Staff Report on 

Gas-Electric Coordination Technical Conferences 

(Docket No. AD12-12-000) 

November 15, 2012 

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

This report does not necessarily reflect the views of the Commission. 
Staff Report on Gas-Electric Coordination Technical Conferences 

Docket No. AD12-12-000 

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

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

Table of Contents 

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

II. Background ..........................................................................................................................3

III. Summary of Regional Conferences and Ongoing Initiatives to Address Gas-Electric 

Coordination ...............................................................................................................................4

A. Northeast Region..............................................................................................................4

B. Mid-Atlantic Region.........................................................................................................7

C. Central Region..................................................................................................................11

D. West Region .....................................................................................................................13

E. Southeast Region ..............................................................................................................18

IV. Topics Common to Multiple Regions ................................................................................20

A. Communications, Coordination, and Information-Sharing..............................................21

B. Scheduling-Related Issues................................................................................................29

C. Electric Resource Adequacy ...........................................................................................36

D. NERC Activity ................................................................................................................39

V. Closing..................................................................................................................................40

I. Introduction 

 In recent years, reliance on natural gas as a fuel for electric generation has steadily 

increased. This trend is expected to continue in the future, leading to greater 

interdependence between the natural gas and electric industries. In some areas of the 

country, questions have been raised regarding whether adequate market structures and 

appropriate regulations are in place to support this increasing reliance on natural gas-fired 

generation. To explore these issues, the Commission convened five regional conferences 

throughout the month of August 2012, in advance of the winter heating season, to solicit 

input from both industries regarding the coordination of natural gas and electricity 

markets. The conferences were structured around three sets of issues: scheduling and 

market structures/rules; communications, coordination, and information-sharing; and 

reliability concerns. 

A cross-section of industry representatives participated and/or attended the 

regional conferences, with total attendance exceeding 1,200 registrants. Perspectives 

2
varied by region and across industry sectors as to the issues confronting the industries and 

actions to be taken. Information gathered at the conferences confirmed that gas-electric 

interdependence concerns are more acute in some regions than others, with the discussion 

at each conference focusing on the particular circumstances and needs of each region. 

Notwithstanding the regional focus of the discussions, recurring themes across the 

conferences were that more attention needs to be paid to gas-electric interdependence 

issues and that some matters are appropriate for generic consideration while others are 

more appropriate for individual regions to address. 

This report focuses on several topics that were common to multiple regions. First, 

conference participants in many regions sought confirmation that sharing information in 

furtherance of enhancing gas-electric coordination would not run afoul of the 

Commission’s Standards of Conduct or be construed as engaging in undue discrimination 

or preference.1

 Second, a number of concerns were expressed regarding the 

misalignment of gas and electric scheduling practices, as well as application of the nobump rule and pipeline capacity release rules. Third, questions were raised in several 

regions regarding whether generators have appropriate incentives to deliver firm energy. 

Finally, industry representatives in multiple regions are considering appropriate steps to 

take to address reliability considerations in the context of gas-electric coordination. Staff 

addresses these issues by providing guidance where possible and highlighting relevant 

activities taking place in individual regions. 

As the discussion below indicates, significant industry attention and resources are 

being dedicated to address these and a host of gas-electric coordination issues. Several 

regions have implemented or are developing practices to improve coordination and 

communication between the industries during normal operations as well as in emergency 

situations. Some regions are considering changes to electric market rules to address 

increased reliance on gas-fired generation, while pipelines have developed flexible 

products and scheduling protocols for their customers. These efforts have helped 

participants in each industry identify improvements that can be made to support effective 

operations within both industries. 

By focusing on the subset of cross-cutting issues identified above, staff seeks to 

support the progress being made on gas-electric coordination matters. Staff understands 

that there are a number of other issues unique to each region that must be addressed to 

 1

 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. 18 CFR § 358.1(a) and (b) (2012). See discussion in Section IV of this Report, 

below. 

3
improve coordination across the gas and electric industries. Moreover, staff appreciates 

that gas-fired generators are only one of many users of the interstate natural gas pipeline 

system and that any changes to practices or rules within a particular region or the natural 

gas industry more broadly must be informed by the needs of a broad range of customers. 

With these considerations in mind, staff will be actively monitoring and engaging 

industry regarding progress being made in each region to ensure that gas-electric 

coordination issues are identified and addressed. 

II. Background 

 On February 15, 2012, the Commission issued a notice in Docket No. AD12-12-

000 requesting comments on various aspects of gas-electric interdependence and 

coordination in response to questions posed by Commissioner Philip Moeller and 

Commissioner Cheryl LaFleur.2

 Recognizing the electric industry’s increased reliance 

on natural gas to generate electricity now and into the future, Commissioners Moeller an

LaFleur pointed out the critical importance of the interface between the electric and 

natural gas industries. In order to better understand that interface and identify areas for 

improvement, Commissioners Moeller and LaFleur sought comments on a variety of 

topics including market structure and rules, scheduling, communications, infrastructure 

and reliability. 

d 

 

 

The Commission received comments from seventy-nine entities. The commenters 

raised a wide variety of issues regarding gas-electric interdependence. Many of the 

commenters asserted that the issues differed on a regional basis and requested that the 

Commission convene regional technical conferences. 

