processes can be impacted by cold weather.  In colder climates, compressors can be

housed to protect against any severe weather conditions (Figure 5).  The majority of these compressors

are fueled by natural gas as it is readily available due to it being the medium being compressed and

transported. (Ref. 4, 7, 8)
Appendix: GTI Report

14 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Compressor stations take low pressure gas and increase the pressure significantly which is

accompanied with temperature increases of the gas flow stream.  Changes in pressure and

temperature will cause additional liquids to drop out of the gas stream.  The temperature and pressure

conditions can vary considerably at these facilities.  Some of the variables and conditions involved

include:

 Pressure changes can occur; pressures can be dropped to manage the inlet pressure conditions

to the compressor. High pressure and low pressure wells may be feeding the inlet side of the

compressor.  These well pressures are brought into balance at the inlet section of the

compressor by dropping some well pressures to balance with the low pressure wells.  

 The drop in pressure can cause gas cooling (Joule Thompson effect).

 Increasing pressure through the compression facility can cause gas heating.

 Temperatures and pressures are monitored throughout the compressor system and automatic

shut down devices will be activated if they deviate from a defined range (too high or too low).  

 Many of these changes can cause liquids (water and condensate) to condense from the gas

stream and need to be removed and stored in nearby storage tanks.

 The storage tanks must be emptied on a regular schedule or fail safe shut‐in devices will

activate.   

In urban areas (Dallas Ft. Worth as an example) electric compression is sometimes required due to

noise limitations or emissions constraints.  These facilities in particular are subject to any reduction in

electric power due to weather or other conditions.  There are some electric compression facilities in

the Ft. Worth area but not in large enough numbers to have significant impact on gas production.  (Ref.

4, 7, 8, 9)   
Appendix: GTI Report

15 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 5 ‐ Fully enclosed, insulated and heated compressor; for cold weather environments. The unit

offers metering, separation, and compression, all on one skid. (Photo Wikimedia Commons)

Larger compressor facilities are located at gas aggregation points where larger volumes of gas are

compressed to higher pressures.  These can be complex facilities with extensive piping, metering, and

instrumentation.  Cold weather can impact these facilities similar to smaller, more remote facilities.  

The incentive to weatherize however is greater at these locations due to the size and gas flow rates

they address.  There is an economic incentive as well as a reliability of service incentive to maintain

flow at these aggregation points.  The technology is readily available for winterization of these facilities

and is commonly applied in colder regions of the country.  As with the wellhead and production sites,

the weatherization approach is a combination of heating important components via electric supply or

warmed liquid flow (glycol), insulation of components, housing critical portions of the facility, injection

of anti‐freeze type chemicals (methanol), drying of the gas flow components, drying instrumentation

gas via desiccants or other drying medium, or a combination of these techniques.  (Ref. 4, 6)

Gas processing plants function to remove heavier hydrocarbons from the gas stream.  These include

ethane, propane, butane and others.  There are three factors that drive the gas processing business:

1. The need to control gas heating value (BTU).  Gas going into most end use functions

(residential, commercial) requires gas within a certain BTU range which is often a narrow

window around 1000 BTU/Ft3 of gas.

2. For gas to be transported long distances through interstate pipeline systems it needs to be

relatively free of heavier hydrocarbons.  The heavier constituents will eventually precipitate

during the pressure ups and downs encountered during long distance transportation. They

then form liquids inside of the pipeline causing an unwanted pressure drop, freezing (through

hydrate formation) or other interference.

3. With high oil prices, liquids are more valuable than natural gas.  Therefore an economic

incentive exists to remove the heavier hydrocarbons and sell into the liquids market as

opposed to keeping them in the gas phase and selling based on BTU value alone.  

These plants can be very complex (Figure 6) with extensive piping, processing units, regulators,

instrumentation and other components.  Many of these components can be impacted by weather

conditions and to assure ongoing processing plant operation must be protected against weather. (Ref.

4, 10)
Appendix: GTI Report

16 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 6 – Flowchart for a Gas Processing Facility – Illustrates the Complexity of the Process and the

many Steps that can be Required.  Levels of Complexity vary from Plant to Plant based on Need.

(From ABB Oil and Gas).

Gas processing plants operate in cold weather climates along with other gas production facilities and

as such, winterization equipment and processes are well known. It is a matter of frequency of events

(cold weather) and the amount of time the facility is impacted, vs. the cost and time to winterize.  

Some processing plants have adequate piping and flow schematics to bypass some processes that

might be impacted by cold weather. (Ref. 10)   

Prevention of Wellbore, Wellhead and Production Facilities from Freezing –

General Discussion and Description  

There are several options for the prevention of freezing problems.  Many of these are practiced on a

regular basis in the colder regions of the country, to a lesser extent in the Mid‐Continent region of the

United State and not at all (in many cases) in Southern regions of the country.  In order to correct

freezing problems that occur under differing operational conditions, solutions must be designed for the

particular needs of the location where the problem exists.  Protection against freezing requires

deployment of one or more mitigation techniques. Each of these techniques requires and investment

in capital and operating expenses.  The application of these techniques is usually determined by the
Appendix: GTI Report

17 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

need or frequency of use along with the consequences (loss of production for a certain time period) of

not utilizing.    

