During the first week of February 2011, the southwest region of the United States experienced unusually cold and windy winter weather conditions. Low temperatures during this period plunged into the teens for five consecutive mornings, with many hours of below-freezing temperatures experienced overnight. Albuquerque, New Mexico, for example, experienced temperatures ranging from 7 to –7° Fahrenheit (F), compared to average temperatures in the 26 to 51° F range. The impacts from this extreme cold weather event—the “Southwest cold snap”—were far reaching and severe, with the natural gas and electric sectors being hit particularly hard. By the time the region had recovered, 4.4 million electricity customers and 50,000 gas customers in various portions of Texas, New Mexico, and Arizona had lost service.
Arctic cold fronts penetrating the Southwest are not unusual. Since 1980, the region has experienced a number of significant cold weather events, most notably in 1983, 1989, 2003, 2006, 2008, and 2010. The cold front that descended on the Southwest during the first week of February 2011 was unusually severe, however, in terms of its temperatures (below freezing for four or more days in some locations), intense winds (often gusting to more than 30 miles per hour), and protracted duration (one week in total). Many described the cold weather event as unprecedented, and, indeed, only in 1989 did winter weather approach the harsh conditions experienced during the first week of February 2011. The severe winter of 1989 forced the Electric Reliability Council of Texas (ERCOT) to resort to systemwide rolling blackouts of its utility customers.
While today’s weather cannot be predicted with complete accuracy, history has taught us that extreme weather events are not entirely unpredictable. Rather, they occur with sufficient frequency to be adequately combatted via appropriate preparation measures. A lack of preparedness, as seen in the February 2011 Southwest cold snap, the November 2011 Connecticut snowstorm (resulting in a six-day electric outage for roughly 300,000 residents), and the June 2012 Mid-Atlantic derecho storms (resulting in nearly 3,000,000 customer outages over nearly one week’s time) can be overcome. And specifically in the context of extreme temperature events, as electric generators continue to increase their reliance on natural gas, preparation and coordination between these two industries will become even more critical as the impacts of climate change increase the likelihood and frequency of extreme weather events.
This article uses the extreme weather event example from the February 2011 cold snap to analyze the impacts of severe weather events on both natural gas and electric systems. It highlights the interdependency of operations between the natural gas and electric industries and examines where improvements can be made in terms of operations, scheduling, and coordination between these two industries. Finally, it proposes solutions not only for mitigating future impacts of extreme weather, but for improving the reliability of the electric and natural gas systems as a whole.
From an energy generation perspective, the Southwest United States, in general, is not prepared for extreme winter weather. Rather, it is extreme heat that is experienced for much of the year in this region. In preparation for the heat, electric generation facilities in the Southwest are not enclosed as they are in colder regions of the country. This design helps to avoid the overheating of the generator equipment. However, because these facilities are literally “out in the open,” they are not protected from extreme cold weather or natural disasters. Thus, as the severe Arctic cold front hit the Southwest during the first week of February 2011, these unprotected electric generators tripped, suffered derates (i.e., operated at less than maximum power), or failed to start entirely. This unexpected loss of capacity resulted in electric utilities across the region experiencing temporary unit outages and undertaking “load shedding” procedures (i.e., utility-engineered rolling blackouts used as a last resort to avoid a regionwide total blackout). In ERCOT alone, which covers most of Texas, more than 3.2 million customers experienced rolling blackouts. FERC & NERC, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1–5, 2011: Causes and Recommendations 1 (2011). On the natural gas side, the extreme cold led to production declines in the five natural gas basins serving the entire Southwest region. Cities across New Mexico were particularly affected, with more than 30,000 outages reported in a dozen cities throughout much of the state. Id. at 2.
For the region as a whole, 67 percent of the electric generation outages were due directly to weather-related causes, including frozen sensing lines, frozen equipment, frozen water lines, frozen valves, and generator blade icing. Id. at 8. Additionally, another 12 percent were indirectly attributable to the weather, including gas-fired generation failures due to natural gas curtailments. Id. at 9. The production curtailments were due both to freeze-offs (where water produced alongside the natural gas during production froze, blocking gas flow and shutting down the well), as well as icy road conditions (preventing maintenance personnel and equipment from reaching the wells and hauling off the excess water before it could freeze).