On July 5, 2012, the Commission responded and issued a notice of a series of 

regional technical conferences to explore coordination between the natural gas and 

electric industries.3

 During the month of August 2012, Commission staff held five 

2 Coordination between Natural Gas and Electricity Markets, Docket No. AD12-

12-000(Feb. 15, 2012) (Notice Assigning Docket No. and Requesting Comments) 

(available at http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12893828). See 

also Commissioner Philip D. Moeller, Request for Comments of Commissioner Moeller 

on Coordination between the Natural Gas and Electricity Markets (Feb. 3, 2012), 

available at http://www.ferc.gov/about/com-mem/moeller/moellergaselectricletter.pdf; 

Commissioner Cheryl A. LaFleur, Statement regarding Standards for Business Practices 

for Interstate Natural Gas Pipelines (Feb. 16, 2012), available at

http://www.ferc.gov/media/statements-speeches/lafleur/2012/02-16-12-lafleur-G-1.asp. 

3 Coordination between Natural Gas and Electricity Markets, Docket No. AD12-

12-000 (July 5, 2012) (Notice of Technical Conferences) (available at

(continued) 

4
regional technical conferences for the Central, Northeast, Southeast, West and MidAtlantic regions. Each conference had a staff-led roundtable discussion of the following 

topics: scheduling and market structures/rules; communications, coordination, and 

information sharing; and reliability concerns. 

III. Summary of Regional Conferences and Ongoing Initiatives to Address GasElectric Coordination

 Before turning to the discussion of concerns common across multiple regions, staff 

provides a summary of general observations at each conference (not in chronological 

order) and information gleaned from publicly available sources. Each regional summary 

includes identification of initiatives to address gas-electric coordination issues that are 

either underway or in the planning stages in each region. 

A. Northeast Region4

 Several participants in the Northeast Region conference stated their views that the 

region is in need of additional pipeline infrastructure. It was noted that New England 

historically has had strong fuel diversity and dual-fuel capability,5

 and that this region 

will depend on dispatching generators with alternate fuel sources out of economic order 

to protect reliability in the face of possible natural gas delivery concerns. 

 Several pipeline participants reported that their systems within the Northeast are 

consistently running near their design capacities. According to statements made at the 

conference, some of the major existing pipelines serving the New England region are 

 

http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=13023450); 77 Fed. Reg. 

41,184 (July 12, 2012) (available at http://www.gpo.gov/fdsys/pkg/FR-2012-07-

12/pdf/2012-16997.pdf). 

4

 The Northeast region technical conference was held August 20, 2012 in Boston, 

Massachusetts, and included natural gas and electric entities from an area defined by the 

corporate boundaries of ISO New England Inc. (ISO-NE) and the States of Connecticut, 

Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. 

5

 According to a recent report by ISO-NE, as recently as the 1990s the region’s 

electricity was produced primarily by oil, coal and nuclear generating plants, with little 

gas-fired generation. In contrast, by 2011, approximately 51% of the electricity 

consumed in New England was produced by gas-fired generation. ISO New England, 

Addressing Gas Dependence,” at 3 (July 2012), available at http://www.isone.com/committees/comm_wkgrps/ strategic_planning_discussion/materials/natural-gaswhite-paper-draft-july-2012.pdf. 

5
nearly fully subscribed or constrained at specific points on their respective systems. The 

lack of available capacity may limit regional pipeline flexibility, and frequently results in 

flow restrictions and strict balance requirements. Both gas and electric industry 

participants stated that relatively little gas-fired generation in New England is backed by 

primary firm pipeline transportation contracts. Instead, participants stated that generators 

typically rely on released secondary firm or, to a much lesser extent, on interruptible 

transportation (IT) pipeline capacity. Some participants also discussed the roles of 

marketers in procuring both pipeline transportation service and gas supplies. 

 Conference participants reported that under the current market structure, 

generators have few incentives to obtain long-term primary firm pipeline service, invest 

in alternate fuel capabilities, or take other steps to ensure fuel availability. A 

representative of ISO-NE reported that several proposed revisions to its forward 

wholesale electric capacity market are being developed. ISO-NE’s representative and 

other conference participants also discussed a proposal to allow hourly re-offers in the 

real-time energy market, and revisions to ISO-NE’s price mitigation rules to allow bids to 

be adjusted to reflect actual fuel costs.6

 

 Several conference participants indicated that options are limited for addressing 

the natural gas pipeline infrastructure issue in the near term. A representative of ISO-NE 

discussed its intentions to review generators’ plans for the winter and determine whether 

individual generating units would be able to continue operating during a cold snap similar 

to that of January 2004. Pipelines stated their focus for the upcoming winter would be to 

maximize utilization of existing pipeline capacity to ensure reliability. 

 In the intermediate term, an ISO-NE representative noted ISO-NE’s plans to 

propose adjustments to the electric market day-ahead scheduling and resource adequacy 

assessment process. Under its proposal, day-ahead awards may be released as early as 30 

hours prior to the start of the electric day, and well in advance of the North American 

Energy Standards Board (NAESB) timely nomination deadline for gas pipeline capacity. 

ISO-NE stated its belief that the current timeline leaves it with too little time to mitigate 

generation supply risks before the start of the operating day. Some conference 

participants voiced support for such a change, while others stated that it would reduce, 

but not eliminate, the risk exposure of the generators. 

 6

 ISO-NE is proposing to allow hourly offers and intra-day re-offers so that 

generators would be able to adjust their bids to reflect changes in fuel costs closer to real 

time. “Accordingly, resources that must buy intra-day gas will be able to reflect their 

true costs, and generators that might not be able to get gas in real-time and want to switch 

to oil will have the ability to reflect the cost of switching.” ISO New England, 

Addressing Gas Dependence, at 15. 

