Document ID: FERC-2015-0508-0001
Agency: ferc
Document Type: Rule
Title: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities
Posted Date: 2015-04-24T04:00Z

[Federal Register Volume 80, Number 79 (Friday, April 24, 2015)]
[Rules and Regulations]
[Pages 23197-23227]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-09275]

[[Page 23197]]

Vol. 80

Friday,

No. 79

April 24, 2015

Part III

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 284

Coordination of the Scheduling Processes of Interstate Natural Gas 
Pipelines and Public Utilities; Final Rule

  Federal Register / Vol. 80 , No. 79 / Friday, April 24, 2015 / Rules 
and Regulations  

[[Page 23198]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 284

[Docket No. RM14-2-000; Order No. 809]

Coordination of the Scheduling Processes of Interstate Natural 
Gas Pipelines and Public Utilities

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission 
(Commission) is revising its regulations to better coordinate the 
scheduling of wholesale natural gas and electricity markets in light of 
increased reliance on natural gas for electric generation, as well as 
to provide additional scheduling flexibility to all shippers on 
interstate natural gas pipelines. The revised regulations in this Final 
Rule modify the scheduling practices used by interstate pipelines to 
schedule natural gas transportation service and provide additional 
contracting flexibility to firm natural gas transportation customers 
through the use of multi-party transportation contracts. The revisions 
in this Final Rule, together with the Commission's action in certain 
related proceedings, will better ensure the reliable and efficient 
operation of both the interstate natural gas pipeline and electricity 
systems.

DATES: This rule will become effective July 8, 2015. The incorporation 
by reference of certain publications listed in this rule is approved by 
the Director of the Federal Register as of July 8, 2015.

FOR FURTHER INFORMATION CONTACT: 
Anna Fernandez (Legal Information), Federal Energy Regulatory 
Commission, Office of the General Counsel, 888 First Street NE., 
Washington, DC 20426, (202) 502-6682.

Caroline Daly Wozniak (Technical Information), Federal Energy 
Regulatory Commission, Office of Energy Policy and Innovation, 888 
First Street NE., Washington, DC 20426, (202) 502-8931.

SUPPLEMENTARY INFORMATION:

ORDER NO. 809

FINAL RULE

Table Of Contents

 
                                                              Paragraph
                                                               numbers
 
I. Background..............................................           4.
    A. Notice of Proposed Rulemaking.......................          12.
    B. NAESB...............................................          17.
    C. Subsequent Developments.............................          21.
II. Discussion.............................................          23.
III. Gas Day...............................................          26.
    A. NOPR Proposal.......................................          26.
    B. NOPR Comments.......................................          28.
    C. Data Request and ISO and RTO Responses..............          49.
    D. Comments on Data Request............................          61.
    E. Commission Determination............................          62.
IV. Natural Gas Transportation Nomination Timeline.........          71.
    A. Background..........................................          71.
    B. Natural Gas Transportation Day-Ahead Cycles.........          75.
        1. NOPR Proposal...................................          78.
        2. Revised NAESB Day-Ahead Nomination Cycles.......          82.
        3. NOPR Comments...................................          84.
        4. Commission Determination........................          87.
    C. Intraday Nomination Cycles..........................          89.
        1. NOPR Proposal...................................          91.
        2. NAESB's Revised Intraday Nomination Cycles......          93.
        3. Comments........................................          94.
        4. Commission Determination........................         104.
V. DSPS Proposal...........................................         108.
    A. Background..........................................         108.
    B. DSPS's Proposed National Changes....................         111.
        1. Comments........................................         112.
        2. Commission Determination........................         121.
    C. 1-Year Pilot Program................................         124.
        1. Comments........................................         125.
        2. Commission Determination........................         127.
VI. Multi-Party Transportation Contracts...................         128.
    A. Background..........................................         128.
    B. NOPR Proposal.......................................         130.
    C. Comments............................................         133.
    D. Commission Determination............................         142.
VII. Notice of Use of Voluntary Consensus Standards........         149.
VIII. Incorporation By Reference...........................         150.
IX. Information Collection Statement.......................         153.
X. Environmental Analysis..................................         161.
XI. Regulatory Flexibility Act Certification...............         162.
XII. Implementation Schedule...............................         165.
    A. Comments............................................         165.
    B. Commission Determination............................         168.
XIII. Document Availability................................         172.
XIV. Effective Date and Congressional Notification.........         175.
 

[[Page 23199]]

    1. In this Final Rule, the Federal Energy Regulatory Commission 
(Commission) revises Part 284 of the Commission's regulations relating 
to the scheduling of transportation service on interstate natural gas 
pipelines to better coordinate the scheduling practices of the 
wholesale natural gas and electric industries, as well as to provide 
additional scheduling flexibility to all shippers on interstate natural 
gas pipelines. The Final Rule changes the nationwide Timely Nomination 
Cycle nomination deadline for scheduling natural gas transportation 
from 11:30 a.m. Central Clock Time (CCT) to 1:00 p.m. CCT and revises 
the intraday nomination timeline, to include adding an additional 
intraday scheduling opportunity during the gas operating day (Gas Day). 
The Final Rule effectuates these changes by incorporating by reference 
into the Commission's regulations the standards developed and filed by 
the North American Energy Standards Board (NAESB).\1\ The revised 
regulations in this Final Rule also provide additional contracting 
flexibility to firm natural gas transportation customers through the 
use of multi-party transportation contracts.
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    \1\ NAESB is accredited by the American National Standards 
Institute (ANSI) as an accredited standards organization. NAESB 
complies with ANSI's requirements that its procedures are open to 
materially affected entities and that the standards represent a 
reasonable consensus of the industry without domination by any 
single interest or interest category.
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    2. On March 20, 2014, the Commission instituted proceedings under 
section 206 of the Federal Power Act (FPA) \2\ to ensure that each 
Independent System Operator's (ISO) and Regional Transmission 
Organization's (RTO) scheduling, particularly its day-ahead scheduling 
practices, correlate with any revisions to the natural gas scheduling 
practices ultimately adopted by the Commission in this Final Rule. The 
Section 206 Order provides that ninety days after publication of this 
Final Rule in the Federal Register each ISO and RTO is required to 
propose tariff revisions to coordinate its day-ahead market with the 
changes adopted herein or to show cause why its existing scheduling 
practices need not be changed. This Final Rule--together with actions 
already undertaken by the Commission in other dockets as discussed 
below, additional regional efforts underway by market participants and 
stakeholders, and any actions taken in the section 206 proceeding on 
ISO and RTO scheduling practices--is designed to better ensure the 
reliable and efficient operation of both the interstate natural gas 
pipeline and electricity systems.
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    \2\ California Independent System Operator Corp., et al, order 
initiating investigation into ISO/RTO scheduling practices and 
establishing paper hearing procedures, 146 FERC ] 61,202 (2014) 
(Section 206 Order).
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    3. However, for the reasons described below, the Commission 
declines to adopt the proposal to change the start of the Gas Day. It 
is not clear that requiring a change in the Gas Day start time would 
provide sufficient benefits to outweigh the operational and safety 
impacts and costs of making such a change. While the Commission 
declines to take action in this proceeding to change the start of the 
Gas Day on a nation-wide basis, we note that since the issuance of the 
NOPR in March 2014 both ISO-NE and PJM (the two regions that appear to 
be of the most concern) have recently undertaken operational and market 
actions to address the availability and performance of generators, 
including gas-fired generators, in their footprints. These and other 
regional efforts to address generator performance may result in natural 
gas-fired generators and other market participants in these regions 
taking actions to alleviate some of the electric industry fuel supply 
concerns underlying the Gas Day proposal in the NOPR.

I. Background

    4. The Commission's existing regulations incorporate by reference 
the interstate natural gas pipeline scheduling business practice 
standards of NAESB's Wholesale Gas Quadrant (WGQ).\3\ NAESB is a 
consensus standards organization composed of representatives of all 
segments of the natural gas industry and the electric power industry. 
Since 1996, these standards have established nationwide timelines that 
the industry and the Commission have determined are necessary to 
establish a more efficient and integrated pipeline grid.
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    \3\ See 18 CFR 284.12(a) and (b) (2014).
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    5. The existing 24-hour operating day, or Gas Day, for interstate 
natural gas pipelines begins at 9:00 a.m. CCT and ends at 9:00 a.m. CCT 
the following day. All nominations for interstate natural gas pipeline 
transportation service are for a daily quantity to be transported over 
the 24-hour Gas Day.\4\ The rate at which a shipper may use its 
contracted quantity on a given interstate pipeline, also known as a 
flow rate, is determined by the individual pipeline's tariff and the 
flexibility of that pipeline to permit shippers to use gas on other 
than a uniform hourly basis over the 24-hour Gas Day (i.e., non-ratable 
flows). Except for special services, pipeline services are generally 
based on the assumption of uniform hourly flows over the Gas Day.\5\
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    \4\ The NAESB WGQ standards refer to CCT which refers to the 
actual time in the Central Time Zone, reflecting Central Standard 
Time or Daylight Savings Time, whichever is applicable.
    \5\ During much of the year, most interstate natural gas 
pipelines can accommodate significant variations in hourly flow 
rates. However, during high demand periods when pipeline 
capabilities are being fully utilized to provide firm transportation 
services, a pipeline may announce a critical notice period, where 
shippers are expected to stay in balance. Some pipelines also offer 
enhanced services that permit subscribing shippers more variable 
hourly flow rates.
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    6. The current NAESB WGQ standards establish four standard 
nomination periods (i.e., periods during which a shipper can request 
transportation service under its contract) for a Gas Day. As summarized 
in Table 1 below, shippers have two nomination opportunities prior to 
the day of gas flow, the Timely Nomination Cycle and the Evening 
Nomination Cycle, and two opportunities to revise their nominations on 
the day of gas flow (Intraday 1 and Intraday 2). Individual pipelines 
may offer additional scheduling opportunities beyond the standard 
nomination cycles.\6\
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    \6\ See, e.g., Texas Gas Transmission LLC, 137 FERC ] 61,093 
(2011), order on compliance, 138 FERC ] 61,176 (2013) (Texas Gas); 
and Gulf South Pipeline Company LP, 141 FERC ] 61,262 (2012) (Gulf 
South).