Following the February 2011 Southwest cold snap, both the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) launched investigations into the causes of the widespread outages. Ultimately, staffs for the two agencies concluded that inaccurate winter weather forecasting was not to blame, as the generators and natural gas producers in the region had both adequate and accurate notice of the approaching winter storm. Rather, primary fault lay with the poor to nonexistent winter weatherization of equipment by electric generators and natural gas producers. Also to blame was communication—or in the case of the Southwest cold snap, a lack thereof. Specifically, NERC and FERC identified a lack of effective communication and coordination, particularly in terms of emergency protocol, among the electric generators, the electric reliability coordinators, and the natural gas pipeline producers. Had proper winter weatherization techniques and emergency communication protocols been in place (and used), the severity of the impacts from the cold snap could have been greatly reduced.
The joint work of NERC and FERC in investigating the February 2011 Southwest cold snap has been pivotal, not only in shining light on the impacts of severe weather on electric reliability, but on the reliability implications existing at the interface of the electric and natural gas industries. During the cold snap, outages on the electric side impacted operations on the natural gas side and vice versa. As the natural gas operators and electric generators in the Southwest begin responding to the joint recommendations of NERC and FERC by improving both the winter weatherization of equipment and their inter- and intra-industry communications, it is becoming alarmingly clear that these two industries are becoming inextricably tied. Going forward, the electric sector’s increased dependence on natural gas as a generating fuel means significant changes will need to be made in order to better coordinate the important operations between these two industries.
Nationwide, natural gas-fired units account for more than 20 percent of total electrical generation. FERC, “2011 State of the Markets,” Presentation Item No: A-3, Apr. 19, 2012. As coal plant retirements continue, variable generation penetration climbs, and natural gas prices continue falling to record lows, gas-fired generation will steadily increase and the need for coordination between the two industries will become increasingly critical. Indeed, the reliance on natural gas as a fuel source for electricity supply is projected to increase by nearly 24 percent in 2012. U.S. Energy Information Administration, Short-Term Energy Outlook 2 (2012).
Realizing that electric reliability is directly implicated by natural gas operations, FERC recently has taken the lead in coordinating these two interdependent industries. First, FERC has issued a new rulemaking proceeding, by which it proposes to adopt certain North American Energy Standards Board (NAESB) practices for the natural gas pipeline system. Notice of Proposed Rulemaking, Standards for Business Practices for Interstate Natural Gas Pipelines, 138 F.E.R.C. ¶ 61,124, FERC Docket No. RM96-1-037 (Feb. 16, 2012). In addition, FERC Commissioners Philip D. Moeller and Cheryl A. LaFleur have solicited comments from participants and stakeholders across both the electric and gas industries as to how FERC should approach the issue of greater coordination between the natural gas and electricity markets. Notice Assigning Docket No. and Requesting Comments, Coordination between Natural Gas and Electricity Markets, Docket No. AD12-12-000 (Feb. 15, 2012); Statement of Cheryl A. LaFleur on Standards for Business Practices for Interstate Natural Gas Pipelines (Feb. 16, 2012). While the rulemaking and the Commissioners’ comment solicitations are important first steps, both regional and interregional coordination are needed to address the reliability concerns stemming from the interface of the electric and natural gas industries. This coordination will require a closer examination of the following: (1) improving communications between the two industries to maintain reliable operations and improve the transmission of emergency alerts during severe weather events; (2) acquiring a better understanding of the differences between natural gas and electric operations and scheduling; (3) examining the need for increased natural gas pipeline infrastructure and storage; and (4) understanding how best to integrate variable generation using natural gas.
Traditionally, the natural gas and electric industries have had little need for coordination and communication. As a result, despite the electric sector’s increased reliance on natural gas, the communication efforts between the two industries today are lacking. Presently, the gas pipeline operator will communicate with the local gas distribution company serving an electric generator or, in some cases, will communicate with the generator itself. NERC, 2011 Special Reliability Assessment: A Primer of the Natural Gas and Electric Power Interdependency in the United States 96 (2011). However, the natural gas operator will not freely communicate with a regional electric reliability coordinator due to the confidentiality of commercially sensitive business information. Id. Additionally, the electric industry’s concept of a reliability coordinator, which is charged with ensuring reliable electric grid operations, does not have a parallel entity in the pipeline industry. As a result, communication attempts regarding emergency events that could potentially impact either or both industries, as seen most recently during the Southwest cold snap, are often lacking or ineffective.
