Gas-Electricity

D.West Region

Participants at the West technical conference discussed many subregional differences within the region, including resource mix, market structure, and degree of dependence upon natural gas for electric generation. There was general agreement that the West as a whole will have a greater reliance on natural gas for electric generation in the future. Some participants expect the burn profile for natural gas used for electric generation to become more volatile, due both to the normal variation in electric demand and the increased use of gas for balancing, resulting from the increase in renewable generation in the region.
Representatives from both natural gas and electric entities in the West stated that most of the natural gas-fired electric generation in the West region (outside of the
California Independent System Operator Corp. (CAISO)) is backed by firm gas transportation contracts. Natural gas-fired electric generators served by the LDCs within CAISO mainly use interruptible gas transportation contracts on the LDCs’ distribution systems, but this service reportedly performs like firm because gas pipeline infrastructure within CAISO is expanded in anticipation of load, as opposed to responding to long-term firm contracts.
Some conference participants stated that gas-electric coordination issues could be alleviated by having more efficient electric markets in the West region. An energy imbalance market was explicitly mentioned as one way of achieving additional efficiencies. A representative of CAISO indicated that it has no mechanism to look at firmness of fuel, and believes that it should not have a mechanism for this purpose. He noted that CAISO’s market has a penalty for non-performance.
Several conference participants requested more opportunities for intra-day nomination adjustments on pipelines, but a few pipelines clarified that these additional nomination opportunities would have value only if they resulted in actual physical changes; actual changes in pipeline flow can only occur if gas can be purchased and injected into the pipeline to accommodate the revised nomination and then delivered. The appropriateness of the “no-bump” rule was challenged on multiple occasions. A few participants from the Southwest opined that both the gas and electric scheduling days should go until midnight local time.
Regarding communications, CAISO’s representative discussed recent Commission-approved revisions to its tariff to permit sharing generation and transmission outage information with utilities that operate pipelines and/or deliver gas to gas-fired generators, pursuant to non-disclosure agreements. Additionally, a few participants both inside and outside California currently send estimated burn profiles for electric generation to the pipelines on a day-ahead basis.
Representatives of several pipelines in the region discussed their efforts to improve communications with generators and electric balancing authorities, including updating points of contact and communication methods, conducting regional table top exercises, and reviewing emergency procedures. For example, one pipeline hosted a mock gas supply emergency exercise following the February 2011 cold weather event, and another plans to host a similar mock emergency drill in 2013. Pipeline representatives added that both gas and electric operators could benefit from education about the other’s system, in particular how to interpret and determine the important information from the notices and information that is provided, especially given the sheer volume of postings from both sides. The pipeline representatives also described efforts between the RTOs/ISOs and the Interstate Natural Gas Association of America (INGAA), as well as operator training programs that can provide that education. For example, in the wake of the February 2011 Southwest cold weather event, a number of
entities participated in the electric and natural gas interdependency conferences at the Western Electricity Institute, which focused upon educating the electric and gas companies about how the other functions.19
Several participants stated that FERC’s Standards of Conduct are a barrier to communications. For example, the representative of a utility in the Northwest described a tabletop exercise in that region during which it was discovered that some organizations have employees with considerable operational experience within marketing groups. This gave rise to the concern that the Standards of Conduct would prohibit these employees from being involved with efforts to resolve operational problems or emergency situations.
Some participants stated that the Northwest needs to improve gas-electric coordination and communication during normal operating conditions, but noted that there are agreements in place to help during emergency situations. One example mentioned as a model for such coordination is the Northwest Mutual Assistance Agreement (NMAA), which aids coordination between utilities during gas-related emergency situations by maintaining updated emergency contact information, and conducting semi-annual planning meetings and periodic emergency exercises for utilities.20 Some participants at the technical conference believe that this type of agreement should be extended to the rest of the West region. It was mentioned that the Western Energy Institute maintains the Western Region Mutual Assistance Agreement, but this agreement only covers crew assistance during emergencies.
The importance of gas storage, especially during emergency situations, was expressed by multiple participants. Representatives of several utilities in Arizona noted that that state has been attempting to get market area storage, without success, for many years. CAISO’s representative stated that long-term electric contracts may be needed to finance and construct market area gas storage facilities.
Representatives of several Southwest utilities suggested a regional gas sharing pool or pooling mechanism for pipeline capacity, in which members of the pool could give up pipeline capacity to help a generator that requires more gas. One pipeline representative at this conference commented that this already occurs in the market through capacity releases.
Several participants from the electric industry confirmed that pipeline contingencies are not currently included in planning studies. One participant argued that the probability of an event on the gas side is so low that it is negligible, but others still want it quantified because it may be within the risk parameters that are planned for on the electric side.
West Regional Initiatives
Participants representing entities in the Northwest described regional efforts by the Pacific Northwest Utilities Conference Committee (PNUCC), the Northwest Power and Conservation Council (NPCC), and the Northwest Gas Association (NWGA) to look at long-term resource adequacy needs through analyses of utility integrated resource plans.22
Representatives of two utilities in the Northwest discussed regional emergency coordination efforts, including the Northwest Mutual Assistance Agreement described above, that provides procedures to address anticipated cold weather events and critical situations leading to loss of pressure on a pipeline or storage facility. These utility representatives believe that such efforts have led to improved coordination and cooperation among regional entities, but that communications with the Bonneville Power Administration (BPA) could be improved because they are not a customer of any pipeline. A representative of BPA noted that the mutual assistance agreement works well
in dealing with emergencies but does not address non-emergency situations. BPA’s representative added that the Western Electric Coordinating Council also maintains a “merchant alert protocol” that facilitates communications and coordination between merchant generators and reliability entities prior to an emergency situation occurring.23
A representative of CAISO stated that California entities talk frequently and meet at least quarterly to examine outages and coordinate generation and transmission. According to CAISO’s representative the result has been that even major pipeline outages have not led to electric outages, and the electric and gas systems within California have been robust enough to weather an extended outage at Southern California Edison Company’s San Onofre nuclear plant.
The Northwest transmission planning group, ColumbiaGrid,24 announced on August 28, 2012, that it has formed a study team to analyze potential impacts of a gas supply limitation in the Interstate 5 corridor area of Oregon and Washington.25 ColumbiaGrid stated that the study is an exploration of possible consequences if something happened to the natural gas supply system in a way that limited supply to the electric generating stations. Columbia Grid will coordinate the study with PNUCC and NWGA.26
In October 2012, members of the Committee on Regional Electric Power Cooperation and State-Provincial Steering Committee formed a task force to identify and study issues at the interface of the gas and electric industries. The Task Force is currently
engaged in outreach to determine the scope of its work and potential for collaboration with others, with the goal of providing direction to states and provinces as they consider the interface issues most important to the West.