6
Some electric utility and gas local distribution company (LDC) participants 

suggested that further, coordinated studies of regional gas and electric infrastructure are 

needed. A few electric industry participants offered the idea of a regional gas 

infrastructure planning effort, similar to how the region already performs regional electric 

infrastructure planning. Gas industry participants did not express support for this idea. 

 Commentary of participants suggested that they are generally comfortable with the 

quality of communications between the pipelines, generators, and ISO-NE. Some 

observed that the communications currently occur on a largely ad hoc basis, and 

suggested that efforts to further formalize the communications procedures could be 

beneficial. 

 Northeast Regional Initiatives 

 Many technical conference participants supported the idea of forming a steering 

committee to address concerns about gas-electric coordination in the Northeast. The 

steering group would consider changes to the electric day, maximizing assets in the 

region through maintenance planning, and changes to ISO-NE’s market rules, scenario 

planning, and funding mechanisms. 

Participants at the conference discussed the need for improved coordination of 

maintenance outages among electric and natural gas industry participants. 

Representatives of pipelines and LDCs offered that the Northeast Gas Association is 

willing to lead the efforts to develop communication protocols governing gas and electric 

maintenance-related outage coordination. 

As noted above, and according to the ISO-NE participants at the conference, ISONE is considering several potential modifications to its tariff, some to take place sooner 

than others. In the near-term, ISO-NE is considering a plan to conduct a supplemental 

procurement for natural gas, liquefied natural gas, or back up oil supplies to ensure 

adequate supplies over 2013 and 2014. Longer-term, ISO-NE plans to develop certain 

tariff revisions to move up the timeline for day-ahead unit commitment and the resource 

adequacy assessment process in an effort to provide additional time to ensure that gasfired generators may procure gas supplies and delivery services so that adequate 

generation capacity is available in real time.7

 Further, ISO-NE is considering several 

 7

 ISO-NE is proposing to move the day-ahead market back so that generators can 

buy gas and pipeline capacity while the market is still liquid and so that it has more time 

to call on generators. See Janine Dombrowski, Moving the Day Ahead Market & Reserve 

Adequacy Assessment Clearing Times, ISO New England (Aug. 7-8, 2012), available at

http://www.iso-

(continued) 

7
changes to the market rules to allow energy and capacity prices to better reflect the risk of 

generator interruptible vs. firm gas procurement, including changes to the capacity 

product definition, changes to the resource adequacy assessment process, and a review of 

the consequences of generator non-delivery. ISO-NE is also considering a proposal to 

modify the real-time energy market and bid mitigation rules to allow generators to update 

bids to reflect changes in natural gas prices. 8

 

B. Mid-Atlantic Region9

 According to some participants representing generators in the Mid-Atlantic region, 

power markets provide no incentive to purchase firm contracts for pipeline transportation. 

Various other participants in the Mid-Atlantic Region conference pointed out that there 

are multiple ways a gas-fired generator can firm its fuel supplies—through firm contracts 

for pipeline transportation, dual fuel, storage contracts, and access to more than one 

pipeline. A North American Electric Reliability Corporation (NERC) representative 

noted the appeal of a requirement for generator “firmness” that would account for the 

multiple ways to firm-up fuel supply, and identified a potential firmness requirement as 

an item more suited for an RTO/ISO proposal rather than a NERC standard. 

 The prevalence of dual fuel capability in both the NYISO and PJM regions was 

noted. Participants stated that both the PJM and NYISO markets provide some incentive 

or requirement for dual fuel. A representative of PJM said that its Reliability Pricing 

Model (RPM) uses a dual fuel reference unit to determine the Cost of New Entry for the 

wholesale electric capacity market demand curve, which helps set the price of capacity. 

In NYISO, according to conference participants, generators in downstate New York 

(New York City and Long Island) are required to have alternate fuel capability under 

state reliability requirements. Participants generally indicated that gas markets in PJM 

are more liquid than those in NYISO given the availability of various pipelines and 

storage. 

 

ne.com/committees/comm_wkgrps/mrkts_comm/mrkts/mtrls/2012/aug782012/a07_iso_p

resentation_08_07_12.ppt. 

8 See ISO New England, Addressing Gas Dependence, supra n. 5. 

9

 The Mid-Atlantic Region technical conference was held August 30, 2012 and 

included natural gas and electric entities from an area defined by the corporate 

boundaries of New York Independent System Operator Inc. (NYISO), PJM 

Interconnection, L.L.C. (PJM) and related areas, including the States of Delaware, 

Maryland, New Jersey, New York, Ohio, Pennsylvania, Virginia and West Virginia. 

8
While many representatives of generators indicated that they currently are able to 

secure pipeline capacity, several pipelines noted that liquidity and flexibility experienced 

thus far in the Mid-Atlantic region are not necessarily indicative of the flexibility that will 

be available in the future as gas-fired generation grows. Representatives of an LDC and a 

pipeline also argued that cost causality needs to be matched with cost responsibility. An 

LDC representative asserted that today certain costs of serving generators’ variability and 

hourly flows are being paid by LDCs. 