Attempts to improve communications between these two industries are already underway. Within the western United States, both the California ISO (CAISO) and the Pacific Northwest region have developed communication models to better guide communications between the natural gas and electric industries. CAISO’s model requires regular communications on the status of both the electric and natural gas systems, in addition to the scheduling of seasonal meetings to prepare for summer and winter peak demand. CAISO.com, Natural Gas Pipeline Coordination Tariff Modifications (June 20, 2012). Within the Pacific Northwest, the Northwest Mutual Assistance Agreement (NWMAA) establishes coordination protocols for emergencies and requires biannual meetings between the two industries to discuss seasonal weather forecasts and update emergency contact lists. Clay Riding, PSE, “Northwest Gas System Dec. 2009 Experience,” Presentation at Plugging into Natural Gas Summit, Jan. 25, 2012. Outside the West, the Florida Reliability Coordinating Council (FRCC) has similarly established communication protocols, requiring the issuance of “Critical Notices” during emergency situations and regular training and testing of its communication protocols with both industries to ensure compliance. FRCC.com, FRCC Coordination Procedure (June 20, 2012). Finally, a collaborative effort among the New York ISO (NYISO), the New England ISO (ISO-NE), the PJM Interconnection (PJM), and the Northeast Gas Association (NGA) has resulted in the formation of the Electric/Gas Operations Committee (EGOC) to facilitate natural gas and electric system coordination efforts in the Northeast. ISO-NE.com, Electric/Gas Operations Committee (June 20, 2012).
FERC’s NOPR, “Standards for Business Practices for Interstate Natural Gas Pipelines,” also addresses the need for improved communications between the natural gas and electric industries by adopting the NAESB’s Wholesale Gas Quadrant Version 2.0 Standards. Notice of Proposed Rulemaking, Standards for Business Practices for Interstate Natural Gas Pipelines, 138 F.E.R.C. ¶ 61,124, FERC Docket No. RM96-1-037 (Feb. 16, 2012). Included in these standards are communication requirements, in particular, standards requiring that public utilities be updated with clear identification of any changes in pipeline system conditions. The standards also create fifteen additional notice types intended to facilitate the identification of pipeline condition changes between the relevant parties. Additionally, on June 21, 2012, Chairman Jon Wellinghoff announced FERC’s plans to host a number of regional conferences in 2012 , in the Central, Northeast, Southeast, West and Mid-Atlantic regions. Statement of Chairman Jon Wellinghoff on Regional Conferences on Gas-Electric Coordination (June 21, 2012); Notice of Technical Conferences, FERC Docket No. AD12-12-000 (July 5, 2012). The conferences, scheduled throughout the month of August 2012 would serve as a follow-up to the NOPR, by addressing infrastructure in these regions and providing an opportunity for industry discussions of specific issues affecting coordination between the gas and electricity markets and electric reliability. Id.
Operations and Scheduling
In general, the variable demand produced by electric operations increases the strain placed on the natural gas pipeline system. While electric utilities use a variety of gas-fired power generation units, the most common units in use today are the newer and larger capacity gas-fired combustion turbine (CT) and combined cycle (CC) units. NERC, 2011 Special Reliability Assessment: A Primer of the Natural Gas and Electric Power Interdependency in the United States 35–37 (2011). Generally, CTs can be quickly started and are thus used as peaking units (operating only during periods of high demand), while CC units are used primarily as either cycling (started when demand goes up and shut off when demand goes down) or baseload units (running twenty-four hours a day). These newer units exhaust “line pack” (i.e., the ability of the natural gas pipeline to “store” small quantities of natural gas on a short-term basis by increasing the pipe’s operating pressure) much faster than older units, increasing the strain placed on the gas pipeline system by requiring increased operating pressure. Additionally, because gas-fired electric generation is primarily used to meet intermediate and peaking electricity requirements, daily energy demand (i.e., load) requirements can be subject to significant variation, as a result of weather events or unplanned outages for other units. This variation also increases the strain placed on the pipeline system.
Beyond operations, significant differences exist between the “gas scheduling day” and the “electric scheduling day” that can create difficulties when attempting to coordinate the two industries for purposes of electric generation. The typical gas day occurs from 9:00 a.m. Central Clock Time (CCT) to 9:00 a.m. CCT the following day. Aspen Environmental Group, Implications of Greater Reliance on Natural Gas for Electric Operations 72 (2010). During this time, supplier arrangements, nominations, confirmation, and scheduling all take place, with pipelines scheduling gas quantities to flow at the start of the next day (packing pipelines the night before, as needed). Id. By contrast, the typical electric planning day is from midnight to midnight local time. NERC, 2011 Special Reliability Assessment: A Primer of the Natural Gas and Electric Power Interdependency in the United States 97 (2011). Further, an electric day usually completes its scheduling for the next day by 6:00 p.m., local time, of the current day. Id.