E.Southeast Region

While some participants in the Southeast Region had specific concerns about certain current gas scheduling rules, they generally did not believe that the reliability of natural gas service for electric generation was an issue in their region. Conference participants explained that in this region, most of the entities use integrated resource planning, examining both transmission and generation jointly with expected load growth to determine areas where either transmission or generation capacity is required. These studies also include fuel supply interactions for generation. Generators in this region typically have firm pipeline transportation service, and utilize a combination of released firm or IT service to meet peak needs. For example, a utility representative noted that it requires all new gas-fired generation capacity additions to have firm gas transportation and storage. A Florida utility representative noted that Florida entities use similar processes, although it was noted that a third natural gas pipeline into Florida would enhance reliability.
Many of the Southeast technical conference participants agreed that weather driven electric load variations will increasingly be supplied by gas generation. They also agreed that the need to rely upon gas-fired generation to meet daily and hourly variations is not consistent with interstate pipelines’ standard firm transportation service, including the timely nomination cycle and the no-bump rule. Some representatives of generation owners with firm pipeline capacity stated that they would like the ability to use the firm service as flexibly as possible. For example, one electric utility representative stated that it often is not able to use its firm capacity to make nomination changes because of the no-bump rule and other service priority rules. Other participants stated that they have not experienced the same limitations, in part due to completing their electric day analysis before gas prior day timely nominations must be submitted.
In contrast, representatives of some gas shippers, such as industrial users, argued in favor of retaining the no-bump rule. They stated loss of the no-bump rule could cause
fewer shippers to use IT, resulting in lower overall utilization of pipeline capacity and a greater share of fixed costs allocated to firm shippers.
A utility representative also asserted that the present analysis used to determine nominations in gas system operations (forward haul and back haul pipeline capacity, storage, and LDCs’ local capabilities) “leaves too much on the table” by not allowing utilization of dynamic gas system capabilities. The representative further stated that gas-fired electric generators need to supply the net electric demand over a short time frame without impacting operational flexibility on the gas system.
Several generator representatives stated that they rely upon marketers and asset managers, who hold a mix of firm and interruptible transportation and storage services to manage their load swings throughout the day. They believe that additional flexibility could be achieved through FERC changes to the capacity release rules, which in turn could result in more efficient pipeline capacity utilization.
Participants stated that communications between the major electric entities and pipelines in the region are robust. For example, during a cold weather event in January 2010, an electric utility shifted away from gas generation to allow pipeline packing for use on the coldest day. This allowed the utility to stay within its long term contractual withdrawal limits while allowing sufficient withdrawals to occur on the critical electrical demand day. Participants stated that gas and electric entities share locations of electric driven natural gas compressor stations, which account for usually less than 20% of the flow capacity on the pipelines. However, one participant identified that there are critical locations that are supplied by electric-only compressor stations.
Participants stated that maintenance outages on the electric and gas systems are informally coordinated between major entities, resulting in selected changes in the timing of maintenance on both systems. They state that this is accomplished through a number of informal meetings per year. Participants also agreed that the communications that take place between the pipelines and their customers, including power generators, have been adequate to address reliability concerns both day-to-day and during emergencies. No concerns were expressed regarding the Standards of Conduct.
One utility representative stated that his utility plans its system to include gas system limitations and selected contingencies. This includes the complete outage of a single pipeline (and all generation attached). This utility has sufficient generation supplied by other fuels and the transmission to deliver that generation to be able to supply firm load for at least one to two days.
Southeast Regional Initiatives
According to participants, the Florida Reliability Coordinating Council (FRCC) created a flow model of the pipelines in Florida. FRCC also created a Fuel Reliability Working Group (FRWG) that reports to the FRCC Operating Reliability Subcommittee on matters relating to fuel and impacts to Bulk Electric System reliability. Specifically, the FRWG provides the administrative oversight of a regional fuel reliability forum that studies the interdependencies of fuel availability and electric reliability and supports coordinated regional responses to fuel issues and emergencies.28
At least one pipeline in the region offers an enhanced nomination service, and others are contemplating a similar service.