                                  Table 1--Current NAESB Gas Nomination Cycles
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                                   Nomination deadline    Notification of         Nomination
         Nomination cycle                  (CCT)          schedule  (CCT)      effective  (CCT)    Bumping of IT
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Timely...........................  11:30 a.m..........  4:30 p.m...........  9:00 a.m. Next Day.  N/A.
Evening..........................  6:00 p.m...........  10:00 p.m..........  9:00 a.m. Next Day.  Yes.
Intraday 1.......................  10:00 a.m..........  2:00 p.m...........  5:00 p.m. Current    Yes.
                                                                              Day.
Intraday 2.......................  5:00 p.m...........  9:00 p.m...........  9:00 p.m. Current    No.
                                                                              Day.
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[[Page 23200]]

    7. With respect to electric industry scheduling practices, the 
Commission has accepted regional variation in the development of 
scheduling practices in ISO and RTO electric markets, each of which has 
established its own scheduling timelines. For most electric utilities, 
the 24-hour operating day begins at 12:00 a.m. local time. The ISOs' 
and RTOs' practice of scheduling resources generally includes the 
commitment and dispatch of sufficient, deliverable generation to supply 
load in a reliable least cost manner, all based on generator 
availability and the transmission facilities that will be in service 
that day. To perform the unit commitment and dispatch processes used to 
develop daily resource schedules, each ISO and RTO has its own timeline 
for collecting supply offers from generators and expected demand from 
load serving entities on the day prior to the operating day. The ISOs 
and RTOs then run market algorithms that determine the least cost set 
of resources that can be used to serve the next day's load. Each ISO 
and RTO also performs a reliability unit commitment process to procure 
resources, in addition to those resources committed to serve the load 
bid into the day-ahead market, as necessary to meet the ISO's or RTO's 
own forecast of the next day's load or other system needs. Each ISO and 
RTO establishes its own timing for executing the day-ahead and 
reliability scheduling processes, including the times of day when bids 
and offers are due to the system operator, when the market and 
reliability processes are run, and when the results of the scheduling 
processes are made available to generators.\7\
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    \7\ FERC, Operator-Initiated Commitments in RTO and ISO Markets, 
Docket No. AD14-14-000 (Dec. 2014), available at http://www.ferc.gov/legal/staff-reports/2014/AD14-14-operator-actions.pdf.
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    8. In non-ISO and RTO systems, the Commission's pro forma OATT 
specifies that firm interchange schedules need to be submitted by 10:00 
a.m. day-ahead or a reasonable time that is generally accepted in the 
region and is consistently adhered to by the Transmission Provider.\8\
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    \8\ Pro forma OATT section 13.8. Schedules for Non-Firm Point-
To-Point Transmission Service must be submitted to the Transmission 
Provider no later than 2:00 p.m. of the day prior to commencement of 
such service. Pro forma OATT section 14.6.
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    9. Recent developments in the wholesale natural gas and electricity 
industries--particularly the organized electricity markets--signal that 
changes to the gas nomination schedule may be needed.\9\ Reliance on 
natural gas as a fuel for electric generation has steadily increased in 
recent years.\10\ This trend is expected to continue, resulting in 
greater interdependence between the natural gas and electric 
industries.\11\ Several events over the last few years, such as the 
Southwest Cold Weather Event \12\ and the extreme and sustained cold 
weather events in the eastern U.S. in January 2014,\13\ show the 
crucial interrelationship between natural gas pipelines and electric 
transmission operators and underscore the need for improvements in the 
coordination of wholesale natural gas and electric markets.
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    \9\ The Commission is directing ISOs and RTOs to make 
corresponding changes in the Section 206 Order.
    \10\ See, e.g., U.S. Energy Information Administration, Annual 
Energy Outlook 2014 with projections to 2040 at ES-4 (April 2014); 
North American Electric Reliability Corporation, 2014 Long-Term 
Reliability Assessment (November 2014) at 19.
    \11\ See, e.g., U.S. Energy Information Administration, Annual 
Energy Outlook 2014 with projections to 2040 (April 2014) (Natural 
gas-fired generation is projected to overtake coal-fired generation 
for U.S. electricity generation by 2040. Natural gas' share of U.S. 
electricity generation is projected to increase from 30 percent in 
2012 to 35 percent in 2040.); ICF Assessment of New England's 
Natural Gas Pipeline Capacity to Satisfy Short and Near-Term 
Electric Generation Needs: Phase II Final Report (November 20, 
2014); North American Electric Reliability Corporation, 2014 Long-
Term Reliability Assessment (November 2014) at 13.
    \12\ See FERC/NERC, Report on Outages and Curtailments During 
the Southwest Cold Weather Event of February 1-5, 2011 (2011), 
available at http://www.ferc.gov/legal/staff-reports/08-16-11-report.pdf.
    \13\ The widespread and record low temperatures during January 
2014 resulted in coincident record peak demand for natural gas 
throughout the Midwest, Northeast, Mid-Atlantic, and Southeast 
regions leading to constrained pipeline capacity and high natural 
gas prices. In addition, in February 2014, arctic temperatures 
limited the availability of natural gas to supply New Mexico and 
Southern California leading CAISO to issue a system alert and a 
request for consumers to reduce power demand around the system. 
CAISO invoked increasingly stringent measures throughout the day to 
move generation off natural gas, reduce demand, and maintain 
sufficient supply to meet firm load. See FERC Staff Presentation 
``Recent Weather Impacts on the Bulk Power System,'' January 16, 
2014, http://www.ferc.gov/CalendarFiles/20140116102908-A-4-Presentation.pdf.
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    10. Since early 2012, the Commission has conducted multiple 
technical conferences and requested comment on various aspects of gas-
electric interdependence and coordination in order to better understand 
the interface between the electric and natural gas pipeline industries 
and identify areas for improved coordination.\14\ In a report issued on 
November 15, 2012, Commission staff noted that natural gas and electric 
industry participants highlighted the need for greater alignment of 
natural gas and electric scheduling practices.\15\ At the direction of 
the Commission, staff conducted an additional technical conference in 
April 2013 to specifically discuss natural gas and electric scheduling 
practices, including whether and how natural gas and electric industry 
scheduling practices could be harmonized in order to achieve more 
efficient scheduling practices for both industries.\16\
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    \14\ See Coordination Between Natural Gas and Electricity 
Markets, Docket No. AD12-12-000 (Feb. 15, 2012), available at http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12893828.
    \15\ Staff Report on Gas-Electric Coordination Technical 
Conferences, Docket No. AD12-12-000 (Nov. 15, 2012) (November Staff 
Report), available at http://elibrary.ferc.gov/idmws/File_List.asp.
    \16\ Coordination between Natural Gas and Electricity Markets, 
Docket No. AD12-12-000 (Mar. 5, 2013) (Notice of Technical 
Conference), available at http://elibrary.ferc.gov/idmws/File_list.asp?document_id=14095482.
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    11. At the April 2013 conference, participants identified several 
areas in which the differences between the nationwide natural gas 
schedule and the regional electric schedules can affect the provision 
of reliable service and may create inefficiencies in scheduling that 
result in less cost effective use of resources. The participants 
identified three major issues. These included: (1) The difference 
between the standardized operating day of interstate natural gas 
pipelines and the operating days of electric utilities (including ISOs 
and RTOs); (2) the lack of coordination between the day-ahead process 
for nominating interstate natural gas pipeline transportation services 
and the day-ahead process for scheduling electric generators, 
particularly those in the ISOs and RTOs; and (3) the lack of intraday 
nomination opportunities on interstate natural gas pipelines, which 
limits the ability of gas-fired electric generators, as well as other 
shippers, to revise their nominations during the operating day. Several 
conference participants stressed that, due to the difficult policy 
questions involved, they would need Commission policy guidance before 
they would be able move forward on coordination of the natural gas and 
electric industries existing scheduling practices.

A. Notice of Proposed Rulemaking

    12. Based on the increased reliance on natural gas as a fuel for 
electric generation and in consideration of the discussions at the 
2012-2013 technical conferences and filed comments, the Commission 
concluded that the concerns identified by the industries warranted 
further action. On March 20, 2014, the Commission issued the Notice of 
Proposed Rulemaking (NOPR or Proposed Rule) to address concerns

[[Page 23201]]

with divergent interstate natural gas pipeline and wholesale electric 
utility scheduling practices, as well as concerns regarding the 
flexible and efficient use of pipeline capacity by natural gas-fired 
generators and other shippers.\17\
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    \17\ Coordination of the Scheduling Processes of Interstate 
Natural Gas Pipelines and Public Utilities, 79 FR 18223 (Apr. 1, 
2014), FERC Stats. & Regs ] 32,700 (2014) (cross-referenced at 146 
FERC ] 61,201 (2014)) (NOPR).
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    13. The NOPR proposed three changes to the nationwide natural gas 
scheduling practices: (1) Move the start of the Gas Day from 9:00 a.m. 
CCT to 4:00 a.m. CCT; (2) move the start of the first day-ahead gas 
nomination opportunity for pipeline scheduling (Timely Nomination 
Cycle) from the current 11:30 a.m. CCT to 1:00 p.m. CCT;\18\ and (3) 
modify the current intraday nomination timeline to provide four 
intraday nomination cycles, instead of the existing two, to provide 
greater flexibility to all pipeline shippers.
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    \18\ The Commission did not propose any changes to the Evening 
Nomination Cycle.
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    14. The NOPR also proposed to require interstate natural gas 
pipelines to offer multi-party transportation contracts to provide 
multiple shippers the flexibility to share interstate pipeline capacity 
to serve complementary needs in an efficient manner, and the NOPR 
provided clarification of the Commission's no-bump policy with respect 
to any enhanced nomination opportunity proposed by a pipeline (beyond 
the standard nomination opportunities).
    15. Recognizing that the natural gas and electricity industries 
were best positioned to work out the details of how changes in 
scheduling practices could most efficiently be made and implemented, 
the Commission provided the natural gas and electric industries, 
through NAESB, with a period of 180 days after publication of the NOPR 
in the Federal Register to reach consensus on any revisions to the 
Commission's proposals regarding the Gas Day and pipeline nomination 
timeline and either file consensus standards with the Commission or 
notify the Commission of the natural gas and electric industries' 
inability to reach consensus on any revisions to the Commission's 
proposals. Comments on NAESB's consensus standards, as well as comments 
on the Commission's proposals, were to be filed 240 days after 
publication of the NOPR in the Federal Register, or November 28, 2014. 
In the NOPR, the Commission stated that if the Commission were to adopt 
regulations that have not been approved by NAESB, it would expect NAESB 
to integrate the Commission's regulations into its standards within 90 
days of the effective date of the final rule and to notify the 
Commission when the standards have been approved.
    16. On the same day the NOPR was issued, the Commission issued two 
other orders, which, in conjunction with the NOPR, were designed to 
better ensure the reliable and efficient operation of both the 
interstate natural gas pipeline and electricity systems. In one order, 
the Commission instituted proceedings under section 206 of the Federal 
Power Act (FPA) \19\ to ensure that each ISO's and RTO's scheduling 
practices, particularly its day-ahead scheduling practices, correlate 
with any revisions to the natural gas scheduling practices ultimately 
adopted by the Commission in the instant proceeding.\20\ In the Section 
206 Order, the Commission required each ISO and RTO within ninety days 
of the publication of a Final Rule in this proceeding to: (1) Make a 
filing that proposes tariff changes to adjust the time at which the 
results of its day-ahead energy market and reliability unit commitment 
process (or equivalent) are posted to a time that is sufficiently in 
advance of the Timely and Evening Nomination Cycles, respectively, to 
allow gas-fired generators to procure natural gas supply and pipeline 
transportation capacity to serve their obligations; or (2) show cause 
why such changes are not necessary. In the second order, the Commission 
instituted proceedings, under section 5 of the Natural Gas Act (NGA) 
\21\ to examine whether interstate natural gas pipelines are providing 
notice of offers to purchase released pipeline capacity in accordance 
with section 284.8(d) of the Commission's regulations.\22\
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    \19\ 16 U.S.C. 824e (2012).
    \20\ Section 206 Order, 146 FERC ] 61,202.
    \21\ 15 U.S.C. 717d.
    \22\ Posting of Offers to Purchase Capacity, 146 FERC ] 61,203 
(2014). See also 18 CFR 284.8(d) (2013).
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B. NAESB