 The issue of the use of secondary firm contracts and recallable capacity release 

contracts (rather than primary firm contracts) as a means of serving gas-fired generation 

was discussed. Several contend the practice of relying on types of transportation services 

other than primary firm transportation to fuel gas-fired generation is not a reliable 

solution given the higher rate of curtailment of secondary firm customers. Some pipeline 

participants also noted that while producers have funded some new pipeline capacity, 

these pipelines only extend far enough to get the natural gas from the producing region to 

a liquid pooling point, and there is still a need to build infrastructure to get natural gas 

from the supply area to generators. Some LDC representatives noted that for generators 

behind their citygates, even if the generator has firm gas contracts on an interstate 

pipeline, it still needs firm natural gas delivery capacity on the LDC’s system. 

 

 Several participants also raised concerns about planning—whether the planning 

horizon is long enough and whether market participants are planning appropriately. 

Noting the differences between electric and gas planning horizons, a pipeline noted that 

pipelines do not plan for growth; rather they build to accommodate firm customers. An 

industrial participant argued that market signals are not a substitute for planning and 

contended that the region may need a longer-term planning horizon. A generator noted 

that while a long-term electric planning process exists, what is missing is consideration of 

fuel security. 

 There was no consensus among Mid-Atlantic conference participants as to the best 

way to address the gas-electric scheduling mismatch. A representative of NYISO stated 

that it currently releases its day-ahead dispatch results earlier (10 a.m. EST) than PJM 

does (4 p.m. EST). NYISO’s representative noted that the earlier release allows gas-fired 

generators to be better informed for the first timely pipeline nomination cycle which 

occurs at 11 a.m. (CST). Feedback from participants representing generators on whether 

they preferred the earlier release or later release was mixed. NYISO’s representative also 

reported that it is considering moving the day-ahead dispatch results release to earlier 

than 10 a.m. (EST) (when gas markets are more liquid) or later (to facilitate better gas 

supply and transportation price certainty when bidding), and will continue to explore 

scheduling through its stakeholder process. Conference participants noted that in PJM, 

where the natural gas market is relatively liquid and there are many pipelines and storage 

reservoirs, generators thus far have been able to acquire natural gas supplies and pipeline 

capacity in later pipeline nomination cycles. Conference participants noted that in 

9
NYISO where the gas market is less liquid it is not always easy to acquire gas after the 

first timely pipeline nomination cycle. 

 With regard to the process for allowing generators to modify bids to reflect actual 

fuel costs, NYISO permits it if a generator had to switch fuels or procure more expensive 

intra-day gas if the ISO increased its dispatch level. According to the PJM 

representative, PJM does not currently permit this, but PJM would be open to considering 

it. 

 Some participants representing generators encouraged the creation of more 

nomination cycles. Pipeline representatives noted that some pipelines in the region 

already offer hourly nomination cycles and stated that more frequent nominations will not 

help if there is inadequate pipeline capacity. 

 Regarding communications, a representative of NYISO noted that it does not 

necessarily understand how pipeline outages impact the electric system and which 

generators will be affected. Representatives of PJM and a pipeline mentioned a 

partnership which would include exchanging control room operators. They expect that 

spending time in each others’ control rooms will help to bridge the language gap and 

learn about each other’s industry. Various conference participants also noted their 

interest in tabletop exercises that simulate reliability scenarios. A representative of 

NYISO noted that several combined gas-electric utilities, along with certain pipelines 

within its area, recently ran a useful tabletop exercise. 

 Conference participants indicated that there is no formal outage coordination 

process across industries, but some expressed support for a formalized process. Some 

conference participants noted there is a tension between wanting to openly discuss 

publicly available information on outages and the impact on operations, and concern 

about whether unit-specific discussion would violate regulations against undue 

preference or discrimination. Pipeline representatives noted reluctance to discuss 

granular impacts at the level of individual shippers beyond the information the pipelines 

make publicly available on electronic bulletin boards. One participant noted that 

enhanced outage coordination gives rise to heightened concern over manipulation. 

Various participants indicated concern about specifying shipper-level information in 

discussions. 

 Participants from both the natural gas and electric industries suggested 

clarification of the Standards of Conduct and Natural Gas Act Section 4b undue 

preference and anti-manipulation rules would be helpful.10 One participant suggested 

 10 N. 35, infra. 

10
“common sense leeway” to the Standards of Conduct rules in emergencies. A pipeline 

trade association representative noted that some RTOs/ISOs have adopted the Standards 

of Conduct in their tariffs and RTOs/ISOs are concerned about sharing information with 

pipelines. PJM’s representative asked whether it can tell pipelines which generator units 

will be dispatched. 

 Participants articulated different views on the markets’ ability to send appropriate 

signals. One pipeline representative argued that electric market signals do not factor in 

reliability and another participant argued that generators in unregulated markets have no 

incentive to contract for firm pipeline transportation. A PJM representative noted that its 

wholesale electric capacity market does not pay generators if they do not run and capacity 

factors11 decline if generators do not run. A generator representative stated that PJM’s 

capacity market sends the right signals, while a pipeline representative argued that PJM’s 

nonperformance penalties are weak and do not justify paying for fuel security. A NERC 

representative noted that many capacity market incentives, such as Equivalent Forced 

Outage Rate—demand (EFORd)12 penalties, are problematic because they are 

retrospective and the impact arrives three years later. 

 In general, participants in this technical conference urged the Commission to “be 

patient” and check back with the regions to see that they continue to make progress on 

most issues involving gas-electric coordination, although there was interest in having the 

communications issues clarified. 