IV.Topics Common to Multiple Regions

The conferences summarized above were planned as a series of regional discussions given that the particular circumstances and needs of each region are distinct. Notwithstanding the regional focus of the discussions, a recurring theme across all of the conferences was that more attention needs to be paid to gas-electric interdependence issues. Participants in multiple conferences also stressed that some matters may be more appropriate for generic consideration while others are more appropriate for individual regions to address. In addition, several topics were of particular interest to participants across the conferences. The discussion below focuses on these topics:

communications, coordination, and information sharing, including the Standards of Conduct and prohibitions on undue preference and discrimination;

scheduling-related issues, including the no-bump rule and pipeline capacity release policies;

electric resource adequacy, including RTO and ISO wholesale electric capacity markets; and

reliability issues.

Industry representatives participating in the technical conferences described ongoing efforts to address each of these topics, noting that some issues implicate rules of general applicability while others are tied more closely to market structures or the resource mix of a particular region. For example, conference participants generally stated that communications and coordination improvements could be made on a regional basis, but that generic guidance regarding Commission rules and policies would facilitate progress. Similarly, while electric scheduling practices within a particular region can be
refined to better align with gas scheduling opportunities, changes to gas scheduling rules would require national coordination given the way pipeline systems are operated. In comparison, resource adequacy and reliability issues are often tied to the structure and performance of the electric system in a particular region.
Staff discusses on-going efforts in each of these cross-cutting areas below. Where relevant, staff provides guidance regarding applicable Commission rules and policies and highlights regional activities that will be monitored for progress.