    17. Following issuance of the NOPR, NAESB reconvened the Gas 
Electric Harmonization (GEH) Forum as the platform for the gas and 
electric industries to consider the NOPR proposals, as well as to 
develop any consensus-based alternatives to the NOPR proposals.\23\ The 
GEH Forum was tasked with developing a recommendation for consideration 
by the NAESB Board of Directors (Board). The GEH Forum and NAESB Board 
convened several meetings between April and June 2014 with nearly five 
hundred active participants and over seven-hundred participants 
monitoring the activity, representing all facets of the wholesale gas 
and wholesale electric markets.\24\
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    \23\ The NAESB Board of Directors formally defined consensus of 
the GEH Forum as 67 percent affirmative vote of each of the 
wholesale gas and wholesale electric quadrants and 40 percent 
affirmative vote of each of the segments of the two quadrants.
    \24\ NAESB June 18, 2014 Report at 11.
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    18. Four alternatives to the NOPR proposal were considered during 
the final GEH Forum meeting.\25\ The day-ahead and intraday nomination 
cycles in each package were the same,\26\ but the start of the Gas Day 
in each package was different. Disagreement over the start of the Gas 
Day prevented the GEH Forum from reaching consensus on any of the 
alternative proposals to the NOPR.\27\ The GEH Forum was also unable to 
reach consensus on an alternative proposal that did not define the Gas 
Day, but contained the same day-ahead and intraday nomination schedule 
as the four alternative proposals. Several participants expressed 
concern that any alternative proposal would be incomplete without a Gas 
Day start time, and indicated that they could not support a package 
that did not include the start of the Gas Day.\28\
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    \25\ Id. at 9.
    \26\ Id. at 8. The nomination deadline for the Timely and 
Evening Nomination Cycles were the same as those proposed in the 
NOPR--1:00 p.m. CCT and 6:00 p.m. CCT, respectively. The modified 
NAESB standards proposed only three intraday nomination 
opportunities, instead of four as proposed in the NOPR. The 
nomination deadlines for Intraday 1, Intraday 2 and Intraday 3 would 
be at 10:00 a.m. (bump), 2:30 p.m. (bump), and 7:00 p.m. (no-bump), 
all CCT.
    \27\ Id. at 9-10.
    \28\ Id.
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    19. Despite the inability of the GEH Forum to reach consensus, the 
NAESB Board directed the WGQ to proceed with the development of 
standards related to the day-ahead and intraday nomination cycles given 
the broad agreement among industry participants on those issues.\29\ 
Electric utilities could participate in the WGQ meetings, but only 
members of the WGQ were eligible to participate in the final vote 
(i.e., Wholesale Electric Quadrant (WEQ) members that are not also 
members of the WGQ, such as the ISO and RTO segment, were ineligible to 
vote on the standards).
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    \29\ Id. at 10.
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    20. On June 18, 2014, NAESB filed a status report with the 
Commission. On September 29, 2014, NAESB filed a second report to 
supplement the June 18 report and to inform the Commission of the 
modifications to the NAESB WGQ Business Practice Standards that were

[[Page 23202]]

developed at the direction of the NAESB Board.\30\ The modified NAESB 
WGQ Business Practice Standards revise the nomination timeline to 
provide for three intraday nomination cycles in addition to the Timely 
and Evening Nomination Cycles. NAESB stated that nomination cycles are 
not dependent upon a specific start time to the Gas Day and are 
implementable with whichever time the Commission chooses as a start of 
the Gas Day. On November 26, 2014, NAESB filled another report to 
inform the Commission of the options the organization may pursue to 
respond to Commission action within the ninety-day deadline provided in 
the NOPR, if the Commission adopts regulations not approved by NAESB.
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    \30\ NAESB reports that, in total, there are modifications to 
twenty-three NAESB WGQ Business Practice Standards: The NAESB WGQ 
Nomination Related Standard Nos. 1.1.18, 1.2.4, 1.3.1, 1.3.2, 1.3.3, 
1.3.4, 1.3.13, 1.3.14, 1.3.41, 1.3.42, 1.3.51, and 1.3.80, the NAESB 
WGQ Flowing Gas Related Standard Nos. 2.2.5, 2.3.5, and 2.3.21, the 
NAESB WGQ Quadrant Electronic Delivery Mechanism Related Standard 
No. 4.3.90, and the NAESB WGQ Capacity Release Related Standard Nos. 
5.3.2, 5.3.44, 5.3.45, 5.3.48, 5.3.49, 5.3.53, and 5.3.54. NAESB 
states that, pursuant to the direction given by the NAESB Board of 
Directors, the NAESB WGQ Business Practice Standards are silent as 
to a start time of the Gas Day. Accordingly, references to the 
specific start time of the Gas Day in NAESB WGQ Standard No. 1.3.1 
have been removed and replaced by the placeholder: [?]. Likewise, 
NAESB WGQ Standard No. 1.3.41 was revised to contain a generic 
reference to the start time of the Gas Day. NAESB states that, 
should the Commission identify a specific start time of the Gas Day, 
it will revise the language of the NAESB WGQ Business Practice 
Standards as necessary. NAESB WGQ Annual Plan Item 11c which 
modified the NAESB standards was approved by the NAESB WGQ Executive 
Committee and ratified by the NAESB membership on September 22, 
2014. In addition, Minor Correction M14018 was applied to these 
standards effective October 10, 2014.
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C. Subsequent Developments

    21. On October 15, 2014, the Commission issued a notice of NAESB's 
September 29 report. The notice provided that comments in response to 
the NOPR should address the alternate proposal submitted to NAESB by 
the Desert Southwest Pipeline Stakeholders during the formal comment 
period on the proposed modifications to the NAESB WGQ standards.\31\ 
Comments on the NOPR were due on November 28, 2014. Seventy-five 
comments were filed. Comments were received from all sectors of both 
industries, including ISOs and RTOs, electric utilities, interstate 
natural gas pipelines, local distribution companies (LDC), producers, 
state regulators, electric generators, and other interested persons.
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    \31\ NAESB Sept. 29, 2014 Report at Appendix C.
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    22. On December 12, 2014, Commission staff requested data from each 
of the six jurisdictional ISOs and RTOs regarding their experience with 
the impact on reliable and efficient operations of natural gas-fired 
generators running out of their daily nomination of natural gas 
transportation service during the morning electric ramp, to the extent 
this occurs. California Independent System Operator Corporation 
(CAISO), ISO New England Inc. (ISO-NE), Midcontinent Independent System 
Operator, Inc. (MISO), New York Independent System Operator, Inc. 
(NYISO), PJM Interconnection, L.L.C. (PJM), and Southwest Power Pool, 
Inc. (SPP) each filed a response to the data request. On February 2, 
2015, American Public Gas Association (APGA), Natural Gas Council, New 
England LDCs,\32\ and the Enhanced Reliability Coalition \33\ filed 
comments on the ISO and RTO responses.
---------------------------------------------------------------------------

    \32\ New England LDCs include the following: Bay State Gas 
Company d/b/a/Columbia Gas of Massachusetts, The Berkshire Gas 
Company, Connecticut Natural Gas Corporation, Fitchburg Gas and 
Electric Light Company, City of Holyoke, Massachusetts Gas and 
Electric Department, City of Norwich, Department of Public 
Utilities, Liberty Utilities (EnergyNorth Natural Gas) Corp. d/b/a 
Liberty Utilities, Middleborough Gas & Electric Department, New 
England Natural Gas Company d/b/a Liberty Utilities, Northern 
Utilities, Inc., NSTAR Gas Company, The Southern Connecticut Gas 
Company, Westfield Gas & Electric Department and Yankee Gas Services 
Company.
    \33\ The Enhanced Reliability Coalition represents the views of 
a wide variety of electric and gas industry companies located 
throughout the United States and Canada that provide services such 
as natural gas production, interstate and intrastate gas pipeline 
transportation, natural gas distribution, natural gas procurement 
for core and industrial customers, natural gas procurement for 
electric generation, natural gas storage, electric generation, 
electric transmission, natural gas and electricity marketers, retail 
electric service, competitive retail electric and natural gas 
service, and electric procurement for customers.
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II. Discussion

    23. Based on the record developed in this proceeding, the 
Commission is taking final action to address certain natural gas and 
electric industry coordination challenges resulting from the divergent 
interstate natural gas pipeline and electric utility scheduling 
practices. The Commission is revising its regulations to incorporate by 
reference the modified NAESB WGQ Business Practice Standards, which 
revise the standard nomination timeline for interstate natural gas 
pipelines.\34\ These changes will revise the most liquid nomination 
cycle for scheduling natural gas transportation, the nationwide day-
ahead Timely Nomination Cycle, so that the nomination deadline will be 
1:00 p.m. CCT rather than 11:30 a.m. CCT, and will include an 
additional intraday scheduling opportunity, as well as conforming other 
standards to these revisions.\35\ The Commission is also revising its 
regulations to provide additional contracting flexibility to firm 
natural gas transportation customers through the use of multi-party 
transportation contracts. However, the Commission declines to adopt the 
NOPR proposal to move the start of the Gas Day.
---------------------------------------------------------------------------

    \34\ NAESB's WGQ Annual Plan Item 11c and Minor Correction 
MC14018.
    \35\ See Appendix.
---------------------------------------------------------------------------

    24. The Commission expects that these changes will provide 
significant benefits to both the natural gas and electricity 
industries, and will improve coordination between the industries. 
Moving the Timely Nomination Cycle to an hour and a half later will 
allow electric transmission operators additional time to complete their 
day-ahead scheduling sufficiently before the Timely Nomination Cycle 
deadline, so that gas-fired generators receive electric market dispatch 
instructions prior to the deadline for acquiring pipeline capacity in 
the Timely Nomination Cycle. The vast majority of commenters from both 
the gas and electric industries support this change. This change is 
further complemented by NAESB's revised three intraday nomination 
cycles that will provide shippers with greater flexibility to revise 
their nominations to adjust to system conditions and changes to load 
during the Gas Day. The addition of an afternoon bumpable cycle, 
together with a later, evening no-bump cycle, should afford firm 
transportation shippers, particularly those in the western United 
States, more of an opportunity to revise nominations to take into 
account weather and load changes. The comments in this proceeding show 
that these nationwide changes are supported broadly across the natural 
gas and electric industries.
    25. The Commission does not find a sufficient record at this time 
to revise the nationwide Gas Day start time as proposed in the NOPR. As 
discussed in more detail below, it is not clear that requiring a change 
in the Gas Day start time would provide sufficient benefits to outweigh 
the operational and safety impacts and costs of making such a change. 
The record developed here--including the comments received on the NOPR 
proposal and the data responses submitted by the ISOs and RTOs-- 
suggests that the concerns underlying the proposal to change the Gas 
Day start time, to the extent they exist, are primarily regional in 
nature. As a result, we find that it is appropriate to allow the 
changes to the standard natural gas pipeline nomination timelines in 
this

[[Page 23203]]

Final Rule, as well as changes to market rules and practices in the 
electric industry, to be implemented and evaluated without changing the 
nationwide Gas Day. While we will not revise the nationwide Gas Day in 
this proceeding, ongoing regional efforts to address electricity market 
reforms and fuel assurance, and the individual section 206 proceedings 
initiated by the Commission to review ISO and RTO day-ahead scheduling 
practices, provide opportunities to seek regional solutions to the 
concerns underlying the Gas Day proposal in the NOPR.

III. Gas Day

A. NOPR Proposal

    26. In the NOPR, the Commission proposed to move the start of the 
Gas Day from 9:00 a.m. CCT to 4:00 a.m. CCT. The Commission expressed 
concern about the potential impact of the difference in start times of 
the natural gas and electric operating days on the reliable and 
efficient operation of electric transmission system and interstate 
natural gas pipelines. Specifically, the Commission identified two 
problems resulting from the natural gas and electric operating days 
beginning at different times. First, the electric operating day 
currently extends over two Gas Days. Therefore, gas-fired generators 
committed across a single electric operating day must procure gas 
supply and schedule gas transportation across two Gas Days. Second, the 
current 9:00 a.m. CCT start of the Gas Day occurs in the middle of the 
morning electric load ramp in some regions, creating a situation where 
electric load is increasing at the same time natural gas-fired 
generators may be running out of their daily nomination of natural gas 
transportation service.
    27. The Commission proposed to move the start of the Gas Day 
earlier, to 4:00 a.m. CCT, to address concerns expressed by several 
commenters--such as ISO-NE and NYISO--that the current Gas Day start 
time presents operational challenges resulting in gas-fired generators 
running out of scheduled natural gas capacity during the morning 
electric ramp period, and having to wait until 9:00 a.m. CCT before 
being able to rely on their next day gas nomination. The Commission 
stated that this change would mean that generators in all regions would 
be able to approach the morning electric peak, as well as most of the 
morning ramp period, with new daily gas nominations and, therefore, the 
proposal should largely eliminate the concern that some gas-fired 
generators will be unable to run during a substantial part of the 
morning electric ramp period because they have burned through their 
nominated gas before the start of the next Gas Day.