 Mid-Atlantic Regional Initiatives 

 A representative of NYISO noted that NYISO, PJM, ISO-NE, the Ontario 

Independent Electricity System Operator (IESO), and possibly also Midwest Independent 

System Operator (MISO) are planning a comprehensive study across pipelines serving 

these regions that would incorporate retirements and infrastructure changes over five to 

ten years. The study will examine planned generation retirements, new transmission 

lines, and new pipelines for the next five to 10 years and try to identify any electric 

reliability problems. The study is expected to be available sometime in 2013. 

On communications between the RTOs/ISOs and the pipelines in coordinating 

outages, representatives of PJM and NYISO discussed educational processes and 

 11 Capacity factor refers to the ratio of a plant's output during a period of time to its 

potential output if it had operated at its full nameplate capacity. 

12 EFORd is a measure of the probability that a generator will not meet its demand 

periods for generating requirements. 

11
operator training and exchange programs, and the development of protocols for the 

sharing of maintenance schedules.13 As mentioned above, several combined utilities 

went through a tabletop reliability scenario exercise with several pipelines, where they 

examined different scenarios based upon loss of supply.

C. Central Region14

 Many participants in the Central Region conference stated that gas-electric 

coordination in the region is not currently a problem. However, a representative of MISO 

suggested that this could change in 2013-2015 when it expects approximately 30,000 

MW of coal-fired generation to either be retired or taken off line for retrofits to meet 

emissions standards over the 2012-2015 period. MISO’s representative anticipates this 

will result in a greater reliance upon gas-fired generators, and said that it is particularly 

concerned about the unavailability of coal units during the December – April period, 

when natural gas demand is highest. 

Participants came down on all sides of the gas-electric scheduling question. Some 

suggested that both markets would benefit if the market schedules were more aligned: if 

the electric market cleared earlier in the day and the timely (first) gas nomination cycle 

occurred later in the day, market participants would be able to make gas supply 

arrangements at a time when the natural gas market is more liquid, based upon knowing 

earlier which generation plants were going to run. Others asserted that the earlier dayahead electric commitments are made, the less accurate the load and price forecasts 

become. Some firm gas pipeline shippers expressed concern about the impact of 

increased gas-fired generation upon the quality of their firm pipeline services. 

Suggestions to improve gas pipeline flexibility include revisiting the “no-bump” rule and 

making intra-day capacity release more flexible. A few shippers noted what they 

 13 See, e.g., NYISO, NYISO Tariffs, OATT, § 34, Attachment BB, New York 

State Gas-Electric Coordination Protocol (available at http://www.nyiso.com/public/ 

webdocs/documents/ tariffs/oatt/oatt_attachments/att_bb.pdf). The protocol applies 

where a gas system event would likely lead to a loss of firm electric load on either bulk or 

local power system; applies in emergency situations only and not to situations where a 

generator is derated for economic reasons. 

14 The Central Region technical conference was held August 6, 2012 in St. Louis, 

Missouri, and included natural gas and electric entities from an area defined by the 

corporate boundaries of MISO, Southwest Power Pool, Inc. (SPP), and Electric 

Reliability Council of Texas (ERCOT). It included the states of Arkansas, Illinois, 

Indiana, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi, Missouri, 

Nebraska, North Dakota, Oklahoma, South Dakota, Texas, and Wisconsin. 

12
described as the high quality and flexibility of their pipeline transportation services. One 

pipeline representative expressed a willingness to continue to create flexible services for 

customers, including offering short-term capacity and volumetric rates. 

 Participants generally reported that there is little direct communication between 

the pipelines and electric system operators in this region. Many participants asserted that 

responsibility for information-sharing lies with the generator, and that generators should 

be responsible for communicating and sharing outage, capacity, and expected gas burn 

information with both the pipelines and the RTOs/ISOs. Several participants suggested 

that information sharing could be improved by having RTOs/ISOs provide the gas 

pipelines with hourly generator commitments, so that pipelines would know in advance 

which gas-fired generators are likely to run. Many expressed concern, however, about 

the market sensitivity and the potential for violations of the Commission’s regulations 

prohibiting undue discrimination or preference associated with sharing such information. 

They suggested that adequate protections would need to be in place to ensure such 

information was confined only to operating personnel and not shared with marketing 

departments. 

 Another example identified at this conference was gas-electric communications 

during emergencies and peak demand situations. While generators often provide the 

pipelines with a day-ahead hourly burn profiles as required by NAESB gas-electric 

business standards,15 pipelines suggested more real-time information would also be 

useful, especially during electric contingencies that could affect gas facilities such as 

electric compression, production or storage. Again, concerns were raised about violating 

the Commission’s regulations against anti-competitive conduct. 

 Addressing reliability concerns, it was suggested that entities responsible for 

resource adequacy should evaluate fuel availability in their loss of load probability 

(LOLP) studies for both winter and summer planning. MISO’s representative suggested 

that this could be accomplished by including unavailability due to lack of fuel in the 

generators’ forced outage rate. However, there was concern expressed that the forced 

outage rates are historical and do not reflect the expected unavailability due to increases 

in capacity factors of gas-fired generation. 

 Central Regional Initiatives 

 15 See Order No. 698. Order No. 698 mandates that communication protocols be 

established between interstate pipelines, power plant operators, and transmission 

owners/operators, and among other things requires power plant operators to provide their 

projected hourly natural gas flow rates to directly-connected pipelines upon request. 