A.Communications, Coordination, and Information-Sharing

Gas and electric industry representatives participating in the technical conferences described a variety of actions that are being taken to improve communications and information sharing between their industries. However, participants at multiple conferences expressed concern that Commission rules and policies could be impeding further efforts to improve communication between the industries. Industry representatives asked that the Commission provide guidance regarding application of the Standards of Conduct and prohibitions on undue discrimination and preference in the context of gas-electric coordination. After reviewing actions already being taken across the regions, relevant Commission regulations and precedent are discussed and opportunities for further progress are highlighted below.
Groups have been formed in multiple regions to enhance communication and coordination across the gas and electric industries. For example, in the Northeast, ISO-NE, representatives of its stakeholders, the Northeast Gas Association, and pipelines serving the region have formed a working group/steering committee to foster improved communications within the region.29 NYISO formed an Electric Gas Coordination Working Group earlier this year,30 and in August the MISO announced a taskforce to
work on general gas-electric coordination issues.31 In the West, the Northwest Mutual Assistance Agreement aids coordination between utilities during gas-related emergency situations by maintaining updated emergency contact information and conducting semiannual planning meetings.32
Several regions have conducted emergency exercises to test inter-industry coordination and communication. In New York, pipelines, LDCs and generators conducted a “tabletop” reliability exercise under different loss of supply scenarios. Signatories to the Northwest Mutual Assistance Agreement periodically undertake emergency exercises that prepare participants to take timely and effective action when an emergency does occur. One pipeline in the Southwest hosted a mock gas supply emergency exercise in the fall of 2011, and another plans to host a similar mock emergency drill in 2013.
Responding to issues arising from outage coordination, CAISO amended its tariff to enhance communications on gas-related maintenance activities within California.33 The CAISO tariff now specifically authorizes the CAISO to share outage information with natural gas pipelines, with or without notice to the affected market participant. This includes, but is not limited to, the identity of individual natural gas-fired generation resources that are needed to support reliability of the CAISO balancing authority area in the event of a natural gas shortage, natural gas pipeline testing and maintenance, or other curtailment of natural gas supplies. ISO-NE has announced that it is considering revising its policies to allow sharing of real-time operational information with gas pipeline operators.34
At multiple conferences, however, gas and electric industry representatives questioned whether the FERC Standards of Conduct are impeding further efforts to improve communication between the industries. For example, one entity at the West technical conference raised the concern that information-sharing in an emergency situation could be a problem for companies where employees with operational knowledge are also wholesale merchant function employees. Many entities requested that the Commission provide clarity about what types of information can be shared and when.
Some pipelines and RTOs/ISOs also noted at the technical conferences that, although they make significant amounts of operational information publicly available, there is reluctance to share information on a more granular level because of concerns about violating statutory prohibitions against undue preference for any customer or customer class.35 So, for example, in response to one RTO/ISO’s comment that it was not able to interpret a pipeline’s posted outage information in terms of which specific generators would be affected, several pipelines expressed discomfort with going beyond what was publicly posted.36 Pipelines also noted that, in situations where information regarding pipeline capacity limitations has been posted, they typically will be queried on how much interruptible or secondary transportation is available, but they are not required to provide more specific information beyond their public postings.37
At several conferences, pipelines indicated a desire to receive timely information from RTOs/ISOs about the dispatch of the gas-fired generation fleet and the expected impacts after generation forced outages. Some RTOs/ISOs expressed interest in knowing whether the gas-fired units scheduled in the day-ahead market have the necessary gas supply and transportation arrangements in place. While several generators and RTOs/ISOs expressed concern about the market sensitivity of sharing such information, at least one generation operator stated that generation plant operating profiles are regularly communicated to the pipelines to which they are attached, which facilitates those pipelines’ ability to accommodate the generators’ needs for flexible services. Several entities noted that the Commission’s issuance of Order No. 698,38 which requires generators to provide pipelines with hourly gas burn estimates upon request, has improved gas-electric communications for normal operations.
Subsequent to the August conferences, staff conducted additional outreach to solicit more specific feedback from pipelines, RTOs/ISOs and generators about concerns with information sharing. Pipelines and RTOs/ISOs would like to exchange information that allows each to operate their systems more efficiently and reliably. Generally, this would include information about pipeline capacity scheduled (for generation) and available, individual generator’s expected burn rates, quick notice of significant changes in capacity or operations, and coordination of maintenance planning and scheduling.
One RTO suggested some form of a “one call” system so that it could quickly and efficiently inform all relevant gas industry participants supplying a particular generator (or a specific group of generators) of an unexpected change in electric system operations.39 Some natural gas-fired electric generators would like assistance in perfecting nominations for gas flow, especially later in the day after earlier nominations were rejected due to insufficient available pipeline capacity. Some generators are
concerned that information exchanged between a pipeline and an RTO/ISO may lead to unilateral action by either the pipeline or the RTO/ISO which could cause competitive harm to the generator, or may act as a conduit for third parties to gain access to information about a specific generator causing competitive harm to the generator in the marketplace.
In response to concerns expressed by industry representatives at the technical conferences and in subsequent outreach, staff takes this opportunity to provide its views regarding application of the Commission’s Standards of Conduct and statutory restrictions on undue preference or discrimination.40 The discussion of these issues at the conference was general in nature and, therefore, so is staff’s response. To the extent a natural gas pipeline or electric transmission operator has questions regarding the application of Commission rules or regulations in specific circumstances, it should seek appropriate guidance from the Commission or staff.41
Standards of Conduct