B. NOPR Comments

    28. Thirteen commenters, particularly electric industry 
participants, filed comments in support of the Commission's proposal to 
move the start of the Gas Day to 4:00 a.m. CCT.\36\ These commenters 
argue that, currently, operational problems and logistical challenges 
result from the electric operating day extending over two Gas Days and 
the fact that the current 9:00 a.m. CCT Gas Day splits the morning 
electric load ramp into two Gas Days.\37\ Southern Company explains 
that under the current 9:00 a.m. CCT Gas Day, sharp early morning ramps 
in the winter take place at the end of the Gas Day resulting in gas-
fired generators' hourly gas usage markedly increasing over the last 
eight hours of the Gas Day.\38\ According to Southern Company, because 
of this timing its system operators' option for ensuring sufficient 
fuel to meet the requirements of the morning ramp is limited to holding 
back consumption during the prior evening peak.\39\
---------------------------------------------------------------------------

    \36\ ACES Comments at 7; AECI Comments at 3; Ameren Comments at 
2; Calpine Comments at 10; Con Edison Comments at 5; EquiPower 
Comments at 8; Exelon Comments at 7; First Energy Comments at 3; IRC 
Comments at 2; ISO-NE Comments at 2; NESCOE Comments at 2; PUCO 
Comments at 4; Southern Companies at 6.
    \37\ Calpine Comments at 10-11; Essential Power Comments at 3; 
IRC Comments at 3; ISO-NE Comments at 3-4; PUCO Comments at 4.
    \38\ Southern Company provides as an example a supplier who, on 
January 7 to January 8, 2014 increased gas use on a major pipeline 
from less than 40,000 MMBtu in hour 16 to nearly 50,000 MMBtu in 
hour 23. Southern Company Comments at 7.
    \39\ Southern Company Comments at 7.
---------------------------------------------------------------------------

    29. ISO-NE states that under the current 9:00 a.m. CCT Gas Day, the 
preceding Gas Day ends--with supplies and daily transportation 
quantities from that preceding day potentially running short--just when 
gas-fired generation is critically needed to ensure that electricity 
supply is available to match demand during the morning electric load 
ramp.\40\ IRC states that generators could exhaust gas supply by 
incorrectly anticipating their next day electric schedule, or by 
operating differently in real-time than anticipated when nominating 
day-ahead gas supplies.\41\
---------------------------------------------------------------------------

    \40\ ISO-NE Comments at 3-4.
    \41\ IRC argues that while earlier postings of ISO and RTO day-
ahead market results may help generators know the amount of gas to 
nominate to meet their electric commitments, posting day-ahead 
electric market results earlier does not solve the concern about 
generators nominating gas across two different electric days. IRC 
Comments at 3.
---------------------------------------------------------------------------

    30. Some commenters state that moving the Gas Day to 4:00 a.m. CCT 
or earlier would be helpful to owners of gas-fired resources by 
allowing them to nominate and schedule their fuel and transportation 
requirements in the day-ahead Timely Nomination Cycle--the most liquid 
cycle--to cover the morning electric ramp and the evening peak of a 
single electric day while also being able to make adjustments 
throughout the day in the intraday cycles.\42\ IRC and ISO-NE state 
that planning for and including the entire morning electric ramp in the 
initial Gas Day operating plan is inherently more reliable to serve 
electric load requirements.\43\ ISO-NE states that moving the start of 
the Gas Day earlier should address instances when gas-fired generators 
find they are running out of scheduled natural gas capacity during the 
morning ramp period and have to wait until the 9:00 a.m. CCT start of 
the Gas Day to obtain additional supply or transportation.\44\ 
Equipower and Con Edison state that changing the start of the Gas Day 
will benefit system reliability in that generators exhausting their gas 
supply prior to the end of the Gas Day will do so during the middle of 
the night, when both the gas and electric systems are in a relatively 
low-load, steady-state condition and electric system operators have 
more flexibility to increase output from slow-ramping units, instead of 
during the morning ramping hours.\45\ Southern Company explains that 
with the start of the Gas Day moved to 4:00 a.m. CCT, operators can 
eliminate five hours of significant gas burn from the latter half of 
the preceding Gas Day and shift the steepest part of the morning ramp 
into the beginning of the next Gas Day when operators have the most 
flexibility to address their needs by adjusting gas scheduling and/or 
generation for the remaining hours.\46\ This shift would eliminate the 
current problem of system operators holding back gas consumption during 
the evening peak because of the morning electric ramp.\47\
---------------------------------------------------------------------------

    \42\ ACES Comments at 7; AECI Comments at 3; Ameren Comments at 
5; Calpine Comments at 11-12; IRC Comments at 2; ISO-NE Comments at 
4.
    \43\ IRC Comments at 3; ISO-NE Comments at 5.
    \44\ ISO-NE Comments Brandien Testimony at 4.
    \45\ Equipower Comments at 8-9; Con Edison Comments at 7.
    \46\ Southern Company Comments at 8.
    \47\ Id.
---------------------------------------------------------------------------

    31. ISO-NE states that the current Gas Day start time also 
straddles a time of peak gas demand for other pipeline shippers, such 
as LDCs, which further inhibits the ability to procure gas during the 
morning ramp.\48\ Con Edison asserts that, on the natural gas side, a 
4:00 a.m. CCT start of the Gas Day would avoid virtually all of the 
natural gas ramping

[[Page 23204]]

period. According to Con Edison, this would allow natural gas system 
operators time to respond before loads reach their peak by, for 
example, shifting receipts among gate stations and/or utilizing on-
system storage if there is an event on its system.\49\ Furthermore, Con 
Edison states that forecast deviations should also be reduced if a 4:00 
a.m. CCT start of the Gas Day is approved because it would minimize the 
time between when natural gas is purchased and nominated and when it is 
consumed.\50\
---------------------------------------------------------------------------

    \48\ ISO-NE Comment at 4.
    \49\ Con Edison Comments at 7-8.
    \50\ Id. at 8-9.
---------------------------------------------------------------------------

    32. Thirty-five commenters, particularly natural gas industry 
participants, support the retention of the current 9:00 a.m. CCT Gas 
Day and oppose the Commission's proposal to move the start of the Gas 
Day to 4:00 a.m. CCT.\51\
---------------------------------------------------------------------------

    \51\ AF&PA Comments at 9; AGA Comments at 24; ANGA Comments at 
2; American Public Gas Association Comments at 2; BHE Comments at 3; 
Castex Comments at 5; CenterPoint Energy Comments at 4; CPG Comments 
at 6; DCP Comments at 2; Direct Energy Comments at 2; Dominion 
Comments at 3; DTE Gas Comments at 3; Enhanced Reliability Coalition 
Comments at 5; Gas Processors Association Comments at 1; GRS 
Comments at 2; INGAA Comments at 13; IOGA Comments at 1; IPAA 
Comments at 2; Kinder Morgan Comments at 8; MSGC Comments at 11; 
National Grid Comments at 1; Natural Gas Council Comments at 2; New 
England LDCs Comments at 3; NiSource Comments at 2; NorthWestern 
Energy Comments at 3; Northwest Gas Association et al. at 1; NGSA 
Comments at 4; Northern Municipal Distributors/Midwest Region Gas 
Task Force Comments at 6; NW Industrial Gas Users Comments at 3; 
PG&E Comments at 2; Southwest IS Comments at 4; Southern Star 
Comments at 6; Texas Pipeline Association Comments at 1; WBI Energy 
Comments at 5; XES Comments at 5.
---------------------------------------------------------------------------

    33. INGAA and Direct Energy contend that generator de-rates may 
have a number of causes unrelated to the Gas Day start time such as a 
nomination made based on an estimate of needs or a change in the ISO's 
or RTO's request for generation.\52\ Numerous commenters also argue 
that it is highly uncertain that a 4:00 a.m. CCT Gas Day would increase 
electric reliability and that the speculative benefits of such a change 
appear limited.\53\
---------------------------------------------------------------------------

    \52\ INGAA Comments at 16; Direct Energy Comments at n.10.
    \53\ AGA Comments at 32; BHE Comments at 4; CPG Comments at 8; 
Dominion Comments at 17; Enhanced Reliability Coalition Comments at 
20; Kinder Morgan Comments at 8; MSCG Comments at 11; New England 
LDCs Comments at 16; NGSA Comments at 5; NW Industrial Gas Users 
Comments at 6.
---------------------------------------------------------------------------

    34. Many commenters state that an earlier start to the Gas Day will 
not create additional capacity on pipelines during peak demand 
conditions to meet large swings in generator demand nor will it solve 
critical pipeline capacity availability issues that some regions are 
experiencing, particularly on a long-term basis.\54\ Several commenters 
emphasize that the problems involving gas-electric coordination 
identified in the NOPR exist primarily in New England, are generally 
isolated to a single customer class, and, therefore, urge regional 
changes to be implemented.\55\ Dominion and IPAA state that the NOPR 
appears designed to address the problems identified by the electric 
market participants in the Northeast, but fails to take into account 
concerns in other regions of the country or the concerns of the gas 
industry as a whole.\56\
---------------------------------------------------------------------------

    \54\ BHE Comments at 8; CPG Comments at 8; Enhanced Reliability 
Coalition Comments at 20; INGAA Comments at 28; National Fuel 
Comments at 6; NGSA Comments at 5; NiSource Comments at 8; Southern 
Star Comments at 6; WBI Energy Comments at 7.
    \55\ BHE Comments at 11-12; Dominion Comments at 17; Enhanced 
Reliability Coalition Comments at 10; IPAA Comments at 3; New 
England LDCs Comments at 13; NiSource Comments at 8; WBI Energy 
Comments at 7.
    \56\ Dominion Comments at 24; IPAA Comments at 2-3; MSCG 
Comments at 11-12; NWIGU Comments at 3.
---------------------------------------------------------------------------

    35. Numerous commenters raise concerns regarding the potential for 
adverse impacts on reliability and safety and the danger of increased 
operational risk to the natural gas industry resulting from a 4:00 a.m. 
CCT Gas Day, particularly in the west.\57\ For example, AGA states that 
the vast natural gas infrastructure is, in many instances, unmanned and 
not supported electronically, thus often requiring the dispatch of 
personnel to remote worksites to make the necessary physical changes to 
maintain services and operations.\58\ INGAA and NiSource explain that, 
despite the industry's move toward the use of automated systems such as 
supervisory control and data acquisition (SCADA), there are still 
numerous situations in which a pipeline needs to employ on-site field 
technicians to staff certain types of equipment to ensure safe and 
efficient facility operations and to make any necessary manual 
adjustments.\59\ Commenters argue that changing the start of the Gas 
Day to 4:00 a.m. CCT may create operational and safety risks due to the 
increased need for field work along the gas supply chain during 
nighttime hours, particularly during emergency situations when bad 
weather may exacerbate the effects of darkness.\60\ New England LDCs 
state that while LDCs would take additional precautions to mitigate the 
risk of employees undertaking tasks when it is fully dark, even with 
artificial lighting, the total light available is likely to be less 
than that provided by natural daylight and that electric power is not 
available in many places.\61\
---------------------------------------------------------------------------