In Southern regions of the United States, cold weather can be infrequent and when it does occur, can

be limited in duration.  A consequence is that the investment in freeze protection equipment and

operations can be limited.  The consequence to the producing life of a well can be minimal compared

to the investment for cold weather operations in that lost production occurs for several days from a

well with 20‐30 years of operation life.  On the other hand, if the level of impact is similar to the events

of early February, 2011 and occurs on a more frequent basis, there can be a detrimental impact to the

overall natural gas industry, as lack of reliability and accountability can result in loss of market. (Ref. 4)

Described below in general order of frequency of use are several techniques that can be applied to

prevent freezing in gas operations:

1. Methanol Injection to Prevent Freezing ‐ Methanol (an anti‐freeze type solution) injection is a

very common practice for freeze protection of wellbores and pipelines where wet gas flow

occurs.  Injection down the annulus of a wellbore by chemical injection pumps is utilized in

production facilities in cold climates and in many gas storage operations where reliable, high

flow rates in cold weather is required.  The same technique can be practiced within a pipeline

system and production facilities.  The methanol is injected into the gas stream by chemical

injection pumps or enters the pipeline by methanol drips and effectively lowers the freeze

point of the gas. The amounts of methanol required can be calculated by using available tables

for specific applications.  

A small volume methanol tower can also be fabricated allowing small volumes of gas to pass

through the methanol for treatment. Because of the sensitive nature of many pneumatic

controllers, this method is occasionally used to prevent freeze‐ups in these devices and to

prevent liquid migration into small orifices and passages. An additional filter is often used to

ensure that the methanol is not carried over into the instrumentation. (Ref. 4, 11)
Appendix: GTI Report

18 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 7 – Methanol Injection Pump Utilized to Inject Methanol into a Wellhead and/or Flow

line to Prevent Freezing and Hydrate Buildup. Usually Located in Protected Housing on the

Gas Well Location.  (Ref. 11)  (Photo Source ZKO Oilfield Industries; PTAC.org)

2. Buildings or “Huts” to Enclose Production Equipment and other Weather Sensitive Equipment

Buildings are often constructed to house weather sensitive equipment in cold weather.  This

can be the preferred method for protecting production equipment and is widely applied in

colder climates. The housing can be heated by catalytic heaters and can be insulated as needed

for the extremes of weather conditions anticipated.

Figure 8 is a typical setup for a Midwest Gas Storage Field (Manlove Gas Storage Field near

Champaign, IL).  The green fiberglass housing structure protects metering and other production

equipment from freezing.  Heating devices of various types can be utilized within the structure.

Methanol chemical injection pumps are housed within the structure. During gas withdrawal

operations (winter conditions) methanol is injected into the wellbore to prevent freezing.  The

wellhead itself is not enclosed.  The wellhead is left open to allow for workover rigs to access

the wellbore for any type of downhole maintenance required.  Also, the heating of the

wellhead may not preclude the formation of gas hydrates down in the wellbore some distance.  

This requires methanol injection as described in #1 above (Ref. 4, 12)
Appendix: GTI Report

19 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 8 ‐ Fiberglass Housing Surrounding Production Equipment at Gas Storage Field in Midwest

United States (Ref. 12) (Photo credit Wikimedia Commons)

3. Water Removal from the Gas Stream by Glycol Dehydration.  Gas dehydration is practiced on

all natural gas flow systems to enable flow of gas without problems of hydrate formation,

freezing, water drop out, corrosion and other issues.  One of the most common methods of

dehydration for large volumes of gas is glycol absorption. Gas passes through the glycol inside a

vessel called a contactor (See Figure 2).  The object is to remove the water to a point where the

water vapor dew point of the gas will not be attained at the highest pressure and lowest

temperature of the pipeline system. The glycol absorbs water and is then treated by circulating

the glycol to a regenerator and distilling the water out of the glycol. The reconditioned glycol is

returned to the contractor and the procedure is repeated. This process can reduce the water

dew point to 60‐70 degrees Fahrenheit. Colder climates frequently dictate a dehydration

system in a natural gas system, but even warmer climates may require central dehydration due

to pressure, temperature and gas composition. A producer can basically look at three

dehydration options.  

a. Partial dehydration at the well head and later additional steps to meet contract

specifications.

b. Chemical injection at the well head with later dehydration at the central delivery point.  

c. Full and complete dehydration at each and every well head.  
Appendix: GTI Report

20 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

The glycol dehydration system is a low cost system with continuous operation and minimal

pressure loss across the unit, thus making it a preferred approach in several areas of operation.

The drawbacks can be glycol carry‐over during surges, contamination by solid particles and

inefficiency during fluctuating flow rates. (Ref. 4, 13)

4. Heat Application for freeze protection ‐ Heat is a logical solution to freezing problems. It is also

a costly approach to the problem for several reasons. Obviously, if the gas is never allowed to

reach freezing temperatures, ice cannot form and will not be present. The water will likely not

be removed, which remains an issue for operations and contracts, but the freezing is

eliminated. The problems with heat are that it is expensive equipment to install, it requires

additional fuel (energy and revenue) to produce the heat, and the heat will not remain

effective as it travels down the pipeline and away from the heat source. Heat is also a potential

hazard as it can provide an ignition point for the gas. Safety and special emphasis on proper

application is a must when using a heat source. The most common application of heat for

freeze protection is in a specific and direct situation, as in the case of a regulator valve body.