The Standards of Conduct govern communications between interstate natural gas pipelines and their affiliates that engage in marketing functions, and public utilities that own or operate electric transmission facilities and their affiliates that engage in marketing functions.42 In other words, the Standards of Conduct apply to communications only within the same organization (i.e., between the affiliated entities of a single corporate family). The Standards of Conduct do not apply to communications between two different natural gas and electric transmission organizations. By their terms, then, the Standards of Conduct do not limit communications between natural gas pipelines and electric transmission operators. Moreover, under section 358.1(c) of the Commission’s regulations, the Standards of Conduct do not apply to Commission-approved RTOs or ISOs.43
In those situations where the Standards of Conduct govern the disclosure of non-public transmission information between the transmission function and marketing function of an organization, the Commission’s regulations already permit communications during “emergency circumstances,” such as hurricanes or earthquakes, when information is needed to comply with reliability standards or to maintain/restore system operations.44 Two sections of the Standards of Conduct specifically authorize communications that may be necessary to address emergency conditions: (1) section 358.7(g)(2) authorizes transmission providers to suspend posting requirements in an emergency; and (2) section 358.7(h)(2) permits communication among employees needed to comply with reliability standards, restore system operations and provide for generation dispatch.45 These sections provide relief from the Standards of Conduct rules, including the Independent Functioning Rule, the No-Conduit Rule, and the Transparency Rule.46
Given that the Standards of Conduct do not govern communications or coordination between a natural gas pipeline and an electric transmission operator, and that exceptions to the Standards of Conduct already are provided to allow communications between the merchant function and transmission function of the same organization during emergencies, staff believes that further discussion with industry is necessary to address the continuing perception that the Standards of Conduct can act as a barrier to effective coordination of the gas and electric industries. In addition, Staff encourages industry representatives to contact staff with specific questions regarding application of the Standards of Conduct in the context of gas-electric coordination.
Undue Discrimination or Preference
Separate questions have been raised by industry representatives regarding whether sharing of certain types of information between natural gas pipelines or electric utilities could be viewed as unduly discriminatory or preferential, triggering questions regarding compliance with NGA section 4 and FPA section 205.47 Staff notes that a number of
communication protocols already have been adopted to facilitate the exchange of information between the industries and additional enhancements are being considered by many regions. For example, typical day-to-day practices within each industry provide for the sharing of transmission information among natural gas pipelines, and among electric transmission operators. Pipelines routinely exchange information with other pipelines and other upstream and downstream entities needed to confirm transportation nomination requests, and to coordinate flows between each other. Transmitting electric utilities routinely share eTag information, scheduled interchanges, and related operational data to ensure the safe and reliable transmission of electric power across a region.
As between industries, natural gas pipelines and electric generators have established protocols for sharing a significant amount of information pursuant to Order No. 698. Under the North American Energy Standards Board (NAESB) Wholesale Gas Quadrant (WGQ) Version 2.0 Business Practice Standard 0.3.12, a generator and its directly connected natural gas pipeline(s) “should establish procedures to communicate material changes in circumstances that may impact hourly flow rates.” These communications can help natural gas pipelines anticipate problems, devise solutions and take timely action to avoid operational problems.48 NAESB WGQ Version 2.0 Business Practice Standard 0.3.14 further provides that a pipeline “should provide Balancing Authorities and Reliability Coordinators” and generators with notification of operational flow orders and other critical notices. NAESB Wholesale Electric Quadrant (WEQ) Version 002.1 Business Practice Standard 11.1.4 states that RTOs and ISOs “should sign up to receive” these pipeline notices. These communications can help electric transmission operators better manage their systems by reallocating resources in response to changing conditions on natural gas pipelines.
As noted above, CAISO has begun sharing with natural gas pipelines information regarding outages of generation or transmission facilities within its footprint. Specifically, CAISO is authorized to provide outage information to natural gas pipelines for their use in managing, coordinating, planning, forecasting, and/or scheduling outages, maintenance, repairs, and/or curtailment of their gas transmission pipeline or storage systems.49 This allows CAISO and natural gas pipelines to coordinate outages and
maintenance of generation and transmission resources necessary to ensure the safe and reliable operation of the natural gas system.50 In recognition that the information exchanged can be sensitive, CAISO requires natural gas pipelines to execute non-disclosure agreements that define the purposes for which information may be used and affirms the pipeline’s commitments to follow the Commission’s Standards of Conduct with regard to further communication of the information.
Industry participants at multiple technical conferences expressed a desire for inter-industry communication of the sort currently engaged in by CAISO and natural gas pipelines. The CAISO tariff provisions and non-disclosure agreement serve as an example to other electric transmission operators seeking to implement communication protocols with natural gas pipelines. Other types of information may be useful for natural gas pipelines to share with electric transmission operators. For example, information regarding generators’ scheduled natural gas flow, alternatives where available pipeline capacity would allow deliveries to flow to natural gas-fired generators not yet scheduled, and future available capacity alternatives may assist electric transmission operators respond to changing system conditions more efficiently and maintain reliability of the electric transmission grid. A natural gas pipeline wishing to exchange non-public capacity-related information with electric transmission system operators without subjecting itself to possible future complaints of undue discrimination or preference might also look to the CAISO outage management model, with its non-disclosure agreement and reliance on the Commission’s Standards of Conduct to ensure that any information shared is appropriately used and protected.
As with concerns related to the Commission’s Standards of Conduct, staff appreciates that representatives from both the natural gas and electric industries seek additional comfort that enhanced communication and coordination practices will not violate statutory prohibitions on undue discrimination or preference. Staff believes that further discussion with industry is necessary to identify and address concerns in this area. Conference participants described a number of initiatives to improve inter-industry communication and coordination, including:

Development of communication protocols governing gas and electric maintenance-related outage coordination, suggested by MISO and pipeline and LDC members of the Northeast Gas Association;

ISO-NE’s consideration of revised policies to allow sharing of real-time operational information with gas pipeline operators;

The possibility of brief exchanges of pipeline and electric transmission provider control room operators, for cross-training purposes, as noted by PJM and a Mid-Atlantic pipeline;

The development of a “one call” system to allow an RTO/ISO to inform relevant gas industry participants of unexpected changes in electric system operations;

Enhancement of inter-industry communication and coordination during normal operating conditions under the Northwest Mutual Assistance Agreement; and,

The use of tabletop exercises in multiple regions to examine different scenarios based on loss of supply.Staff will monitor progress being made on these and other initiatives, and provide guidance where possible to ensure that concerns regarding Commission rules and policies do not hinder industry progress.

B.Scheduling-Related Issues

Several conference participants raised issues related to gas and electric scheduling and pipeline capacity release.51 Generators participating in the RTO/ISO markets stated that managing fuel procurement risk can be a challenge because the operating days between the natural gas and electric industries are not aligned, and the timeframe for nominating natural gas transportation service, including pursuant to a capacity release, is not synchronized with the timeframe during which generators receive confirmation of their bids in the day-ahead electric markets. While electric scheduling practices and market rules within some regions are being refined to better align with gas scheduling opportunities, changes to gas scheduling practices can have national implications given the way pipeline systems are operated. As a result, whether gas scheduling practices need to be changed and, if so, what changes are warranted has been a matter of debate among the industries for a number of years.
Scheduling Practices
Standard pipeline services are generally designed as daily services, and the gas day covers a 24-hour period beginning at 9:00 a.m. Central clock time (CCT). For most rate schedules, tariffs provide that the pipeline may insist that gas be taken on a uniform hourly rate of flow although the pipeline tariffs generally provide that the pipeline permits fluctuations in flow on a best efforts basis. The NAESB gas standards, which the
Commission regulations incorporate by reference, currently provide shippers one day-ahead nomination opportunity, the Timely Nomination Cycle (11:30 a.m. CCT the day prior to gas flow), and three opportunities to revise that nomination, one in the day-ahead (the Evening Nomination Cycle (6 p.m. CCT the day before gas flow) and two within the gas day (the Intra-Day 1 (10 a.m. CCT the day of gas flow) and Intra-Day 2 (5 p.m. CCT the day of gas flow)). In the event a pipeline cannot fulfill all service requests, the pipeline allocates capacity according to its nomination priorities. As a general matter, (1) nominations of firm transportation service from “primary” points of receipt to “primary” points of delivery, which is termed “primary firm” service, have the highest priority; (2) nominations from alternative or additional “secondary” receipt or delivery points, which is termed “secondary firm service,” is next in priority and (3) interruptible service is the lowest priority.
Schedules made during the Timely Nomination Cycle establish the allocation of pipeline capacity for the next gas day. In this cycle, the priorities listed above apply so primary firm nominations have priority over all other nominations. During the next three cycles, primary and secondary point nominations are treated equally, so a request to change quantities at a primary point will not bump already scheduled secondary firm service. A revised firm nomination during the Evening and Intra-Day cycles, however, can bump already scheduled interruptible service from prior cycles. During the final Intra-Day- 2 cycle, primary and secondary firm nominations cannot bump already scheduled interruptible service. Pipelines are permitted to offer additional nomination opportunities.
In contrast, electric generators are dispatched during the operating day hour-by-hour. A gas-fired generator may operate for many hours throughout the day or may operate only during peak hours. Increasingly, gas-fired generators are being dispatched as flexible resources, ramping up and down within the hour and across the day to help balance the electric system.
There is no defined electric day, but for most entities the standard 24-hour calendar day begins at 12:00 a.m. local time. Similar to the gas industry, electric generators in wholesale electric markets bid into the market prior to the given electric day, commonly known as the day-ahead market. For these generators, the time to obtain the best natural gas prices is typically before the Timely Nomination Cycle, because the gas markets would be most liquid at this time.52 However, an electric generator’s day-
ahead electric bids generally are not confirmed by the RTO/ISO until after the Timely Nomination Cycle for pipeline service.53
Various generators participating in the RTO/ISO markets noted that these differing timelines result in significant price and/or supply risk for gas-fired generators because, to obtain the best gas price, the generators would need to nominate pipeline transportation service before they know if their electric bid has been confirmed. Generators also noted that, given the operating day mismatch, a pipeline nomination will cover parts of two electric days and therefore involve multiple iterations of the unit commitment process as day-ahead commitments turn into real time dispatch and the day-ahead commitments for the next electric day.54 Concern also was expressed about whether the standard gas nomination schedule provides sufficient ability for generators to revise their nominations as needed by dispatch requirements, whether located within or outside RTO and ISO markets.
Representatives from the gas and electric industries participating in the conferences offered different perspectives on whether changes need to be made in either industry’s scheduling framework. As several pipeline representatives pointed out, some pipelines offer to shippers more than the NAESB standard four daily nomination cycles. For example, in March of this year, the Commission approved a proposal by Texas Gas Transmission LLC (Texas Gas) to allow firm shippers contracting for Enhanced Nominations Service an additional eleven nomination cycles each gas day.55 Some pipelines offer a firm no-notice service under which firm shippers can receive delivery of gas on demand up to their firm entitlements on a daily basis, without incurring daily scheduling and balancing penalties. The purpose of no-notice service is to enable firm shippers to meet unexpected requirements such as sudden changes in temperature. Some pipelines also offer firm shippers enhanced services that allow for greater flexibility in the rate at which their gas can flow. This service, as well as the no-notice service described above, is provided at a higher rate.
Also, representatives of the NYISO and ISO-NE present at the conferences stated that they have considered ways to change the schedule of the day-ahead unit commitment process to better coincide with the gas timely nomination cycle. For example, ISO-NE is considering moving up the timeline for day-ahead unit commitment and the resource adequacy assessment process in an effort to provide additional time to gas-fired generators to procure gas supplies and transportation services so that adequate generation capacity is available in real time.56 However, it was pointed out by several participants at the conference that one disadvantage of moving the day-ahead unit commitment timeframes closer in time to the gas Timely Nomination Cycle and therefore, further from the real time, is that electric load forecasts become less accurate. Some conference participants also indicated that one reason it has been difficult to change the day-ahead unit commitment process is the absence of a standardized electric schedule across markets, similar to the standardized gas day.
A related scheduling issue raised by conference participants involved the service priorities for transportation services offered by interstate pipelines and the “no-bump” rule.57 As noted above, primary and secondary nominations cannot bump already scheduled interruptible service during the final Intra-day 2 cycle, which is at 5 p.m. CCT.58 Discussion at some of the technical conferences indicated that the general consensus supporting the no-bump rule may no longer exist. Some generators with firm pipeline service stated that they would like to see additional nomination opportunities and in some cases, elimination of the no-bump rule. They contended that the current gas nomination cycles do not provide sufficient flexibility to generators facing weather-driven electric load variations, and the no-bump rule impedes their ability to use their firm service flexibly. However, other firm gas shippers, such as industrial users in the Southeast, argued in favor of retaining the no-bump rule. They stated that elimination of
the no-bump rule could cause fewer shippers to use interruptible transportation, resulting in lower overall utilization of pipeline capacity and a greater share of fixed costs allocated to firm shippers.
As noted by many conference participants, prior efforts of NAESB participants did not reach consensus on the creation of a unified gas and electric timeline,59 revisions to the gas nomination schedule to permit additional intra-day changes, or elimination of the no-bump rule. Several participants maintained that these changes were not a high priority and accordingly, should not be a priority for the Commission. To the extent changes are made, most conference participants agreed that these issues are interrelated and cannot be considered in isolation, and that any changes would need to be implemented in a way that makes sense for both industries from both regional and national perspectives.
Staff believes that further discussion is necessary to explore whether coordinated refinements to gas and electric scheduling rules are appropriate. Existing Commission policies and regulations provide a certain degree of flexibility in the near term for utilities to address coordinated scheduling issues on a regional basis and for pipelines to provide enhanced scheduling. As noted above, several RTOs/ISOs are considering or have refined their market practices and some pipelines have modified services and nomination cycles to meet the needs their customers. These efforts improve operations across both the gas and electric industries and should continue to be pursued. However, they do not address whether industry-wide changes would be appropriate to improve the longer-term harmonization of gas and electric operations. Taking a broader view of gas-electric scheduling issues could lead to greater operational efficiencies in both industries.
To that end, staff will continue to engage industry on gas and electric scheduling issues, including the effect of the Commission’s no-bump rule. During this outreach, staff will monitor the progress being made on the following activities highlighted by conference participants:

ISO-NE’s consideration of moving the timeline for its day-ahead unit commitment and resource adequacy assessment process and allowance of bid adjustments and hourly re-offers;

NYISO’s consideration of moving releasing day-ahead dispatch results to early than 10 AM (EST), when gas markets are more liquid; and,

The ability of natural gas pipelines to offer additional nomination opportunities after 5 PM or provide for electronic scheduling that could be completed faster than the current four hour processing time.
Progress on these nearer-term activities may facilitate greater coordination between the gas and electric markets while longer-term initiatives are being evaluated.
Capacity Release
In many regions, natural gas LDCs contract for firm long-term pipeline service based on their winter peak demand. Consequently, those LDCs generally have excess natural gas transportation capacity in the summer when gas demand is lower. In contrast, gas-fired electric generation in most, but not all, regions experience demand peaks in the summer time when LDC use of pipeline capacity is relatively low.60 As a result, gas-fired generators have generally been able to utilize released pipeline capacity from the LDCs to meet their gas delivery needs.61
As the relative amount of gas-fired generation increases, some contend that in the future these dynamics will no longer hold true. Gas-fired generation has increased to an extent that some pipelines are operating at increasing load factors, with diminishing availability of capacity to serve new gas-fired generation needs. For example, in New England, which experiences relatively high winter electric demand, gas-fired generators are increasingly competing with LDCs for pipeline capacity.
In response to these concerns, participants at every technical conference expressed a desire for more flexible capacity release on pipelines. Issues raised included a desire for more opportunities for intra-day releases and short-term or even hourly releases, enhanced ability to facilitate pre-arranged bilateral release deals, and more streamlined processing of capacity release transactions. In some cases, technical conference participants discussed “gas demand response,” but did not specify what that meant or how it could be implemented on the gas pipelines. In at least one case, a large generator with firm gas contracts suggested that more transparency regarding how pipelines analyze their systems to determine available pipeline capacity would be desirable.
The Commission’s current pipeline capacity release program is designed to permit expeditious and flexible releases.62 A firm shipper (releasing shipper) sells its capacity
by returning its capacity to the pipeline for reassignment to the buyer (replacement shipper).63 Released capacity is offered for bid on the pipeline’s website and awarded to the highest bidder. Firm shippers may also enter into a pre-arranged release directly with a replacement shipper. If the prearranged release is for a term of one month or less it need not be posted for bidding. The replacement shipper may pay less than the pipeline’s maximum tariff rate, but not more for releases that are long term in nature. Short term releases, those for one year or less, are not subject to price limitations tied to a pipeline’s maximum tariff rate.64 Many pipelines also permit replacement shippers to prequalify for releases, which expedites the assignment of capacity.
With respect to the flexibility of releases, the regulations provide that releasing shippers can release capacity at any time and that “pipelines must permit shippers acquiring released capacity to submit a nomination at the earliest available nomination opportunity after the acquisition of capacity.”65 Under the regulations, the pipelines must process these releases in one hour. As a consequence of the Commission’s posting and bidding rules, an LDC and a generator, for example, could negotiate a short term release at a market-determined rate at any nomination cycle permitted by the pipeline, including releases during the intra-day process.66 In addition to capacity release, shippers can make bundled gas sales to third-parties.67
The Commission’s capacity release regulations, including the NAESB WGQ standards, therefore provide shippers with considerable flexibility to acquire released capacity or obtain gas on a timely basis. However, the implementation of a capacity release remains subject to the scheduling opportunities available. As a result, it may be
that the concerns expressed by conference participants are driven more by the desire for greater pipeline scheduling flexibilities, or by an unwillingness of firm transportation contract holders to release capacity, than the Commission’s capacity release rules. Staff notes that no specific reforms in the area of capacity release were suggested by conference participants, nor was the relationship between capacity release and underlying pipeline scheduling opportunities generally discussed. Nonetheless, given the significant number of conference participants that raised capacity release rules as an issue to be address, staff believes is it necessary to continue to engage industry with respect to this issue.