To further complicate scheduling, while electric demands typically follow a sinusoidal daily pattern, the gas day typically begins during the morning load “pick-up” on the electric side, while the electric day typically begins during the midnight load “drop-off” on the gas side. Id. Although electric utility plans identify which generator units will run the next day (to project the next day’s fuel consumption), the pipeline deadlines for gas nominations historically have been set at 11:30 a.m. CCT of the current day. Id. This results in a time gap, of up to eight hours or more, between the two industries’ approaches to scheduling. Id. These stark differences between gas-electric operations and scheduling can easily expose the positions taken by market participants to sudden changes in demand caused by unexpected changes in the weather.
Some regions have already begun addressing these differences. For example, while NAESB mandates four cycles in which gas nominations can be adjusted (two cycles the day before flow and two during the day of flow), in the Northwest, an important fifth cycle following the gas day has been added. Allison Bridges, Williams Northwest Pipeline, “CEO Perspectives for Moving Forward,” Presentation at Plugging into Natural Gas Summit, Jan. 25, 2012. This fifth cycle assists the electric side of operations by aligning after-hours requests by the electric generator (usually due to sudden weather changes resulting in unanticipated increases in demand), provided that all parties confirm the flow. Id.
In addition, FERC’s NOPR addresses the operational and scheduling challenges facing the two industries. NAESB’s Version 2.0 Standards, adopted pursuant to the NOPR, require increased coordination between the two industries, through various notice types, to overcome the inherent differences in their operations and scheduling. While FERC’s NOPR requires increased communication and coordination, it does not require substantive changes in scheduling or operations by either industry. Therefore, it is clear that there is room for improved regional and interregional coordination between the natural gas and electric industries in this area.
Increased Natural Gas Storage and Infrastructure
By 2030, it is predicted that the United States and Canada will need approximately 29,000 to 62,000 miles of additional natural gas pipelines and 370 to 600 billion cubic feet (Bcf) of additional storage capacity, due primarily to the increased natural gas demand from electric generation. ICF International, Natural Gas Pipeline and Storage Infrastructure Projections Through 2030 3 (2009). While line pack allows for some flexibility of natural gas deliverability, natural gas storage is the primary vehicle by which the gas industry can provide the flexible services required by the electric power industry. Natural gas storage not only aids electric utilities in meeting baseload and peaking requirements, but also in compensating for unforeseen supply disruptions and meeting seasonal changes in demand requirements.
For purposes of the electric industry, there are two types of natural gas storage that prove most beneficial: (1) salt dome caverns and (2) horizontal wells. Allison Bridges, Williams Northwest Pipeline, “CEO Perspectives for Moving Forward,” Presentation at Plugging into Natural Gas Summit, Jan. 25, 2012. Salt dome caverns, formed out of existing underground salt deposits, are well suited for natural gas storage in that they allow for multiple withdrawals throughout the year (i.e., are “multiple-cycling”) and allow very little natural gas to escape unless specifically extracted. Horizontal wells drilled into depleted oil and gas reserves offer particular value to the electric sector because they provide high deliverability and large capacity, while significantly extending the range of suitable sites beyond the restricted geological conditions of salt domes.
Moving forward, natural gas storage facilities will not only have to satisfy the traditional demands for fuel supply reliability, but will also need to be increasingly flexible to meet the constantly fluctuating needs of the electric generation fleet. To satisfy these significant and expanding swings in demand, future natural gas storage facilities should be high capacity and offer high deliverability through multiple-cycling. In sharp contrast to the extreme cold of the 2011 winter, the 2012 winter was unusually mild, decreasing demand for natural gas-fired generation across the United States and resulting in current gas storage levels 44 percent greater than the five-year average. U.S. Energy Information Administration, Natural Gas Weekly Update for Week Ending May 9, 2012 (May 16, 2012). Thus, increased natural gas storage will not only be needed to accommodate fluctuating electric generation, but to combat ever-changing weather conditions and their impacts on natural gas demand.