The pressure drop at the regulator is the only problem point and therefore, can be the only

specific location where freeze protection is required. There are multiple ways to apply heat

from heating blankets, to catalytic heaters, to fuel line heaters, or in some cases, steam

systems where they are properly designed, installed and maintained. Heat systems can be very

effective for a localized freezing problem.  Heat application coupled with insulation is a

common technique for protecting flow lines in northern climates. (Figure 11).  (Ref. 3)

Figure 9 – Gas Wellhead with Insulation on Flow line to Protect Freezing.  (Photo Courtesy of

ABB Oil and Gas)
Appendix: GTI Report

21 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

5. Combination of Techniques are Often Utilized – A combination of winterization techniques are

often required to fully protect a gas well production facility.  Figure 10 illustrates a typical

installation for a cold climate.

Figure 10 – Gas Production Wellhead and Production Equipment in Northern Region of United States

Winterized for Cold Weather Operations. (Photo Source ZKO Oilfield Industries; PTAC.org and

modified by GTI)

Referencing Figure 10, the following equipment and steps are practiced for flow assurance in cold

weather climates:

 Flow lines are insulated.  

 All wellheads are set up to inject Methanol which is done throughout the cold months.

 Assurance that flow lines are level, avoiding low spots where water can accumulate.

 Utilization of gas fired line heaters ahead of the production separators to keep all fluids warm

enough to avoid freezing prior to separation of gas, gas condensate and water phases (See

Figure 6).
Appendix: GTI Report

22 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

 All flow lines beyond the production separator are insulated and heat traced. This is

accomplished by electrical heat tape when electricity is available.  Where there is no electric

service, glycol tubes for circulating glycol are utilized to maintain flowing temperatures.

 Minimizing flow chokes is also practiced wherever feasible. Flow chokes are notorious Joule

Thompson freeze points.

 Fiberglass huts over the wellheads are sometimes considered but difficult to accommodate due

to impediments to accessing the wellbore for work‐over and other considerations. (Ref. 3, 4, 6,

11)

6. Pipeline Pigging ‐  Pigging in the maintenance of gas pipelines refers to the practice of using

pipeline inspection gauges or 'pigs' to perform various operations on a pipeline without

stopping the flow of the gas in the pipeline (Figure 11).

Figure 11 – Pipeline Pig Inside of Cut out Section of Pipeline (Photo Credit Wikimedia      

Commons).

These operations include but are not limited to cleaning and inspecting of the pipeline. This is

accomplished by inserting the pig into a 'pig launcher. The launcher / launching station is then

closed and the pressure of the product in the pipeline is used to push it along down the pipe

until it reaches the receiving trap ‐ the 'pig catcher' (Figure 12).  (Ref. 14)
Appendix: GTI Report

23 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 12 – Pipeline Pig Launch and Receiving Station (Photo credit Wikimedia Commons).

If the pipeline contains butterfly valves or other restrictions in line diameter the pipeline cannot

be pigged. Pigging has been used for many years to clean larger diameter pipelines in the oil

industry. Today, however, the use of smaller diameter pigging systems is now increasing in

many areas to maintain pipeline flow integrity.   

Pigs are also used in gas pipelines where they are used to clean the pipes, but also there are

"smart pigs" used to measure pipe properties such as pipe thickness and corrosion.  They

usually do not interrupt production, though some natural gas can be lost when the pig is

extracted.  Most of the pigging operations are deployed in the gas gathering, transmission and

distribution portions of the gas system as opposed to the wellhead production areas where

pipeline configurations and sizes do not allow for pigging operations.

Pigging operations are conducted on a year around basis as needed to keep pipelines in

working flow conditions.  During cold weather their deployment can be increased due to

additional liquids fallout and due to increased flow rates during cold weather.  (Ref. 14)   

7. Practical Piping and Equipment Construction Considerations for Freeze Protection ‐ During the

design phase of the piping and the instrumentation system, certain steps can be taken to

reduce the negative effects of freezing problems. Piping configurations that would allow for

liquid accumulation should be avoided if at all possible. Drainage should slope towards drain

fittings located at low spots. Where possible, use ball valves and large diameter tubing for

instrument feed lines and sensing lines. Avoid restrictions where flow will occur.  Limit choking

points.  Tubing runs should slope back toward the pipeline and you should have a leak free
Appendix: GTI Report

24 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

instrument system. Liquids, if they are present, will be drawn towards the leak. If you avoid

creating traps and liquid drop out areas, your freezing problems will be minimized. (Ref. 3, 4).  