    \57\ See e.g., AGA Comments at 29; American Public Gas 
Association Comments at 7 and 9; Castex Comments at 7; CPG Comments 
at 6; Dominion Comments at 22; Enhanced Reliability Coalition 
Comments at 10; Gas Processors Association Comments at 6; GRS 
Comments at 2-3; IPAA Comments at 2; National Grid Comments at 3; 
New England LDCs Comments at 14; Northwest Gas Association et al. 
Comments at 2; NW Industrial Gas Users Comments at 5; PG&E Comments 
at 2; Puget Comments at 8; Southern Star Comments at 6; Texas 
Pipeline Association Comments at 9; WBI Comments at 2.
    \58\ AGA Comments at 31.
    \59\ NiSource Comments at 7.
    \60\ AGA Comments at 29; American Public Gas Association 
Comments at 7; CPG Comments at 7; GRS Comments at 3; INGAA Comments 
at 20; IOGA Comments at 4; National Grid Comments at 4; New England 
LDCs Comments at 4; NiSource Comments at 7; Northwest Gas 
Association et al. at 2; PG&E Comments at 3; Texas Pipeline 
Association Comments at 12.
    \61\ New England LDCs further state it would not be economical 
to provide lighting other than truck lights and flash lights. New 
England LDCs Comments at 21.
---------------------------------------------------------------------------

    36. Numerous commenters argue that a 4:00 a.m. CCT Gas Day would 
result in performing certain critical operations, which require complex 
and risky worker decision making, at a time when many operators may 
suffer from fatigue or lack of concentration.\62\ Commenters state that 
this change would increase the risk of worker error, impaired reaction 
time, situational awareness, judgment, attention, memory and resulting 
accidents and injury to personnel due to fatigue from interrupted sleep 
cycles.\63\ Commenters cite studies identifying serious and substantial 
pipeline safety risks due to human fatigue in the Control Room and 
providing recommendations to avoid critical decision making and 
communication between 2:00 a.m. and 6:00 a.m. local time.\64\
---------------------------------------------------------------------------

    \62\ CenterPoint Comments at 4; Enhanced Reliability Coalition 
Comments at 15; New England LDCs Comments at 4; NiSource Comments at 
6; Northwest Gas Association et al. Comments at 2; PG&E Comments 3-
5; Texas Pipeline Association Comments at 12; WBI Comments at 7.
    \63\ Dominion Comments at 22; INGAA Comments at 26-27; New 
England LDCs Comments at 22; Texas Pipeline Association Comments at 
11-12.
    \64\ AGA Comments at 31-32; Dominion Comments at 22; INGAA 
Comments at 26-27; New England LDCs Comments at 23; PG&E Comments at 
3-4; Puget Comments at 8-9; Texas Pipeline Association Comments at 
11-12.
---------------------------------------------------------------------------

    37. AGA, New England LDCs, and CenterPoint contend that a flurry of 
significant activities occur approximately three hours before or at the 
start of the Gas Day \65\ and that these

[[Page 23205]]

activities would be difficult or costly to do if the Gas Day start time 
were moved to 4:00 a.m. CCT.\66\ Commenters also state that, in 
providing reliable service, pipelines and LDCs are required to make 
manual changes to numerous facilities throughout the country prior to 
the start of every Gas Day to ensure delivery.\67\ National Grid states 
that requiring these changes to occur at 4:00 a.m. CCT would place 
unnecessary operational and financial burdens on LDCs and could 
adversely affect their ability to prepare to meet morning natural gas 
load demands.\68\
---------------------------------------------------------------------------

    \65\ These activities include: Updating weather forecasts, 
forecasting demand from various customer groups (including gas-fired 
generators), forecasting interruptible service requirements, 
verifying volumes from interconnected pipelines, determining 
operational issues and notifications on interconnected pipelines, 
evaluating supply options, evaluating balancing needs, coordinating 
storage injections or withdrawals, planning for intraday gas flow 
changes, evaluating volume balancing needs of the current day, and 
adjusting peaking supply.
    \66\ AGA Comments at 29; CenterPoint at n. 7; New England LDCs 
Comments at 21.
    \67\ AGA states that a survey of LDCs revealed that nineteen out 
of fifty-three LDCs conduct manual operations hourly, and that 
another nineteen LDCs conduct manual operations daily. AGA Comments 
at 29 and 31. PG&E states that it has assessed its daily operations 
and concluded that annually, a minimum of 2,200 manual and 3,500 
automated operating changes will shift to 4:00 a.m. (CCT), and thus 
during the night, rather than during the daylight hours, if the 
start of the Gas Day is changed. PG&E Comments at 3. See also DCP 
Comments at 3; Dominion Comments at 22; Enhanced Reliability 
Coalition Comments at 16; INGAA Comments at 24; National Grid 
Comments at 4; WBI Comments at 6.
    \68\ National Grid Comments at 4.
---------------------------------------------------------------------------

    38. Commenters note that requiring workers to travel in the dark is 
particularly problematic for facilities located in remote areas.\69\ 
Some safety concerns associated with employees on roads in these early 
hours include: Decreased visibility, roads not yet cleared of ice or 
snow, decreased mental alertness of employees and other drivers, and 
increased animal activity on roads.\70\ Thus, NGSA states that 
operational practicalities would create a need to delay field work 
until daylight hours when conditions are more conducive to a safe 
working environment.\71\
---------------------------------------------------------------------------

    \69\ Texas Pipeline Association Comments at 12; CPG Comments at 
7; INGAA Comments at 22; IOGA Comments at 4; WBI Comments at 6; ERC 
Comments at 16; DCP Comments at 3; Texas Pipeline Association 
Comments at 13; NiSource Comments at 10.
    \70\ CPG Comments at 7.
    \71\ NGSA Comments at 12; INGAA Comments at 19.
---------------------------------------------------------------------------

    39. Commenters state that the optimum time for packing the pipeline 
\72\ is when customer demands are low and, therefore, pipelines and 
LDCs with pipeline operations currently use the late night and early 
morning hours to pack their systems in anticipation of the morning 
load.\73\ Commenters state that, particularly in the west, the proposed 
Gas Day change would reduce the number of hours available to pack the 
pipeline, thus jeopardizing the ability of pipeline operators to 
pressurize their systems to meet peak morning natural gas demands.\74\
---------------------------------------------------------------------------

    \72\ Enhanced Reliability Coalition explains that pipelines 
generally accommodate the hourly differences in supply and demand 
through storage and the build-up of system inventory, that is, 
system packing, in which gas is accumulated within the pipeline 
system in order to meet the rapid outflows often needed by 
customers. Enhanced Reliability Coalition Comments at 7.
    \73\ AGA Comments at 30-31; Dominion Comments at 20; Enhanced 
Reliability Coalition Comments at 7-8; Northwest Gas Association 
Comments at 2; PG&E Comments at 6.
    \74\ Dominion Comments at 20; Enhanced Reliability Coalition 
Comments at 8-9; Northwest Gas Association Comments at 2; Puget 
Comments at 6.
---------------------------------------------------------------------------

    40. Some commenters assert that moving the Gas Day earlier will 
also make it more difficult for gas industry participants to coordinate 
necessary activities.\75\ INGAA and NGSA state that, given the number 
of transactions and operational assets involved in addressing issues 
that may arise near the beginning of the Gas Day,\76\ and given the 
unbundled nature of the industry, daily coordination among industry 
participants is required to ensure the uninterrupted delivery of gas to 
those who need it.\77\
---------------------------------------------------------------------------

    \75\ INGAA Comments at 18-19; Natural Gas Council Comments at 9-
10; NGSA Comments at 11-13.
    \76\ For example, (1) there may be mismatches between 
nominations and actual gas receipts or deliveries, (2) gas may not 
come on-line as planned or expected, (3) equipment may malfunction, 
especially in cold weather, (4) not all equipment is automated, (5) 
gas flows may need to be redirected manually from one pipeline to 
another, and (6) maintenance projects may affect gas flows.
    \77\ INGAA Comments at 18-19; Natural Gas Council Comments at 9-
10.
---------------------------------------------------------------------------

    41. NW Industrial Gas Users and New England LDCs argue that their 
regions rely on Canadian supplies and, since Canadian pipelines will 
not necessarily switch their Gas Day start time in response to a 
Commission ruling, mismatches at U.S./Canadian delivery points into 
U.S. pipelines could cause delays and/or interruptions in flows as well 
as operational difficulties for shippers scheduling gas deliveries 
using pipelines in both countries.\78\
---------------------------------------------------------------------------

    \78\ New England LDCs Comments at 23-24; NW Industrial Gas Users 
Comments at 4.
---------------------------------------------------------------------------

    42. Enhanced Reliability Coalition and AF&PA state that if a 4:00 
a.m. CCT Gas Day start is adopted, all of the hours of flow for gas 
nominated in the intraday cycles would be reduced by five hours, 
resulting in approximately a 25 to 45 percent reduction, depending on 
the cycle.\79\ Commenters state that this change would eliminate the 
flexibility that the current intraday service provides and that 
shippers would face even greater difficulty in using intraday 
nomination cycles to adjust to unanticipated changes in demand or other 
unforeseen events that occurred after the Timely or Evening nomination 
cycles.\80\
---------------------------------------------------------------------------

    \79\ AF&PA Comments at 9-10; Enhanced Reliability Coalition 
Comments at 19.
    \80\ AF&PA Comments at 9-10; Enhanced Reliability Coalition 
Comments at 20; MSCG Comments at 12-13.
---------------------------------------------------------------------------

    43. Several commenters state that, under the current 9:00 a.m. CCT 
Gas Day, many pipelines provide an opportunity for shippers to submit 
``clean up'' or ``retro'' nominations in the final hours of the current 
Gas Day in order to balance loads and reduce potential exposure to 
imbalance penalties.\81\ Commenters assert that an unintended 
consequence of moving the Gas Day to 4:00 a.m. CCT is that pipelines 
may not be able to offer these enhanced balancing/clean-up services 
that provide flexibility to shippers, and these services could be more 
difficult for shippers to utilize and manage.\82\ AGA and INGAA state 
that under a 4:00 a.m. CCT Gas Day model, it would be exceedingly 
difficult to replicate this type of business activity, and market 
liquidity, in the 1:00 a.m. CCT timeframe, since key decision-makers 
would not be on duty at that hour.\83\
---------------------------------------------------------------------------

    \81\ AGA Comments at 30; Calpine Comments at 14; CenterPoint 
Comments at n.7, INGAA Comments at 21; Natural Gas Council Comments 
at 10; NiSource Comments at 6-7; Puget Comments at 8; Spectra 
Comments at 4.
    \82\ AGA Comments at 30; Calpine Comments at 15; Enhanced 
Reliability Coalition Comments at 14; INGAA Comments at 21; Natural 
Gas Council Comments at 10; Spectra Comments at 4.
    \83\ AGA Comments at 30; INGAA Comments at 23.
---------------------------------------------------------------------------

    44. Some commenters state that there is a concern that non-
jurisdictional entities may not adjust to a 4:00 a.m. CCT Gas Day and 
that a lack of action, or timely action, by some operators on the 
upstream portion of the natural gas delivery chain could occur for 
various reasons, such as concerns over costs of the change and worker 
safety at night, particularly during inclement weather.\84\ Dominion 
and Enhanced Reliability Coalition assert that if gas suppliers and 
producers do not operate on the same Gas Day as pipelines, then 
pipelines may have difficulty obtaining necessary supplies and will 
need to manage swings with line pack and storage until producers make 
necessary changes, decreasing the pipeline's operating flexibility.\85\ 
Texas Pipeline

[[Page 23206]]

Association, Gas Processors Association, and INGAA state that this 
change would also require the modification and renegotiation of 
numerous non-jurisdictional contracts that specify a 9:00 a.m. CCT Gas 
Day.\86\
---------------------------------------------------------------------------

    \84\ Enhanced Reliability Coalition Comments at 11-12; Gas 
Processors Association Comments at 6-7; MSCG Comments at 12; 
NiSource Comments at 7; NW Industrial Gas Users Comments at 3-4; 
PG&E Comments at 6; Texas Pipeline Association Comments at 9.
    \85\ Dominion Comments at 21; Enhanced Reliability Coalition 
Comments at 12.
    \86\ Texas Pipeline Association Comments at 11; Gas Processors 
Association Comments at 9.
---------------------------------------------------------------------------