In addition to natural gas storage, improvements to natural gas pipeline infrastructure must be considered. Today’s gas pipeline system has considerable operational flexibility for supplying natural gas reliably to electric generators. But at some locations in some regions, new facilities may need to be constructed to guarantee reliable on-demand gas service to support changing generator needs resulting from both increased electric demand (due to extreme weather conditions) and increased variable generation. More specifically, according to a recent study, many areas of the country will need additional investment in natural gas infrastructure due to increased demand for natural gas-fired generation and increased penetration of variable generation. Aspen Environmental Group, Implications of Greater Reliance on Natural Gas for Electric Generation 57 (2010). Therefore, given the electric industry’s current growing reliance on natural gas for both electric generation and variable generation firming, it is not a question of whether pipeline expansion will be necessary, but rather, when and where.
Integrating Variable Generation
Variable generation (i.e., generation resources fueled by intermittent, typically renewable fuels such as wind and solar) is becoming a larger component of the electric generation fleet, with nearly 140 gigawatts (GW) currently in place, and an additional 105 GW anticipated to be added by 2025. Leonard Crook, ICF International, “Integrating Variable Renewable Power Generation and Natural Gas Infrastructure,” Presentation at Plugging into Natural Gas Summit, Jan. 25, 2012. Integrating variable generation will create challenges not just for the electric grid, but also for natural gas operations and infrastructure. For example, gas turbines work well to compensate for the variability associated with renewable generation (i.e., generally, they can be started quickly and can ramp up and down faster than coal, steam, and nuclear plants). However, while gas turbines operate best at full power and steady-state (i.e., not cycling), when integrating renewables, they typically operate at various deviations from this set point, resulting in both increased inefficiencies and operational costs.
Additionally, weather forecast error can result in the need for either more or less generation at any given time. For instance, where there is more wind than forecasted, less gas generation will be needed than scheduled, but because gas deliveries are already “in the pipe,” the problem of excess gas arises. Or, when there is less wind than forecasted, quick start-ups are required of gas-fired generators and not enough gas may be available (as a result of insufficient nominations and scheduling). These uncertainties not only complicate the operation of the facilities, but also expand the risk facing operators as they plan and execute fuel procurement decisions.
Severe weather events are not only fraught with uncertainty, but tend to highlight a general lack of preparedness in a region, from ineffective emergency alert protocols to weak and vulnerable infrastructure. The February 2011 Southwest cold snap is a recent example of how a region’s lack of preparedness for a severe winter storm had far-reaching impacts, ultimately leading to rolling electric blackouts across an entire region. These events, in turn, shed light not only on proper preparedness measures to take in the future, but on how the electric sector’s increasing dependence on natural gas as a generating fuel source can impact reliable operations of both industries. While the weather may never be predicted with 100 percent accuracy, critical steps can be taken to reduce regional vulnerabilities to the impacts of severe weather, including appropriate weatherization of generating equipment and improved coordination between the electric and natural gas industries.
Specifically, to take advantage of natural gas-fired generation’s ability to both cheaply replace coal-fired generation as a form of baseload electric power and ease the difficulties associated with integrating variable generation, coordination between the natural gas and electric sectors is critical. As natural gas continues to grow as a generating fuel source, this coordination will be essential to achieving the below “goals,” designed to improve and maintain reliable operations at the interface of the electric and natural gas industries: (1) improving communication protocols between the two industries to provide more reliable and consistent daily communications and scheduling and to provide adequate emergency alerts to reduce the potential reliability impacts from severe weather events; (2) enhancing line pack on natural gas pipelines to provide a short-term form of storage and to better integrate variable generation using natural gas; (3) increasing natural gas storage capability and pipeline infrastructure to improve reliability and to better integrate variable generation using natural gas; (4) increasing the number of gas nomination cycles to improve reliability and to better coordinate operations between the two industries; and (5) perhaps the easiest, yet the most overlooked: appropriately responding to “lessons learned” from past events that negatively impacted reliable operations on both sides (even when not mandated so by FERC and NERC), including lessons learned from the February 2011 Southwest cold snap, to prevent similar events from occurring in the future.
In working to achieve these goals, communication between these two integral industries will be substantially improved. As communication increases, coordination will naturally follow. Having greater coordination and communication will lead to critical discussions taking place at both the regional and national levels, beginning with the regional discussions currently being led by FERC. These discussions will prove critical not only to determining infrastructure needs, but to improving operations between the two industries (including improved scheduling, enhanced emergency operations, and more effective integration of variable generation). Finally, going forward, as industry begins to implement necessary change pursuant to “lessons learned,” impacts on both natural gas and electric operations from extreme weather events like the February 2011 Southwest cold snap can be reduced and, ideally, prevented entirely.