8. Other Water Removal Techniques for Cold Weather Protection, Especially for

Instrumentation  

a. Solid Absorption ‐ A very efficient method of water removal is the dry bed or molecular

sieve method. The gas is passed through large towers of solid particles and the

molecular sieve absorbs the water very aggressively. Very dry gas over a wide range of

flow rates can be attained by this method. Eventually, the sieve becomes saturated and

must be regenerated. The stream must be switched to a second tower and hot gas is

introduced to the original unit to evaporate the water and dry the sieve. Cool gas is

then used to cool the desiccant and the tower is ready for re‐use. This cycle is repeated

until the desiccant has degenerated and is no longer effective. While this method

produces very dry gas and has several positive operating characteristics, it is more

costly than typical glycol systems and more complex to operate.  If the gas contains

heavier hydrocarbons they can sometimes interfere with the sieves.

b. Drip pots, coalescers and automatic liquid dumps can reduce freezing problems on

instrumentation ‐ Occasional slugs of liquid can damage or even “shut in” many

instrument supply systems. Where this slug potential exists or in cases where liquid is a

severe problem in the gas supply used for instrumentation, drip pots and coalescers can

effectively knockout or reduce the water and condensate in a small volume instrument

supply system.  If the problem is excessive, an automatic liquid dump designed for

instrumentation can be extremely helpful. Whereas the drip pot requires routine

manual draining, the automatic liquid dump will act as a drip pot collection vessel with

a coalescer and as a result of an internal float assembly and pivot valve, will

automatically release the collected liquid to a lower pressure point.

c. Instrument filters designed for freeze protection to control equipment ‐ Many

instrument controllers and other sensitive measurement equipment powered by

instrument gas supply need the highest level of clean and dry instrument supply that is

attainable. In some cases a good linear polyethylene filter can provide adequate

protection. But the most common solution for instrument supply gas is the filter dryer.

These units are designed for high pressure applications with removable media

cartridges. While various types of media are available from molecular sieve to special

H2S removal media, most are equipped with a combination desiccant and charcoal filter

cartridge. Coupled with providing extremely dry and fresh gas, the ancillary filtration

elements in the cartridge provide for 2‐4 micron protection as well. (Ref. 3, 4).
Appendix: GTI Report

25 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Natural gas systems, from mainstream pipeline flow to low pressure instrumentation, are subject to

freezing conditions.  Figure 10 is contrasted with Figure 13 where a non winterized location is

illustrated.  

Through careful planning and evaluation of a specific application, proper selection of available options,

and a good routine maintenance program, this industry wide concern can be controlled and minimized.

The cost of dealing with the aftermath can be more expensive than the preventative action that could

have been taken.   

Figure 13 ‐ Typical wellhead in Warm Climate. (GTI)  No methanol or other injection equipment for

freeze mitigation.  Flow line is elevated without insulation of other protection from cold weather.  Tank

battery and other production equipment are not protected from cold weather. (Ref. 4)  

Alternatives to Cold Weather Control Techniques

Emissions of natural gas and other greenhouse gases are under increasing scrutiny as the concern

about global warming continues to grow.  Natural gas can be emitted to the atmosphere in many

locations along the gas system.  The gas industry has taken steps to mitigate these releases and

continues to do so.  Gas dehydration facilities are one step in the process where some gas is emitted.  

The dehydration step is required to remove water vapor from the gas stream to allow for safe and

efficient transportation of the gas, and in particular to avoid gas line freeze‐up when weather

conditions turn cold.

One alternative to gas dehydration is the continuous injection of methanol into the system from the

wellhead to a point of aggregation of the gas where it can be dried to pipeline specifications.  This

practice would eliminate the need for many individual dehydration facilities and thus the gas

emissions.  This is relevant when discussing flow assurance under cold weather conditions as well. The
Appendix: GTI Report

26 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

injection of methanol could have the additional impact of avoiding freezing conditions within the gas

flow system.  This mechanism is practiced in the offshore environment where long pipelines transport

oil, gas and water to onshore facilities for processing.  Application of this technique onshore however,

is often hampered by the many different mineral owners involved with each well.  Each mineral owner

has a royalty interest in the well allowing him a percentage of the revenue generated.  This requires

that a gas sales meter be installed to measure his appropriate share prior to mixing the flow volume

with another well.  Accurate gas measurement requires dry, liquid free gas leading to dehydration

facilities at most wells.  In the offshore environment there is only one royalty owner, the Federal

Government. (Ref. 4, 11)

Discussion of Gas Hydrates Formation

Gas hydrate formation, also known as freezing, is a potentially serious problem in natural gas flow lines

starting at the production well all the way through to the customer delivery system. The effective

inhibition of hydrate formation, especially during cold weather, is essential for producers and

transmission companies if they are to maintain a continuous supply of natural gas. Methods to control

freezing range from removing water from the gas stream to lowering the water's dew point by

injection of chemicals such as methanol.  

Natural gas hydrates are ice‐like substances that form through entrapment of hydrocarbon molecules

inside the lattice of ice crystals.  Hydrate crystals are formed under certain pressure and temperature

conditions where the temperature may be above the melting temperature of ice.  Many types of

hydrates can form based on the presence of various gases.  These include methane, ethane and

propane hydrates, carbon dioxide and nitrogen hydrates and others.