    45. CenterPoint Energy, Northern Municipal Distributors/Midwest 
Region Gas Task Force, and New England LDCs assert that a 4:00 a.m. CCT 
Gas Day would negatively impact interruptible customers served by LDCs, 
including electric generation customers.\87\ CenterPoint and Northern 
Municipal Distributors/Midwest Region Gas Task Force contend that 
shifting the Gas Day to 4:00 a.m. CCT would be difficult for these 
interruptible customers because they do not have employees available 
for a third overnight shift to accommodate late changes and would 
therefore have to discontinue use of gas earlier in the day.\88\ 
CenterPoint states that this change may reduce reliability and 
jeopardize service to firm customers which could include electric 
generation customers.\89\
---------------------------------------------------------------------------

    \87\ CenterPoint Comments at 4-5; New England LDCs Comments at 
19; Northern Municipal Distributors/Midwest Region Gas Task Force 
Comments at 11-12.
    \88\ CenterPoint Comments at 4-5; Northern Municipal 
Distributors/Midwest Region Gas Task Force Comments at 11-12.
    \89\ CenterPoint Comments at 4-5.
---------------------------------------------------------------------------

    46. Essential Power urges the Commission to adopt a 12:00 a.m. 
Eastern Prevailing Time (EPT) Gas Day to align with the electric day 
and allow a generator to match its gas purchases and electric operation 
in the dispatch day.\90\ If the Commission ultimately determines that 
an earlier start to the Gas Day is necessary, National Grid recommends 
moving the start to 12:00 a.m. CCT to align with the electricity 
operating day for most electric utilities.\91\ MSCG, however, proposes 
that it would be most practical to implement a uniform operating day 
that requires electric system operators to adapt to the natural gas 
system's commercial practices and therefore, states the uniform day 
should start at a time later than 4:00 a.m. CCT.\92\ AGA, Con Edison, 
Dominion, EPSA, ISO-NE., and National Fuel argue that the Commission 
should not consider other Gas Day start times between 4:00 a.m. and 
9:00 a.m. CCT.\93\
---------------------------------------------------------------------------

    \90\ Essential Power Comments at 4.
    \91\ National Grid Comments at 2.
    \92\ MSCG Comments at 7.
    \93\ AGA Comments at 25-26; Con Edison Comment at 9; Dominion 
Comments at 27-28; EPSA Comments at 8; ISO-NE Comments at 5; 
National Fuel Comments at 3.
---------------------------------------------------------------------------

    47. Gas industry participants cite high cost as a key reason for 
opposing the Gas Day proposal.\94\ A number of commenters discuss the 
information technology and staffing costs associated with the proposal 
including providing overtime compensation, hiring new employees to 
cover the earlier start to the Gas Day, retraining employees, and 
reprogramming SCADA systems.\95\ Commenters provided a range of cost 
estimates for SCADA/IT modifications and staffing requirements, with 
some above $3 million.\96\ Several commenters also discuss the costs of 
mitigating safety issues raised by moving the Gas Day to 4:00 a.m. 
CCT.\97\ Dominion states that approximately $2.5 million will be 
required to modify tariffs and contracts.\98\ MSCG and BHE estimate the 
overall cost of compliance with the NOPR changes, including the changes 
to the Gas Day, will be in the $5 million range for one jurisdictional 
interstate natural gas pipeline, which indicates the cost of compliance 
for all 166 interstate natural gas pipelines would far exceed the $7.5 
million estimated in the NOPR.\99\
---------------------------------------------------------------------------

    \94\ See, e.g., AF&PA Comments at 9-10; AGA Comments at 27-28; 
American Public Gas Association Comments at 14-15; BHE Comments at 4 
& 9-13; Center Point Comments at 4-6; Dominion Comments at 17, 20, 
25-27; DTE Comments at 3; Northern Municipal Distributors/Midwest 
Region Gas Task Force Comments at 6; PG&E Comments at 7-8.
    \95\ AGA Comments at 28; CenterPoint Comments at 4; NiSource 
Comments at 5; NWGA et al. Comments at 2; MSCG Comments at 16-17.
    \96\ See, e.g., Dominion Comments at 26. Dominion states that a 
4:00 a.m. CCT Gas Day will result in an estimated one-time cost of 
$3.8 million for modifications related to their SCADA system, 
electronic bulletin board, and information technology management 
system, and estimated on-going annual costs of $125,000. Dominion 
anticipates hiring one or two additional transportation analysts, 
with annual on-going costs of between $85,000 and $170,000. 
Additionally, Dominion anticipates one-time implementation costs of 
$2.5 million to modify existing tariffs and contracts, and $1.7 
million to reprogram transportation, storage, production, and 
gathering meters.
    \97\ Enhanced Reliability Coalition at 17.
    \98\ Dominion Comments at 26.
    \99\ BHE Comment at 10-11; MSCG Comments at 16-17.
---------------------------------------------------------------------------

    48. Commenters also address the significant costs entities other 
than interstate natural gas pipelines will incur as a result of the 
Proposed Rule.\100\ PG&E states that compliance with the Gas Day 
proposal will result in an estimated one-time implementation cost of 
between $2 and $3 million for the reprogramming of SCADA systems, 
metering devices, and information technology management systems, as 
well as estimated ongoing annual costs of $600,000 for additional 
nighttime field personnel, traders, schedulers, and other staff-related 
costs.\101\ Puget states that aligning their operations with the Gas 
Day proposal would have an estimated one-time implementation cost of 
$300,000 for modifications related to their SCADA system, metering 
devices, and information technology management systems.\102\ Downstream 
gas industry commenters (e.g., LDCs) also caution that interstate 
pipelines will raise rates for pipeline transportation and storage 
services in order to recover the compliance costs of implementing the 
Gas Day proposal.\103\

---------------------------------------------------------------------------

    \100\ AGA Comments at 28; American Public Gas Association 
Comments at 7 and 14; New England LDCs Comments at 21-22; Producer 
Coalition Comments at 6; Puget Comments at 16-17.
    \101\ PG&E Comments at 7-8.
    \102\ Puget Comments at 8.
    \103\ See, e.g., AF&PA Comments at 9; AGA Comments at 28; 
American Public Gas Association Comments at 15; BHE Comments at 11; 
IECA Comments at 5-6; INGAA Comments at 27; New England LDCs 
Comments at 25; MSCG Comments at 17; NiSource Comments at 5.
---------------------------------------------------------------------------

C. Data Request and ISO and RTO Responses

    49. On December 12, 2014, Commission staff requested data, for 2013 
and 2014, from each of the six jurisdictional ISOs and RTOs regarding 
the impact on reliable and efficient operations of natural gas-fired 
generators running out of their daily nomination of natural gas 
transportation service during the morning electric ramp, to the extent 
this occurs.
    50. In its response, CAISO states that it believes gas-fired 
generators in its balancing authority generally do not face problems 
securing sufficient fuel to meet the morning electric ramp under 
existing electric and gas market timelines.\104\ CAISO was not able to 
locate any record of a gas-fired generator de-rating a unit during the 
hours of 3:00 a.m. and 9:00 a.m. CCT due to the generator exhausting 
its daily nomination of natural gas transportation service prior to the 
end of the Gas Day. CAISO states that it does not believe it has 
committed generation out of merit order in anticipation of natural gas-
fired generators running out of their nominated gas transportation at 
the end of the Gas Day.\105\ The data submitted by CAISO indicates that 
in 2013 and 2014 fuel-related gas-fired generator outages and de-rates 
during the morning electric ramp were about as common on average as 
fuel-related de-rates during the other hours of the operating day.\106\
---------------------------------------------------------------------------

    \104\ CAISO Data Response at 7-8.
    \105\ Id. at 6.
    \106\ See Tables 1 and 2 CAISO Data Response at 6. In 2013 and 
2014, 17 percent to 33 percent of fuel related de-rates and outages 
occurred during the hours of 3:00 a.m. and 9:00 a.m.

---------------------------------------------------------------------------

[[Page 23207]]

    51. MISO states that it has not experienced any significant impacts 
caused by generators running out of natural gas during the morning 
ramp.\107\ MISO explains that its data of power plants' actual 
performance and equipment failures does not reflect if fuel-related 
outages were specifically due to generators having exhausted their 
daily nomination of natural gas transportation service prior to the end 
of the Gas Day.\108\ MISO submitted data providing the numbers of 
natural gas-fired units reporting outages and de-rates with a cause 
related to fuel during each month of 2013 and January through September 
2014.\109\ In 2013, there were relatively few fuel-related gas-fired 
generator outages and de-rates. In January and February of 2014, MISO 
experienced far more fuel-related gas-fired generator outages and de-
rates, however, no more than 20 percent of the de-rates occurred during 
the morning ramp period. In addition, MISO states that it has made many 
recent enhancements to improve transparency of fuel-related matters in 
the planning and operating horizons.\110\
---------------------------------------------------------------------------

    \107\ MISO Data Response at 1-3.
    \108\ Id.
    \109\ See Tables MISO Data Response at 2.
    \110\ MISO states that these enhancements and initiatives 
include: (1) Conducting a Generator Winter Fuel Survey for Winter 
2014/2015 to gain more transparency into MISO generators' approaches 
related to fuel procurement practices; (2) creating (in 2014) 
additional generator outage cause codes related to fuel in MISO's 
outage scheduling tool to provide greater operational awareness to 
MISO operators regarding fuel; (3) expanding the coordination field 
trial between MISO planning and operations staff and ANR and NNG 
pipeline staff to other pipelines; (4) a new overhead pipeline 
operations display in the control room; and (5) a new consolidated 
pipeline notice Web page. MISO Data Response at 5.
---------------------------------------------------------------------------

    52. In its response, SPP states that it does not require generators 
to submit information related to their nominated gas transportation, 
therefore, SPP does not have information responsive to the request 
regarding de-rates due to gas-fired generators having exhausted their 
daily nomination of natural gas transportation service prior to the end 
of the Gas Day. SPP further states that it has not committed generation 
out of merit order in anticipation of natural gas-fired generators 
running out of nominated gas transportation.\111\ The data submitted by 
SPP indicates that in 2013 and 2014 fuel related gas-fired generator 
outages and de-rates during the morning electric ramp were about as 
common on average as fuel-related de-rates during the other hours of 
the operating day.\112\
---------------------------------------------------------------------------

    \111\ SPP Data Response at 3.
    \112\ See Tables 1 and 2 SPP January 14, 2015 Comments at 
Attachment No. 1. In 2013 and 2014, 16 percent to 38 percent of fuel 
related de-rates and outages occurred during the hours of 3:00 a.m. 
and 9:00 a.m.
---------------------------------------------------------------------------

    53. ISO-NE., NYISO, and PJM provided supplemental data regarding 
gas-fired generator de-rates in 2013 and 2014 due to issues related to 
fuel limitations/availability. PJM and NYISO requested privileged 
treatment of certain data submitted in response to the data request.
    54. ISO-NE provided, among other data, information on time periods 
when generators reported reductions (i.e., de-rates) due to fuel 
limitations. ISO-NE states that during 2013 and 2014 there were 173 
reported gas-fired generator de-rates due to fuel limitations and 67 of 
those were logged between 3:00 a.m. and 9:00 a.m. CCT. The morning de-
rates affected forty-nine days. To see if generators were de-rating due 
to running out of gas, ISO-NE examined the reductions that ended when 
the new Gas Day began (9:00 a.m. CCT).\113\ In 2013 and 2014, twenty 
gas-fired generator de-rates due to fuel limitations, over 14 days, had 
an identified ending time that coincided with the start of the next Gas 
Day at 9:00 a.m. CCT. While ISO-NE states that it does not know whether 
the de-rates occurred solely due to the exhaustion of natural gas 
pipeline nominations, given the 9:00 a.m. CCT ending time of the de-
rates, ISO-NE believes this is likely the cause. ISO-NE further states 
that the issues related to the availability of gas-fired resources in 
New England are even more critical than the data provided shows and 
that the severity of these issues has been masked because system 
operators are required to take actions that diminish the frequency of 
generation outage impacts due to gas reductions.\114\
---------------------------------------------------------------------------

    \113\ While these data do not show specifically whether the 
generators exceeded their firm gas transportation schedule for the 
day, ISO-NE states that the data suggests that the de-rates likely 
resulted from the exhaustion of natural gas transportation service, 
because the generators were able to come back on line at the start 
of the new Gas Day.
    \114\ ISO-NE Data Response at 1.