13
A representative of MISO noted that it is continuing to refine and update an 

October 2011 study,16 which looked at whether current generation capacity is sufficient 

given planned coal plant retirements and planned retrofit outages expected in the 2013-

2015 period. MISO’s representative committed to working with the pipelines that serve 

the generators in its control area and obtaining a more definitive planned 

outage/maintenance schedule from coal-fired generation as they move into the 2013-2015 

time period. In addition, he noted that MISO recently formed a task force to work on 

general gas-electric coordination issues.17

 A representative of ERCOT suggested it could act as a host for tabletop exercises 

for RTOs/ISOs and pipelines to review emergency procedures and discuss 

communication issues and risks on the bulk power and natural gas systems.

D. West Region18

 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 

 16 See MISO, EPA Impact Analysis: Impacts from the EPA Regulations on MISO

(Oct. 2011), available at https://www.midwestiso.org/Library/ 

Repository/Study/MISO%20EPA%20Impact%20Analysis.pdf. 

17 MISO’s Natural Gas Coordination Task Force was recently formed to address 

these issues. See MISO, Steering Committee Meeting Minutes (Sept. 20, 2012), 

available at https://www.midwestiso.org/

Library/Repository/Meeting%20Material/Stakeholder/Steering%20Committee/2012/2012

1018/20121018%20SC%20Item%2001b%20Minutes%2020120920.pdf. 

18 The West Region technical conference was held August 28, 2012 in Portland, 

Oregon, and included natural gas and electric entities from an area defined by the 

Western Interconnection, and included the States of Arizona, California, Colorado, Idaho, 

Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming. 

14
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 

15
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.21

 19 FERC Office of Electric Reliability Staff recently conducted technical 

conferences in Texas and New Mexico (Docket No. AD11-9-000) to discuss actions 

taken in response to the August 16, 2011 Report on Outages and Curtailments During the 

Southwest Cold Weather Event of February 1-5, 2011. See FERC and NERC, Report on 

Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 

2011 (Aug. 2011), available at http://www.ferc.gov/legal/staff-reports/08-16-11-

report.pdf. 

20 Signatories to the NMAA agreement are defined as entities that utilize, operate 

or control natural gas transportation and/or storage facilities in the Pacific Northwest. 

The membership includes pipelines, LDCs, combined utilities, and electric-only utilities. 

An emergency is defined as “an unplanned event [that] causes, or is likely to cause, a 

supply shortfall to firm customers or markets beyond the abilities of a Member to 

manage.” See Western Energy Institute, Northwest Mutual Assistance Agreement, 

http://www.westgov.org/wieb/meetings/crepcfall2012/briefing/NWmaa.pdf

21 http://www.westernenergy.org/WRMAA/wrmaa.htm. 

16
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 

 22 See PNUCC, Northwest Regional Forecast of Power Loads and Resources, 

2013–2022, (Mar. 2012), available at http://www.pnucc.org/ sites/default/files/fileuploads/2012%20Northwest%20Regional%20Forecast.pdf. This report indicates that 

while natural gas currently is used primarily for peak demand needs, utilities in the region 

expect most of the generation added in the next 10 years to be natural gas-fired, followed 

by wind. 

17
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 

 23 See, Merchant Alert Protocol (MAP) Guideline, WECC (April 20, 2011), 

available at

http://www.wecc.biz/committees/StandingCommittees/MIC/Shared%20Documents/Guid

eline%20-%20Merchant%20Alert%20Protocol.pdf. 

24 ColumbiaGrid is a non-profit membership corporation formed in 2006 to 

improve the operational efficiency, reliability, and planned expansion of the Pacific 

Northwest transmission grid. The corporation itself does not own transmission, but its 

members and the parties to its agreements own and operate an extensive network of 

transmission facilities. ColumbiaGrid has substantive responsibilities for transmission 

planning, reliability, Open-Access Same-Time Information System (OASIS), and other 

development services. 

25 The area is home to about 4,400 MW of natural gas-fired generation that serves 

the Portland and Seattle areas. 

26 See ColumbiaGrid, http://www.columbiagrid.org/GasElectric-overview.cfm. 

18
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 Region27

 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 nobump 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 

 27 The Southeast region technical conference was held August 23, 2012 and 

included natural gas and electric entities from an area defined by the corporate 

boundaries of Southern Company, Tennessee Valley Authority, and other areas south of 

PJM and east of SPP and ERCOT. It included the States of Alabama, Arkansas, Florida, 

Georgia, Kentucky, Louisiana, Mississippi, North Carolina, South Carolina, and 

Tennessee. 

19
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 gasfired 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 

20
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 

 28 See FRCC, Scope of FRCC Fuel Reliability Working Group (Feb. 1, 2008), 

https://www.frcc.com/FRWG/ Shared%20Documents/ 

FRCC%20FRWG%20Scope%2002-01-08.pdf. 

21
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, ISONE, 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 

 29 In the wake of the 2004 cold snap in New England, ISO-NE and the Northeast 

Gas Association formed the Electric/Gas Operations Committee (EGOC), consisting of 

representatives from the regional pipelines and gas LDCs as well as ISO-NE, NYISO and 

PJM. The EGOC is responsible for cross-training of electric and gas system operators, 

establishing emergency communications protocols and procedures, assessing 

coordination of electric and gas system maintenance requirements, and other common 

issues. See ISO New England, Electric/Gas Operations Committee, http://www.isone.com/committees/comm_wkgrps/othr/egoc/index.html. 

30 See NYISO, Electric Gas Coordination Working Group, 

http://www.nyiso.com/public/committees/documents.jsp?com=bic_egcwg&directory=20

12-03-05. 