Hydrates are very complex systems and their formation and dissolution remain a topic of ongoing

research.  They are known to exist in nature and form frequently within natural gas flow systems from

the wellbore through the distribution systems for natural gas.  They have been known to plug pipelines

in the Gulf of Mexico for thousands of feet shutting in flow from multiple production platforms and

significantly interrupting gas supply.  In the Gulf of Mexico, where flow lines lay on the ocean floor in

deep, cold water, and where the flow through the pipelines includes oil, gas and water prior to

separation at onshore facilities; hydrate formation is a threat throughout the year. The solution to this

problem is simply to inject methanol and other chemicals that inhibit hydrate development.  This is

performed as an ongoing operation and continues to be practiced.  Research continues to better

understand and control the formation of hydrates under these conditions, but today the application of

methanol is the only effective solution. (Ref 4, 16)  
Appendix: GTI Report

27 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 14 – Hydrate Photos – Inset is the Water‐ Methane Hydrate Structure (Ref. 16, 17) (Photo Credits

National Energy Technology Center (DOE) and Wikimedia Commons)

Figure 14 is comprised of two hydrate photos, one illustrating the melting of hydrates with the

associated release of methane which has been ignited.  It is through this phenomenon that the term

“burning ice” is often used when describing hydrates.  The smaller inset figure illustrates the hydrate

cage formed by water and methane.  

Methane hydrate, much like ice, is a material very much tied to its environment—it requires very specific

conditions to form and be stable. Remove it from those conditions, and it will quickly dissociate into water and

methane gas.  A key area of basic hydrate research is the precise description of these conditions so that the

potential for occurrence of hydrates in various localities can be adequately predicted and the response of that

hydrate to intentional, unintentional, and/or natural changes in conditions can be assessed.  

Figure 15 illustrates the combination of temperatures and pressures (the phase boundary) that

describes hydrate formation conditions.  When conditions move to the left across the boundary,

hydrate formation will occur. Moving to the right across the boundary results in the dissociation (akin

to melting) of the hydrate structure and the release of free water and methane.  

In general, a combination of low temperature and high pressure is needed to support methane hydrate

formation. Note that depending on the ambient pressure, methane hydrate can form at temperatures

well above the freezing temperature for water; for example at 2500 psi pressure, the ice‐like methane

hydrate will form at 65 o F.  
Appendix: GTI Report

28 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Heavier hydrocarbon gases and other gases such as carbon dioxide can form hydrates at higher

temperatures and lower pressures than methane.  Hydrates may form in wet natural gas streams

containing high percentages ethane, propane, CO2 and H2S where no methane hydrate is formed.   

Referring to Figure 15, note that the phase line for CO2 and ethane are to the warm side of the

methane phase boundary indicating that under a given pressure CO2 and ethane hydrates form at

higher temperatures. (Ref 4, 16, 17)

Ethane

CO2

Methane

5 90 32

Temperature (

oF)

7500

15000

Pressure (psi)

Figure 15 ‐   Methane Hydrate Phase Diagram (Diagram Modified from Physical Chemical Characteristics of

Natural Gas Hydrate).

The control of hydrates as previously discussed is accomplished in the same manner as for the control of icing

conditions; application of heat, drying of the gas or chemical injection.  With hydrates however it must be noted

that they can form in somewhat dry gas especially if heavier hydrocarbons are present.   

Gas Quality Considerations and Gas Processing

New technology has enabled the development of many new and significant shale gas plays in the

United States including the Barnett, Marcellus, Eagle Ford, Fayetteville and others.  The quality of the

gas from these shale resources is different in each area requiring different approaches to production

and gas processing. The volume of ethane, propane, carbon dioxide, nitrogen and other constituents

vary considerably from play to play and can vary considerably within a single shale area such as the

Barnett.  
Appendix: GTI Report

29 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

The gas processing industry has scrambled to keep up with the growth of the Barnett shale.  Gas

production has increased to 4 Bcf/day from near zero in 1999.  Major gas processing plants have been

constructed by Devon, Quicksilver, Enbridge and others.  Most of the plants include compression, CO2

treating with amine units, Cryogenic separation and fractionation. The process gas moves east toward

Carthage, Texas where it can reach the Midwest markets via various hubs or it moves Southeast via the

Transco or Florida gas pipeline.  The gas processing plant typically process large volumes of gas. Within

the Barnett region, plant capacities can range from 35 mmcf/day increasing to 1.0 bcf/day.  Given the

size of these plants, the volume of gas processed, the investment and sophisticated processes and

equipment they are likely better able to withstand weather changes and disruptions due to rapid

declines in temperature.  When they do occur the problems can be identified and resolved.  Unlike

individual well locations the scale of these operations can justify winterization equipment and

processes even for infrequent events. (Ref. 4, 5)

Table 3 – Barnett Shale Gas Compositions (Ref. 5) Oil and Gas Journal, March 9, 2009, Compositional

Variety Complicates Processing Plans for U.S. Gas Shales.

Barnett Shale Gas Composition

Methane Ethane Propane

Well C1 C2 C3 CO2 N2

1 80.3 8.1 2.3 1.4 7.9

2 81.2 11.8 5.2 0.3 1.5

3 91.8 4.4 0.4 2.3 1.1

4 93.7 2.6 0 2.7 1

Table 3 illustrates the gas composition from 4 wells from the Barnett shale producing area.  As can be

seen the compositions vary considerably.  These changes and levels of gas constituents across the

Barnett region have the following impact on gas production with respect to cold weather:

 The presence of the heavier hydrocarbons establishes a higher probability of hydrate formation

even after the gas stream has been dried to 7 lbs/mmcf.  
Appendix: GTI Report

30 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

 There is the potential for liquids fallout with the heavier gases that may be accelerated during

cold weather.  This condensation may occur without hydrate formation.  