                      Table 2--ISO-NE Gas-Fired Generator De-Rates Due to Fuel Limitations
----------------------------------------------------------------------------------------------------------------
                                                                                     De-rates
                                                                 -----------------------------------------------
                                                                                   Morning ramp
                              Year                                                  (3:00 a.m.-    With end time
                                                                       Total      9:00 a.m. CCT)   of 9:00 a.m.
                                                                                                        CCT
----------------------------------------------------------------------------------------------------------------
2013............................................................              97              39               8
2014............................................................              76              28              12
                                                                 -----------------------------------------------
    Total.......................................................             173              67              20
----------------------------------------------------------------------------------------------------------------
Source: ISO-NE Data Response at 2 and Attachment A.

    55. PJM provided a summary of the outage notifications due to lack 
of fuel from natural gas-fired generators in 2013 and 2014 and non-
confidential system conditions on the relevant interstate natural gas 
pipelines and LDCs.\115\ According to PJM's data response, in 2013, 62 
percent of the unique generators that reported lack of fuel outages are 
located behind an LDC.\116\ PJM also reports that 54 percent of the 
generators reporting outages due to lack of fuel in 2014 are located 
behind an LDC. In 2014, 60 percent of the generator-reported lack of 
fuel outages occurred in January. The confidential data provided by PJM 
shows that the vast majority of fuel-related gas-fired generator de-
rates in 2013, and a majority of the fuel-related gas-fired generator 
de-rates in 2014, were caused by a limited number of generating units.
---------------------------------------------------------------------------

    \115\ See Table 3, PJM Data Response at 4. PJM notes that this 
information may not be complete, as this data is not information 
required by PJM. PJM collected these data from publicly available 
information.
    \116\ A gas-fired generator may be limited in its ability to 
receive or take gas in instances when there are constraints on an 
LDC system, regardless of whether the gas-fired generator has 
sufficient remaining nominated quantities of interstate pipeline 
transportation.
---------------------------------------------------------------------------

    56. NYISO states that it identified 13 generators committed in 2013 
and 2014

[[Page 23208]]

via Supplemental Resource Evaluation \117\ on days with de-rates 
greater than 225 MW in any given hour. NYISO states that given the 
times the Supplemental Resource Evaluations occurred, it is not clear 
that any of the Supplemental Resource Evaluations were issued in 
response to a generator de-rating due to having exhausted its daily 
nomination of natural gas transportation service prior to the end of 
the Gas Day. Instead, NYISO states the de-rates were more likely 
related to limitations on natural gas customers' ability to receive or 
take gas, such as Operational Flow Orders (OFO), which require gas 
customers to operate within tight tolerances, or generator specific 
issues that may, or may not, be related to the availability of gas 
supply.\118\
---------------------------------------------------------------------------

    \117\ NYISO Manual 12: Transmission and Dispatching Operations 
Manual Section 5.7.7 states ``SRE shall only be used to address 
resource deficiencies; it shall not be used to reduce costs.''
    \118\ NYISO Data Response at 6.
---------------------------------------------------------------------------

    57. The confidential data submitted by NYISO shows the number of 
gas-fired generator de-rates and the amount of energy reduced generally 
decreased between 3:00 a.m. and 9:00 a.m. CCT. Specifically, over all 
of 2013 and all of 2014, the total (by hour) number of gas-fired 
generator de-rates related to fuel availability fell as the morning 
progressed (between hours ending at 4:00 a.m. CCT and 9:00 a.m. CCT). 
Similarly, over all of 2013 and all of 2014, the total (by hour) amount 
of energy reduced later in the morning was less than the early-morning 
reductions. If fuel related de-rates were caused by exhaustion of 
nominated natural gas transportation capacity, the impact of the de-
rates would likely have been steady or worsening as more generating 
units ran out of gas as the morning progressed towards 9:00 a.m. CCT.
    58. To provide another perspective on the overall impact on 
reliability of the gas-fired generator de-rates during the morning 
ramp, the Commission examined the monthly and hourly average values 
\119\ of resulting energy reductions as a percentage of the available 
operating reserves. Commission staff analysis of the data response 
indicates that, in ISO-NE during 2013 and 2014, the energy reductions 
were minimal relative to the operating reserves available to ISO-NE at 
the time.
---------------------------------------------------------------------------

    \119\ For example, the average of all of the 6:00 a.m. CCT de-
rates in January.

                        Table 3--Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in ISO-NE
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    All 2014     All 2013     Jan 2014     Mar 2014                  Jan 2013     Feb 2013     Mar 2013
              Hour beginning (CCT)                    (%)          (%)          (%)          (%)       Nov 14 (%)      (%)          (%)          (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 a.m...........................................         0.47         0.69         0.14         1.08         2.10         0.00         0.90         1.47
4 a.m...........................................         0.39         0.49         0.14         0.69         2.11         0.00         0.53         0.83
5 a.m...........................................         0.26         0.32         0.07         0.01         2.11         0.02         0.91         0.01
6 a.m...........................................         0.29         0.48         0.17         0.18         2.11         0.16         1.38         0.06
7 a.m...........................................         0.43         0.61         0.57         0.31         2.11         0.42         1.25         0.43
8 a.m...........................................         0.55         0.70         0.57         0.47         2.11         0.61         1.00         0.92
--------------------------------------------------------------------------------------------------------------------------------------------------------

    59. In NYISO, during certain winter months,\120\ Commission staff 
analysis of the data response indicates that the average hourly 
reductions were potentially significant relative to the operating 
reserves available to the NYISO, ranging up to 5.7 percent of reserves. 
For all other months of 2013 and 2014, the average hourly reductions in 
NYISO were less than one percent of the available operating reserves.
---------------------------------------------------------------------------

    \120\ January 2013, December 2013, January 2014, and February 
2014.

    Table 4--Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in NYISO
----------------------------------------------------------------------------------------------------------------
                                      All 2014     All 2013     Jan 2014     Feb 2014     Jan 2013     Dec 2013
        Hour beginning (CT)             (%)          (%)          (%)          (%)          (%)          (%)
----------------------------------------------------------------------------------------------------------------
3:00 a.m..........................          1.6          2.1          3.7          1.9          3.4          6.1
4:00 a.m..........................          1.5          1.9          4.0          1.8          3.2          3.8
5:00 a.m..........................          1.7          2.1          3.8          2.2          3.5          4.9
6:00 a.m..........................          2.2          1.9          4.5          2.3          2.7          2.6
7:00 a.m..........................          3.2          2.0          5.4          2.3          2.7          3.1
8:00 a.m..........................          3.6          2.3          5.7          1.3          3.1          2.9
----------------------------------------------------------------------------------------------------------------

    60. In PJM in the winter months of 2014, Commission staff analysis 
of the data response indicates that the average hourly reductions were 
large relative to the operating reserves available to the ISO at the 
time, ranging from 16.8 percent to 72.3 percent. The average hourly 
reductions in the winter months of 2013 were also significant relative 
to the operating reserves available to PJM, ranging from 5.6 percent to 
10.1 percent.

[[Page 23209]]

                         Table 5--Gas-Fired Generator Reductions (De-Rates) as a Percent of Available Operating Reserves in PJM
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    All 2014     All 2013     Jan 2014     Feb 2014     Mar 2014     Jan 2013     Feb 2013     Mar 2013
              Hour beginning (CCT)                    (%)          (%)          (%)          (%)          (%)          (%)          (%)          (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 a.m...........................................         13.7          5.0         54.7         25.8         17.2          9.3          7.1          5.9
4 a.m...........................................         13.1          5.0         50.5         25.5         16.8          9.5          7.0          5.6
5 a.m...........................................         13.0          4.8         48.9         25.3         17.0          8.7          6.7          5.9
6 a.m...........................................         15.1          5.1         60.6         27.9         19.5          8.9          7.0          6.7
7 a.m...........................................         17.3          5.3         72.3         32.2         21.4         10.1          7.5          6.8
8 a.m...........................................         17.1          5.2         72.1         30.8         21.1          9.7          7.4          6.5
--------------------------------------------------------------------------------------------------------------------------------------------------------

D. Comments on Data Request

    61. American Public Gas Association, New England LDCs, the Enhanced 
Reliability Coalition, and Natural Gas Council filed comments regarding 
the ISOs' and RTOs' data responses. These commenters argue that the 
ISOs' and RTOs' responses clearly confirm that there is not a 
nationwide problem during the morning electric ramp associated with the 
current start time of the Gas Day.\121\ American Public Gas Association 
and Natural Gas Council contend that the data submitted by the ISOs and 
RTOs does not support the thesis that there is a causal link between 
the start of the Gas Day and the reliability of gas-fired 
generators.\122\ The Enhanced Reliability Coalition points out that in 
2014, many of the instances in which generators in PJM indicated an 
outage due to lack of fuel occurred during OFOs issued by pipelines and 
that, in these circumstances, a change to the start of the Gas Day 
would not have remedied the generator outages.\123\ Natural Gas Council 
and New England LDCs state that the ISOs' and RTOs' responses fail to 
provide sufficient record evidence for the Commission to meet its 
burden under section 5 of the NGA that the current 9:00 a.m. CT Gas Day 
start time is no longer just and reasonable, and that a 4:00 a.m. CT 
start of the Gas Day is just and reasonable.\124\
---------------------------------------------------------------------------

    \121\ Natural Gas Council Feb. 2, 2015 Comments at 1-3.
    \122\ American Public Gas Association Feb. 2, 2015 Comments at 
3-4; Natural Gas Council Comments at 2.
    \123\ Enhanced Reliability Coalition Feb. 2, 2015 Comments at 5.
    \124\ Natural Gas Council Feb. 2, 2015 Comments at 8; New 
England LDCs Feb. 2, 2015 Comments at 3.
---------------------------------------------------------------------------