22
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

 31 MISO’s Natural Gas Coordination Task Force was recently formed to address 

these issues. See MISO, Steering Committee Meeting Minutes (Sept. 20, 2012), 

available at

https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/Steeri

ng%20Committee/2012/20121018/20121018%20SC%20Item%2001b%20Minutes%202

0120920.pdf. 

32 See Western Energy Institute, Northwest Mutual Assistance Agreement, 

available at http://www.westgov.org/wieb/meetings/crepcfall2012/briefing/NWmaa.pdf. 

33 See Cal. Indep. Sys. Operator Corp., Docket No. ER12-278-000 (Dec. 8, 2011) 

(delegated letter order). 

34 See John Norden, Information Policy Changes to Facilitate Electric and Gas 

Coordination, ISO New England (Oct. 11, 2012), available at http://www.isone.com/committees/comm_wkgrps/mrkts_comm/mrkts/mtrls/2012/oct10112012/a13_iso

_presentation_10_11_12.ppt. 

23
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 

 35 Both the Federal Power Act (FPA) and the Natural Gas Act (NGA) prohibit 

undue discrimination or preference. See 16 U.S.C. § 824d(b); 15 U.S.C. § 717c (b). 

Section 205(b) of the FPA provides that no public utility 

shall, with respect to any transmission or sale subject to the 

jurisdiction of the Commission, (1) make or grant any undue 

preference or advantage to any person or subject any person to any 

undue prejudice or disadvantage, or (2) maintain any unreasonable 

difference in rates, charges, service, facilities, or in any other 

respect, either as between localities or as between classes of service. 

Nearly identical language is contained in section 4(b) of the NGA, 15 U.S.C. § 

717c(b). 

36 See 18. C.F.R. § 284.13 (2012) (Reporting requirements for interstate pipelines). 

37 Pipelines are required to post estimates of their operationally available capacity 

based on prior schedules. They are not required to separately report how much 

interruptible or secondary firm transportation is available. See 18 C.F.R. § 284.13 and 

NAESB Version 2.0 WGQ Standard No. O.4.2. 

24
 

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 

 38 Standards for Business Practices for Interstate Natural Gas Pipelines; 

Standards for Business Practices for Public Utilities, Order No. 698, FERC Stats. & 

Regs. ¶ 31,251 (2007), order on clarification and reh’g, Order No. 698-A, 121 FERC ¶ 

61,264 (2007) (collectively, Order No. 698). Order No. 698 mandates that 

communication protocols be established between interstate pipelines, power plant 

operators, and transmission owners/operators, and among other things requires power 

plant operators to provide their projected hourly natural gas flow rates to directlyconnected pipelines upon request. 

39 Regional cooperation and appropriate contractual measures would appear to be 

required to accomplish any form of “one call” system such as this. Staff does not address 

this suggestion further in this report. 

25
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 

 40 Under section 358.7(a) of the Commission’s regulations, a transmission 

provider must provide equal access to non-public transmission information disclosed to 

its affiliated merchant function, to all its transmission customers. 18 C.F.R. § 358.7 

(2012). See also, n.35 supra. 

41 Obtaining Guidance on Regulatory Requirements, 123 FERC ¶ 61,157 (2008). 

42 18 C.F.R. § 358.1(a) and (b) (2012). 

43 18 C.F.R. § 358.1(c) (2012). 

26
In those situations where the Standards of Conduct govern the disclosure of nonpublic 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 

 44 18 C.F.R. § 358.7(g)(2), (h)(2) (2012). 

45 18 C.F.R. § 358.7(g)(2), 358.7(h)(2) (2012). See Standards of Conduct for 

Transmission Providers, Order No. 717, FERC Stats. & Regs. ¶ 31,280 (2008), order on 

reh'g, Order No. 717-A, FERC Stats. & Regs. ¶ 31,297, order on reh'g, Order No. 717-B, 

129 FERC ¶ 61,123 (2009), order on reh'g, Order No. 717-C, 131 FERC ¶ 61,045 

(2010), order on reh'g, Order No. 717-D, 135 FERC ¶ 61,017 (2011) (collectively, Order 

No. 717). 

46 18 C.F.R. §§ 358.5, 358.6, 358.7 (2012). 

47 See n.35 supra. 

27
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 

 48 Anecdotal evidence from the technical conferences and staff outreach suggests 

that this practice may not be in widespread use among pipelines nationwide, 

notwithstanding the opportunity provided by the NAESB standards. 

49 Cal. Indep. Sys. Operator Corp., Business Practice Manual for Outage 

Management, at section 4.2.1.2 (Apr. 30, 2012) (setting forth the terms of a nondisclosure and use of information agreement), available at 

https://bpm.caiso.com/bpm/bpm/doc/000000000001211. 

28
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 nondisclosure 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 interindustry 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; 

 50 See Cal. Indep. Sys. Operator Corp., Docket No. ER12-278-000, Oct. 31, 2011 

Filing at 2. 

29
 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 

 51 The Commission rules governing capacity release on interstate pipelines are at 

18 C.F.R. § 284.8 (2012). 

30
Commission regulations incorporate by reference, currently provide shippers one dayahead 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-byhour. 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-

 52 Natural gas is traded in bilateral markets. Daily transactions are mostly 

consummated in the morning hours before the first timely day-ahead pipeline nomination 

deadline. The ability to find willing buyers and sellers to act as counterparties of a 

commodity transaction is greatest during these normal trading periods; the gas market is 

“liquid” during this time of the day. 