 The heavier liquids provide an economic incentive along with high oil prices to establish gas

processing plants to remove liquids.  

 The presence of CO2 and N2 require that these waste gases be removed or blended with other

gases to bring their percentage levels down to pipeline specifications.  

In general the variation in gas composition adds complexity as compared to a dry gas producing region.

The complexity consists of additional gas handling, processing, transportation, blending, metering and

other operations that potentially can be impacted by cold weather.  The exposure of this additional

equipment to weather can impact the reliability of gas flow under conditions not normal for an area.

(Ref. 4)  

On the other hand, independent of the heavier hydrocarbons, gas shale production has all of the issues

associated with water production and methane hydrate formation. There is the possibility that these

conditions alone are enough to cause disruption during cold weather spells and as such the presence

of heavier hydrocarbons may have limited additional impact. (Ref. 4)  

What needs to be determined is the impact of cold weather on gas processing plants which are

established solely for heavy gas removal.  They being located at aggregation points can disrupt large

volumes of gas flow when problems occur.  Alternatively they are large complex facilities, located in a

contained area (as compared to wellheads spread across many miles) which combines to provide both

the incentive and opportunity for cold weather control technology.

Discussion of Cost Implications to Winterize Gas Wells – Per Well Cost and

Per Field Cost

Recent technology development has enabled the recovery of gas from shale formations around the

U.S. and now around the world. Unlike offshore platforms or large flow volume conventional gas wells,

many wells are required to recover gas from low permeability gas fields.  Gas well spacing

requirements can reach down to one well per 10 or 20 acres in some cases.  In the Barnett area typical

spacing is one well per 40 acres and over time greater than 14,000 gas wells have been drilled over a

12 county area (Figure 10). This development took place in stages over a 10 year period as a better

understanding of the full potential developed.

Another factor regarding gas fields with a large number of wells is the time required to respond to an

event that impacts every wellhead.  Within the time frame of the recent cold weather event it would

have been impossible to attend to each of 14,000 wellheads, most at a different location to alleviate

freezing and/or other cold weather issues. (Ref 4, 18)   
Appendix: GTI Report

31 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Figure 16 – Barnett Shale Gas Development Area near Dallas, TX, (Ref. 18) (Figure Courtesy Perryman

Group – HART Unconventional Gas Conference).

The implications for cold weather flow assurance is that unlike the ability to winterize a large volume of

gas flow at a single well location with a single investment, unconventional gas development requires

winterization of many locations at practically the same capital expense.  

Winterization of a gas well requires both capital expenditures and annual operating expense.  Table 6

identifies the cost per well of these items.

In Northern regions of the country this equipment is normally part of the original well design and

installed as a matter of necessity along with all other production equipment.  On wells that can cost

well in excess of $1 million each, these costs are not as significant as when compared to a retrofit after

the well has been placed on production.   This investment needs to be weighed against the impact and

ramifications of the reduction in gas flow, power reductions and outages during this time period.  (Ref

4, 19, 20)

Winterization cost of a wellhead or associated production equipment can varying considerably based

on the size of facilities to be winterized, location, weather conditions, gas quality  and other criteria.  
Appendix: GTI Report

32 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Some approaches can be relatively simple with other facilities requiring more elaborate winterization

equipment.  Several scenarios based on conditions are described below with discussion of cost.  

 Case 1 ‐ Cost Analysis for Simple Methanol Injection Pump and Hookup

In some areas, possibly in many locations in the warmer climate production areas in Texas and New

Mexico, a simple installation of a methanol injection system to be utilized during cold weather spells

may be effective.  Unlike northern climates where severe cold is experienced throughout the extended

winter, the warmer production regions may not require significant equipment installation.  If problem

areas or key producing facilities are identified they may be protected with a simple investment.  

A methanol injection and solar powered pump system can be installed for a capital cost of

approximately $2,800 per installation. The systems are designed to reduce maintenance and operation

expenses. Methanol costs are $12.00 per mmcf of gas throughput based on a treating ratio of 3 gallons

of methanol per mmcf at a cost of $4.00 per gallon.   Based on a well producing 1 mmcf per day of gas,

methanol costs would equal $12 per day.  On an annualized basis assuming methanol injection for 5

months the methanol cost equals $1800.  Labor is estimated at $1000 per month or $5000 total.  (Ref.

15)  

Capital Cost = $2800 per installation.

Operating Cost for 5 months cold weather = $6800.  

  

 Case 2 ‐ Cost Analysis for Building to Enclose Production Equipment

In some cold weather climates the most efficient approach to winterization is to house the susceptible

equipment in a small building or hut.  This can sometimes save on more expensive approaches while at

the same time protecting all equipment from year around weather conditions.  These buildings can be

heated with specialized heating equipment or in many cases can be warmed simply from the heat

given off by the production equipment itself (assumes a heated production unit is within the building).  

In cold weather climates the design and construction of the production equipment includes the

insulated housing, all of which is skid mounted for portability.  When managed in this fashion the

additional cost for winterization can be negligible compared to total well cost.  Building cost can vary

according to size requirements.  This may be an option for critical equipment in the Texas, New Mexico

producing regions.     