C.Electric Resource Adequacy

The question of whether generators in a particular region have appropriate incentives to deliver firm energy was raised at several of the technical conferences. At every conference, natural gas pipeline representatives emphasized that they are in the business of delivering gas to meet customer needs, but that the customers themselves must arrange for gas supplies. There were differences of opinion, however, with regard to the perceived need for firm delivery arrangements from natural gas pipelines as between electric industry representatives at the conferences.
In the Southeast, characterized by electric service being provided by vertically-integrated electric utilities, firm natural gas pipeline arrangements appear to be the norm. As a result, in this region, there appears to be little concern about ensuring adequate pipeline infrastructure.68 In regions with restructured electric markets and an RTO or ISO, natural gas-fired generators appear to rely more heavily on pipeline capacity release and interruptible services for delivery of gas supplies. Some contend that this practice appropriately reflects the variability with which gas-fired generators are dispatched in RTO/ISO regions, while others suggested the practice indicates a need to provide greater incentives to generators to arrange for fuel supplies in a way that ensures reliability. Conference participants suggesting enhancements to RTO/ISO market rules generally focused on the terms of organized wholesale electric capacity markets and performance incentives for resources clearing in those markets. Several participants at the Northeast conference stated there is a need for additional pipeline infrastructure but there was also recognition that options are limited for addressing the gas infrastructure issue in the near term and that, under current market structures, generators have few incentives to obtain long-term primary firm pipeline service or invest in alternative fuel capabilities.
Most organized wholesale electric capacity markets provide no more than a one-year or seasonal price. Various technical conference participants noted the tension between a short-term one-year price from capacity markets and the long-term decision to contract for firm fuel supply. Representatives from the RTOs and ISOs with organized capacity markets indicated that they are aware of this tension and are exploring potential market design changes. PJM stakeholders are considering multi-year pricing mechanisms, including a voluntary long-term auction.69 A recent letter from PJM indicated that stakeholders are still discussing long-term options and noted that stakeholders agreed to attempt to develop business rules for a multi-year pricing mechanism in time for a May 31, 2013 filing, which could be applied to the May 2014 auction.70
Participants in some regions questioned whether the incentives, penalties, and/or participation requirements in the organized wholesale electric capacity markets are adequate to incent performance and ensure a firm fuel supply. Participants in virtually all regions with capacity markets indicated that their capacity markets do not consider the firmness of a generator’s fuel supply when clearing resources. At the Northeast conference, a representative of ISO-NE indicated that a generator’s Forward Capacity Market (FCM) penalties for not showing up are too low, though one generator argued that forward capacity market nonperformance penalties are substantial. ISO-NE’s representative indicated that its Strategic Planning Initiative includes plans to strengthen capacity market performance incentives. On October 22, ISO-NE shared with stakeholders a white paper on FCM performance incentives that included a proposal to make FCM resources’ revenue contingent on performance during scarcity conditions.71 Stakeholders are currently considering these proposed modifications.
In the Mid-Atlantic region, one gas company in PJM argued that PJM’s Reliability Pricing Model (RPM)72 nonperformance incentives are too weak to encourage a
generator to pay for firm contracts or dual fuel; the gas company argued that PJM should consider increasing penalty provisions or treating a capacity resource as a limited capacity resource. A representative of PJM, however, noted that a generator with an RPM commitment that fails to perform will be penalized with an Unforced Capacity (UCAP)73 reduction and thus earn less in future years. A NYISO representative indicated that they could consider improving their UCAP nonperformance perepresentative of NERC noted that because many capacity market incentives such as Equivalent Forced Outage Rate (EFORd)74 penalties are retrospective, the penalty’s impact does not arrive until three years later. The NERC representative noted that this may be a concern given not only the longer-term dependence on gas, but the near-term dependence on gas because in the next three years a substantial number of coal units will be going offline for retrofit.
Discussion at the conferences affirmed that each region meets resource adequacy requirements in its own way. Focusing on the RTO/ISO markets that rely on capacity market constructs regulated by the Commission, a number of issues have been raised regarding whether and how to structure gas-fired generator’s performance incentives. PJM, ISO-NE and NYISO each have somewhat different market designs and each has commenced work to evaluate performance incentives in their respective regions. MISO continues to study the issue, with plans to refine and update studies evaluating whether generation capacity is sufficient. In CAISO, conference participants stated that gas infrastructure is expanded in anticipation of load (as opposed to responding to firm contracts) and CAISO’s non-performance penalties are adequate.
Staff believes that resource adequacy issues in these markets should continue to be addressed in the first instance by market participants, states, and other stakeholders in each region. Unlike the communication and scheduling issues discusses earlier in this report, generic guidance may not be helpful at this time for regions considering how to structure market rules to ensure that generators have appropriate incentives to deliver firm energy. Significant attention and resources are being devoted to these matters, concrete issues have been identified, and responses to those issues are being formulated.
Staff will monitor progress on these initiatives and encourages industry representatives to contact staff if guidance is required.

D.NERC Activity

A representative of NERC discussed its efforts to study gas electric interdependency reliability issues at several of the conferences, including a potential need to revise reliability assessments such that the assessments would take fuel supply into account. NERC’s representative also indicated that it will complete phase 2 of its Gas-Electric Interdependency Study by the end of 201275 and suggested that recommendations in the phase 2 of the report would include the creation of a taskforce to further identify potential revisions to NERC standards. NERC’s representative also stated that factors associated with the loss of gas lines (such as a gradual loss of gas pressure) may exempt this scenario from the planning standards requirements regarding surviving the loss of the single largest contingency (N-1).76
Participants in several conferences suggested that gas-electric coordination and fuel availability problems could be addressed, in part, with the development of new NERC Reliability Standards or modifications to existing standards. Other participants, such as ISO-NE and PJM, stated that they are addressing electric system performance within their respective regions, whether performance is adversely impacted by fuel supply issues, and what might be needed to address those impacts. Some participants suggested approaches that would establish requirements to study fuel availability and other gas-electric interdependency issues, without mandating specific changes to resource procurement. In the Southeast region, for example, at least one utility indicated that its contingency planning already considers the loss of a single natural gas facility. Other participants expressed concern that fuel supply or resource adequacy requirements could intrude on traditional areas of state jurisdiction.
Staff looks forward to the results of NERC’s interdependency study and the consideration by industry of what additional steps are appropriate to take to address reliability considerations in the context of gas-electric coordination. Staff will monitor the progress of this initiative and encourages active industry participation.