31
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. 

 53 Electric scheduling timelines are set forth in the respective RTO/ISO tariffs and 

are not uniform across entities. 

54 Conversely, an electric generator may seek to procure gas during two successive 

daily cycles to accommodate the needs of a single electric day. 

55 See Texas Gas Transmission LLC, 137 FERC ¶ 61,093 (2011), order on 

compliance filing, 138 FERC ¶ 61,176 (2012) (collectively, Texas Gas) (offering 

enhanced nomination service with bumping of interruptible service permitted until 5 

p.m.). 

32
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 weatherdriven 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 

 56 ISO-NE is proposing to move the day-ahead market back so that generators can 

buy gas and pipeline capacity while the market is still liquid and so that ISO-NE has 

more time to call on generators. See Moving the Day Ahead Market & Reserve 

Adequacy Assessment Clearing Times, ISO New England (Aug. 7-8, 2012), available at

http://www.iso-ne.com/

committees/comm_wkgrps/mrkts_comm/mrkts/mtrls/2012/aug782012/a07_iso_presentat

ion_08_07_12.ppt. 

57 As noted above, at the Intra-Day 2 cycle, a firm nomination will not bump 

already scheduled interruptible service. This is referred to as the “no-bump” rule. 

58 Standards for Business Practices of Interstate Natural Gas Pipelines, Order No. 

587-G, FERC Stats. & Regs. ¶ 31,062, at 30,670-72 (1998). This rule also applies to 

those pipelines that offer enhanced nomination services. 

33
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. 

 59 Standards for Business Practices for Interstate Natural Gas Pipelines, Order 

No. 587-U, FERC Stats. & Regs. ¶ 31,307 at P 27 (2010). 

34
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, gasfired 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 

 60 Gas-fired generators in other regions of the country, particularly the Southeast, 

do not rely on interruptible transportation or capacity release to ensure reliability, but 

contract directly for firm primary point transportation service with the pipelines. 

61 The Commission rules governing capacity release on interstate pipelines are at 

18 C.F.R. § 284.8 (2012). 

62 18 C.F.R. § 284.8 (2012). 

35
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 

 63 The pipeline contracts with, and receives payment from, the replacement shipper 

and then issues a credit to the releasing shipper. 

64 The results of all releases are posted by the pipeline on its Internet web site and 

made available through standardized, downloadable files. 18 C.F.R. § 284.13(b)(1) 

(2012). 

65 18 C.F.R. § 284.12 (b)(1)(ii)(A) (2012). 

66 In the intra-day process, shippers are permitted to release the unused portion of 

their contract demand. 

67 For example, an LDC could sell its gas to an electric generator. Under the 

Commission regulations, a holder of pipeline capacity can redirect that capacity without a 

requirement for rescheduling that supply, so long as the original contract provides for 

service beyond any constraint point. NAESB WEQ Standard 1.3.80. 

36
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 verticallyintegrated 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. 

 68 The exception to this is Florida, which is highly dependent upon gas for electric 

generation. Some Southeast regional conference participants identified a need for a third 

natural gas pipeline into Florida for reliability purposes. 

37
Most organized wholesale electric capacity markets provide no more than a oneyear 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 

 69 PJM Multi-year Pricing Mechanism, http://www.pjm.com/committees-andgroups/issue-tracking/issue-tracking-details.aspx?Issue={B709F188-450F-4A06-A5EBBD61B601C9EF}. 

70 PJM Interconnection, L.L.C., Docket No. ER12-513-000, July 31, 2012 

Supplemental Information Filing, available at 

http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=13038241. 

71 ISO-NE, FCM Performance Incentives (Oct. 2012) available at http://www.isone.com/committees/comm_wkgrps/strategic_planning_discussion/materials/fcm_perform

ance_white_paper.pdf. 

72 RPM refers to PJM’s capacity market. 

38
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 pe

representative of NERC noted that because many capacity market incentives such as 

Equivalent Forced Outage Rate (EFORd)

nalty. A 

 

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. 

73 UCAP refers to installed capacity adjusted by forced outage rates. UCAP 

represents the amount of MWs a resource can sell into a capacity market. For instance, a 

100MW resource with a 20% forced outage rate would have its installed capacity (100 

MW) reduced by its 20% forced outage rate so that the resource could only sell 80 MW 

of unforced capacity into a capacity market. 

74 Equivalent Forced Outage Rate (EFORd) refers to the probability that a 

generator will not be available due to forced outages or forced deratings when there is 

demand for the unit to generate. 

39
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 GasElectric 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. 

 75 See North American Electric Reliability Corporation, 2011 Special Reliability 

Assessment: A Primer of the Natural Gas and Electric Power Interdependency in the 

United States (Dec. 2011), available at

http://www.nerc.com/files/Gas_Electric_Interdependencies_Phase_I.pdf. 

76 TPL-002. 

40
41

V. Closing

As indicated in the discussion above, significant industry attention and resources 

are being dedicated to a host of issues related to the coordination of the gas and electric 

industries. While the focus of this report is on the coordination, scheduling, resource 

adequacy and reliability issues that were common to multiple technical conferences, Staff 

appreciates that there are a number of other issues unique to each region that must be 

addressed to improve coordination across the gas and electric industries. Staff will be 

actively monitoring and engaging industry regarding progress made in each region to 

ensure that gas-electric coordination issues are identified and addressed.