Building cost = $2500 to $10,000
Appendix: GTI Report

33 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

 Case ‐3 ‐ Cost Analysis for Equipment to Winterize Gas Wellhead in Very Cold Climate e.g.,

Canada (See Figure 10).

In very cold production areas such as Canada, several winterization techniques need to be applied

including methanol injection, line insulation, a small hut to protect chemical injection pumps small

heaters, and methanol storage.  The total cost of this installation is estimated at $34,425 per

installation (see itemization below). (Ref. Table 10)  Operating cost for a 5 month period is estimated at

$6800 the same as Case 1.

Table 4 – Winterization Equipment Cost for a Gas Well Located in a Cold Climate

Equipment Description Cost

Winterized Production Unit ‐ Net Cost for Winterization Production unit

winterized by internal

piping and insulation.

$23,000

Timberline solar powered methanol pump w/solar panels $2,800

Chemical Pump to Supply Chemical Inhibitors Chemical Inhibitor

Pump for Corrosion

Protection

$1,350

Vent Gas Bottle to Supply Heater System to Collect Vent

Gas from Injection

Pumps to Supply

Heaters

$675

Methanol Tank Stores Methanol $1,000

Methanol Injection Tubing ‐ High Pressure ‐  $5/Ft ‐ 100 Ft Methanol Transfer $500

Flow Line Insulation ‐ $3/Ft ‐  100 Ft Insulate Flow Line $300

Flow Line Heat Tape ‐ $4/Ft ‐ 100 Ft Provide Heat to Flow

Line

$400

Fiberglass Hut for Enlcosing Production Equipment Weather Protection $1,500

Catalytic Heater for Location Housing Heating for Hut $500

Installation Cost ‐ 2 men for 3 days at $50 per hour. Labor $2,400

Total Capital Cost per Well $34,425

 Case 4 ‐ Cost Analysis for Equipment to Winterize Gas Wellhead Equipment Including Gas

Production Unit  

In areas where a gas production unit is required to remove liquids (water or condensate or both) from

the production stream a gas separator must be installed.  The cost of a separator can vary based on
Appendix: GTI Report

34 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

size which is dependent on the total flow volume to be handled by the separator.  In warm weather

climates the piping and instrumentation for the separator is installed externally to the unit as freezing

is not an issue. For cold weather climates all of the piping needs to be internalized where heat from the

production unit itself, in addition to insulation where required will prevent freezing.  The additional

design requirements, locating of piping and instrumentation in a confined space can add as much as

$23,000 to the cost of a production unit.  (Ref. 20)  A less expensive option in some cases can be as

described in Case 2 where all of the production equipment is housed in a small building or hut.  These

insulated buildings often require no additional heat beyond what is supplied by the heating unit in the

production separator itself. (Ref 21)

 Case 5 – Installation of Additional Storage Capacity at Critical Facilities

During the recent cold weather spell in Texas and New Mexico many wells and compressor facilities

were shut‐in by automatic fail safe shut down devices that were triggered by tanks filling up with

liquids.  The fail safe shut‐in devices protect against tank overflow and spillage.  For critical facilities

such as central compressor stations, gas processing plants or important well tank batteries, additional

storage could be installed to allow for operations during bad weather conditions.  Additional tanks are

relatively inexpensive when compared to the impact of significant gas flow reductions.  

Total Cost Discussion

The cost estimates for winterization can vary considerably based on the type of facility, the number of

installations being considered, the degree of cold weather protection that is required, gas flow rates,

pressures and other factors.

Simple weatherization such as for Case 1 above can be accomplished for an estimated $2800 capital

cost and $6800 annual operating cost.

More comprehensive winter protection can increase the capital cost to over $11,000 per installation.  

Winterization of production units, if required can add an additional $23,000 per installation depending

on production unit size.  

Overall, the cost of winterization, given the number of wells can be considerable.  The simple table

below illustrates cumulative capital cost with variable well counts and per well equipment costs.

  
Appendix: GTI Report

35 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Table 5 – Cumulative Cost for Winterizing Gas Wells – Variable Well Counts and Individual Well

Equipment Cost.

Well Count

10,000 20,000 30,000 40,000 50,000

Cost per Well Cumulative Cost

$2,500 $25,000,000 $50,000,000 $75,000,000 $100,000,000 $125,000,000

$10,000 $100,000,000 $200,000,000 $300,000,000 $400,000,000 $500,000,000

$20,000 $200,000,000 $400,000,000 $600,000,000 $800,000,000 $1,000,000,000

$35,000 $350,000,000 $700,000,000 $1,050,000,000 $1,400,000,000 $1,750,000,000

For 50,000 wells the total cost could vary from $125 million to $1.75 billion based on per well

equipment needs.  It may be that key compressor locations and gas processing facilities, if winterized

or supplied with additional liquid storage tanks, could mitigate a significant percentage of the cold

weather flow problem.  The total number of these locations is likely to be much reduced from the

number of wells noted in Table 5 above.  If 1000 facilities of this type required a $10,000 investment

each the total would equal $10 million, a much reduced number from those illustrated above.

Table 6 which follows itemizes capital cost and operating expenses for winterization of production

facilities.  The capital costs do not total within the spreadsheet as there is duplication of equipment in

some cases.      
Appendix: GTI Report

36 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

Table 6 – Itemization of Capital and Operating Expenses for a Typical Gas Well – (Note, the Capital

Costs Items Listed in the Table are not Totaled as Locations will require a Subset of these Items).  

Gas Well Winterization Expenses

Cold Weather Protection Equipment Description Cost Per Well ‐ 

Excludes

Duplicate

Applications

Source

Capital Cost

Winterized Production Unit ‐ Net Cost for Winterization Production unit

winterized by internal

piping and insulation.

$23,000 Sivals

Engineering,

Odessa, Tx., Ref

20

Methanol Injection Pump High Pressure Pump to

Inject Methanol

$1,648 ZKO Oilfield

Industries, Ref. 11

Timberline solar powered methanol pump w/solar panels $2,800 Timberline

Manufacturing,

Ref. 22

Chemical Pump to Supply Chemical Inhibitors Chemical Inhibitor

Pump for Corrosion

Protection

$1,350 ZKO Oilfield

Industries Ref. 11

Vent Gas Bottle to Supply Heater System to Collect Vent

Gas from Injection

Pumps to Supply

Heaters

$675 ZKO Oilfield

Industries Ref. 11

Methanol Tank Stores Methanol $1,000 estimate

Methanol Injection Tubing ‐ High Pressure ‐  $5/Ft ‐ 100 Ft Methanol Transfer $500 Drillspot .com

Flow Line Insulation ‐ $3/Ft ‐  100 Ft Insulate Flow Line $300 Drillspot .com

Flow Line Heat Tape ‐ $4/Ft ‐ 100 Ft Provide Heat to Flow

Line

$400 Drillspot .com

Fiberglass Hut for Enlcosing Production Equipment Weather Protection $500 JW Williams Co.

Casper, Wyoming,

Ref. 21

Catalytic Heater for Location Housing Heating for Hut $500 ZKO Oilfield

Industries Ref. 11

Installation Cost ‐ 2 men for 3 days at $50 per hour. Labor $2,400 JW Williams Co.

Casper, Wyoming,

Ref. 21

Operating Expense for Methanol Injection

Methanol costs are $4.00 per gallon. Assume 10 gallons per

day for 5 months.  Methanol cost = 5 months * 30

days/mo.*10 gal/day * $4/gallon = $6000

Methanol Cost $6,000 Timberline

Manufacturing,

Ref. 22

Maintenance ‐ Per Month ‐ $200 @ 5 months $1,000

Total ‐ Cost per Year $7,000
Appendix: GTI Report

37 7‐27‐11 – Cold Weather Impact on Gas Production – FERC Study  

References

1. Bentek Energy LLC ‐ Deep Freeze Disrupts U.S. Gas, Power, Processing – February 8, 2011.

2. Gas Technology Institute (GTI) Personal Communications with Gas Producers in the Dallas Ft.

Worth area.

3. Freeze Protection for Natural Gas Pipeline Systems and Measurement Instrumentation, David J. Fish,

Senior Vice President, Welker Engineering Company, Sugar Land, TX

4. Gas Technology Institute – June, 2011 – Cold Weather Study and Impact on Gas Production.

5. Oil and Gas Journal, March 9, 2009, Compositional Variety Complicates Processing Plans for U.S.  Gas

Shales.

6. Shell Oil Company – Gas Flow Schematics for Typical Flowing Gas Wells.

7. NaturalGas.org   http://naturalgas.org/naturalgas/transport.asp

8. Compressor Stations – The Heart of the Pipeline System – El Paso Pipeline Group.

9. www.wikipedia.org/wiki/Compressor_station.

10. Oil and Gas Production Handbook, ABB, Havard Devold

11. ZKO Oilfield Industries, Inc. and PTAC.org

12. Manlove Gas Storage Field, Midwest Gas Storage Section, Gas Technology Institute;

http://en.wikipedia.org/wiki/File:Manlove_gas_storage_facility.jpg

13. http://www.engtechinc.com/downloads.php

14. www.en.wikipedia.org/wiki/Pigging

15. Replace Glycol Dehydration Units with Methanol Injection, EPA Star Program ‐ PRO Fact Sheet No. 205

16. DOE – NETL website – www.netl.doe.gov – Hydrates Resources and Technology Program.

http://www.netl.doe.gov/technologies/oil‐gas/FutureSupply/MethaneHydrates/about‐

hydrates/about_hydrates.htm

17. http://en.wikipedia.org/wiki/Wik/hydrate

18. Barnett Map from Perryman Group, Hart DUG Conference, Ft. Worth, TX.

19. Optimizing methanol usage for Hydrate Inhibition in a Gas gathering System, Bryan Research

Engineering, Annual GPA Convention, 2004

20. Sivalls Engineering, Midland‐Odessa, Texas,  www.sivalls.com , Kent Perry Personal Communications

21. JW Williams Inc., Casper, Wyoming – Kent Perry Personal Communications.

22. Managing Gas Well Freeze Protection, Timberline Manufacturing Company, Inc.,  www.tlinemfg.com