E. Commission Determination

    62. While certain efficiencies in scheduling could be achieved 
through better harmonization of the natural gas and electric operating 
days, the Commission concludes that the current record does not support 
changing the start time of the nationwide natural Gas Day at this time.
    63. In the NOPR, the Commission expressed concern about the 
potential impact of the difference in start times of the natural gas 
and electric operating days on the reliable and efficient operation of 
electric transmission systems and interstate natural gas pipelines. In 
the NOPR, the Commission identified two problems resulting from the 
fact that the natural gas and electric operating days begin at 
different times. First, the electric operating day currently extends 
over two Gas Days. Therefore, natural gas-fired generators committed 
across a single electric operating day must procure gas supply and 
schedule gas transportation across two Gas Days. Second, the current 
9:00 a.m. CCT start of the Gas Day occurs in the middle of the morning 
electric load ramp in some regions, creating a situation where electric 
load is increasing at the same time natural gas-fired generators may be 
running out of their daily nomination of natural gas transportation 
service. We find, based on the comments and data responses, that there 
is limited evidence to support the premise in the NOPR that the current 
start of the Gas Day results in natural gas-fired generators de-rating 
during the morning ramp due to exhausting nominated natural gas 
transportation. As described in comments, gas-fired generator de-rates 
may have a number of causes unrelated to the Gas Day start time, such 
as a nomination made based on only an estimate of needs (especially 
where the generator has not received a dispatch schedule from the 
system operator), an unscheduled change in an ISO's or RTO's real-time 
dispatch, or limitations on shippers' ability to receive or take gas, 
among others.
    64. In addition, evidence in the record provided through the ISO 
and RTO data responses did not provide sufficient support for changing 
the nationwide Gas Day. The responses generally show that, to the 
extent gas-fired generators de-rating during the morning ramp is a 
significant problem, it appears to be isolated to the winter months in 
specific regions.
    65. SPP, MISO, and CAISO all reported no issue with gas-fired 
generator de-rates during the morning ramp. While ISO-NE, PJM, and 
NYISO provided data suggesting that some de-rates during the morning 
ramp are due to fuel-related issues, the data did not show whether 
those de-rates are specifically due to gas-fired generators running out 
of their daily nomination of natural gas transportation service. None 
of the ISOs' or RTOs' outage management systems collect data containing 
the level of detail and specificity to reflect if generator output 
reductions (i.e., de-rates) and outages were specifically due to 
natural gas-fired generators having exhausted their daily nomination of 
natural gas transportation. Rather, the ISOs and RTOs track de-rates 
and outages associated with the broad North American Electric 
Reliability Corporation (NERC) code for fuel-related issues which 
includes several other causes. Therefore, the Commission had to draw 
inferences based on the data submitted in the record.
    66. The Commission concludes that there is limited evidence to 
support the NOPR proposal to change the Gas Day. For example, in ISO-NE 
very few gas-fired generator de-rates due to fuel limitations had an 
ending time that coincided with the start of the next Gas Day at 9:00 
a.m. CCT in 2013 and 2014. In addition, in PJM, a majority of the fuel 
related gas-fired generator de-rates in 2014 and the vast majority of 
fuel-related gas-fired generator de-rates in 2013 were caused by a 
limited number of generating units. The Commission believes any 
conclusions that can be drawn from the PJM data are weakened by the 
idiosyncrasies of these units. Therefore, although gas-fired generator 
de-rates due to fuel limitations appear problematic in certain regions 
during certain times of the year, on balance, the Commission believes 
this does not warrant changing the nationwide Gas Day.
    67. In addition, several commenters in this proceeding provide 
compelling arguments indicating that moving the

[[Page 23210]]

nationwide Gas Day to 4:00 a.m. CCT will result in substantial 
nationwide costs and potential operational and safety impacts for the 
entire natural gas industry, including jurisdictional and non-
jurisdictional entities. The natural gas industry has identified 
significant costs attendant on such a change, including the costs of 
hiring and retraining employees, providing overtime compensation, 
mitigating safety risks, modifying existing contracts, purchasing new 
equipment, and reprogramming SCADA systems, nomination software, and 
metering devices. The identified adverse operational and safety impacts 
include a potential for reduced nighttime hours to pack the pipeline, 
diminished opportunity for shippers to balance loads in the final hours 
of the Gas Day, increased need for field work during nighttime hours, 
and worker fatigue, among others.
    68. Therefore, we find, based on the record, that there has not 
been a showing that the benefits of changing the nationwide Gas Day 
from 9:00 a.m. CCT to 4:00 a.m. CCT sufficiently outweigh the potential 
adverse operational and safety impacts on the natural gas industry to 
justify action under NGA section 5 to require a change in the start of 
the Gas Day.
    69. While the Commission declines to take action in this proceeding 
to change the start of the Gas Day on a nation-wide basis, we note that 
since the issuance of the NOPR in March 2014 both ISO-NE and PJM (the 
two regions that appear to be of the most concern) have recently 
undertaken operational and market actions to address the availability 
and performance of generators, included gas-fired generators, in their 
footprints.\125\ Beyond these measures, ISO-NE argues that the New 
England region needs its generating resources and other entities to 
make investments in firm fuel supplies and transportation, maintenance 
of on-site fuel inventory, and dual fuel capability.\126\ ISO-NE states 
that it is implementing the Pay-for-Performance proposal accepted by 
the Commission to provide incentives for these investments.\127\ 
Similarly, PJM is focusing on long-term procedural improvements in a 
recent Commission filing proposing a series of tariff reforms to ensure 
that resources committed as capacity to meet PJM's reliability needs 
are obligated to deliver energy and reserves when called upon.\128\ 
These and other regional efforts to address generator performance may 
result in natural gas-fired generators and other market participants in 
these regions taking actions to alleviate some of the electric industry 
fuel supply concerns underlying the Gas Day proposal in the NOPR.\129\ 
In addition, the Commission is taking a range of actions in this Final 
Rule, as discussed below, to better coordinate the scheduling of the 
natural gas and wholesale electricity markets as well as to provide 
additional scheduling flexibility to all shippers on interstate natural 
gas pipelines.
---------------------------------------------------------------------------

    \125\ In ISO-NE these measures include changes to the ISO tariff 
to: (1) Allow for better information sharing with the interstate 
pipelines; (2) enhance offer flexibility; (3) accelerate the 
timelines in the Day-Ahead Energy Market; (4) increase the amount of 
reserves procured in the Forward Reserve Market; (5) enhance Forward 
Reserve Market incentives; (6) improve generator auditing; and (7) 
redefine Shortage Events in the Forward Capacity Market.
    Since January 2014 PJM has put into place a number of 
improvements to help ensure generator availability this winter 
including: (1) A process for generators to communicate any long-lead 
notification time they require to start in order to ensure fuel 
procurement; (2) a requirement for generators to ensure data 
accuracy for existing information provided to PJM; (3) a requirement 
for operational information to be submitted to PJM regarding dual 
fuel capability, availability, and operational restrictions; and (4) 
ability for generators, in certain circumstances, to update intraday 
cost schedules to more accurately reflect real-time the cost of fuel 
in their energy schedules.
    \126\ ISO-NE Data Response at 7.
    \127\ ISO New England Inc. and New England Power Pool, 147 FERC 
] 61,172, order on compliance filing, 149 FERC ] 61,009 (2014).
    \128\ On March 31, 2015 Commission staff requested additional 
information from PJM regarding PJM's proposal in Docket No. ER15-
623-000.
    \129\ In addition, the Commission recently issued an order 
directing each RTO and ISO to file reports on the status of its 
efforts to address fuel assurance issues. The Commission is 
currently reviewing the RTO and ISO reports and the comments 
submitted on those reports. Centralized Capacity Markets in Regional 
Transmission Organizations and Independent System Operators and 
Winter 2013-2014 Operations and Market Performance in Regional 
Transmission Organizations and Independent System Operators, order 
on technical conferences, 149 FERC ] 61,145 (2014).
---------------------------------------------------------------------------

    70. In addition to these ongoing efforts, the individual ISO and 
RTO section 206 proceedings provide additional opportunities to seek 
regional solutions. As discussed further below, the 206 Order requires 
each ISO and RTO to adjust the time at which the results of its day-
ahead energy market and reliability unit commitment process (or 
equivalent) are posted to a time that is sufficiently in advance of the 
Timely and Evening Nomination Cycles, respectively, to allow gas-fired 
generators to procure natural gas supply and pipeline transportation 
capacity to serve their obligations, or show cause why such changes are 
not necessary. In the Section 206 Order the Commission encouraged each 
ISO and RTO to consider whether other market reforms would be 
appropriate.\130\ Such regional electric market changes to diminish the 
misalignment between the Gas Day and regional electric days may be less 
costly and result in far less negative operational impacts.
---------------------------------------------------------------------------

    \130\ For example, RTOs and ISOs could consider the potential 
benefits, cost, and operational burdens of adjusting the timing of 
their operating day. Section 206 Order, 146 FERC ] 61,202 at P 19 & 
n.14 (``In addition, we encourage RTOs and ISOs to consider whether 
other market reforms would be appropriate.'').
---------------------------------------------------------------------------

IV. Natural Gas Transportation Nomination Timeline

A. Background

    71. In addition to the industries having different start times to 
their operating days, the natural gas and electric industries operate 
on different schedules within those days. As described above, and as 
shown in Table 1 above, under the current NAESB WGQ Standard 1.3.2 and 
the Commission's regulations,\131\ natural gas pipelines must offer 
pipeline shippers a minimum of four nomination opportunities to 
schedule natural gas transportation. Shippers have two nomination 
opportunities prior to the day of gas flow, the Timely Nomination Cycle 
and the Evening Nomination Cycle, and two nomination opportunities on 
the day of gas flow (Intraday 1 and Intraday 2). Changes to a shipper's 
nominations are limited by the remainder of a shipper's daily quantity 
and the remaining hours of the Gas Day.\132\
---------------------------------------------------------------------------

    \131\ 18 CFR 284.12 (2014).
    \132\ For example, if a shipper with a contract for 2,400 Dth/
day, schedules 1,200 Dth at the Timely Nomination Cycle, and submits 
an intraday nomination at the Intra-Day 1 Cycle, that shipper can 
increase its scheduled capacity, assuming capacity availability, by 
no more than 1,600 Dth, bringing its total scheduled quantity to 
2,000 Dth/day. This occurs because the shipper has already operated 
for eight hours based on a daily nomination of 1,200 Dth (50 Dth/
hour). (8 hrs * 50 = 400 Dth). This leaves the shipper only 16 hours 
to increase its flow rate to 100 Dth/hr, bringing its total daily 
quantity to 2,000 Dth (400 Dth for the first 8 hours + 1,600 for the 
remaining 16 hours).
---------------------------------------------------------------------------

    72. Interstate natural gas pipelines schedule their systems based 
on the priority of the transportation contract held by the shipper. 
Nominations of firm transportation from a primary receipt point to a 
primary delivery point (primary firm nominations) have the highest 
priority,\133\ followed by secondary firm, within-the-path \134\

[[Page 23211]]

nominations, secondary firm, outside of the path nominations, and 
finally nominations from shippers holding interruptible transportation 
capacity. Before a pipeline schedules a shipper's requested quantity 
under these standards, the pipeline confirms the shipper's nomination 
with upstream and downstream entities to make sure the shipper has 
contracted for sufficient gas with an upstream supplier to fulfill its 
nomination and to ensure the downstream entity, such as a LDC, has 
sufficient capacity to accept that gas.
---------------------------------------------------------------------------

    \133\ A firm shipper's primary receipt and delivery points are 
listed in its service agreement and define the guaranteed firm 
transportation service the pipeline has contracted to provide that 
shipper. The Commission also requires pipelines to permit shippers 
to use all other points in the rate zones for which they pay on a 
secondary firm basis.
    \134\ Secondary firm nominations are firm nominations that 
include at least one secondary point. Within-the-path nominations 
are nominations where the nominated secondary receipt and/or 
delivery point is contained wholly within the primary points listed 
in the shipper's contract.
---------------------------------------------------------------------------

    73. The Timely Nomination Cycle is the most liquid time to acquire 
both natural gas supply and transportation capacity. During the Timely 
Nomination Cycle, all of the pipeline's nomination priorities are in 
effect: Primary firm nominations have priority over secondary firm 
nominations, and secondary firm nominations have priority over 
interruptible transportation. In subsequent nomination cycles, firm 
service, including secondary firm service, scheduled in an earlier 
cycle cannot be displaced or bumped by another firm nomination for that 
Gas Day.\135\ In addition, firm intraday nominations, including 
secondary firm nominations, have priority over, and thus can displace 
or bump, scheduled and flowing interruptible transportation.\136\ This 
policy recognizes that ``firm shippers are paying reservation charges 
for priority rights and those rights should include the right to have a 
nomination become effective as early as possible on the Gas Day 
following the nomination.'' \137\ However, the final intraday 
nomination (Intraday 2) cycle is a ``no-bump'' cycle, meaning that 
interruptible transportation previously arranged for cannot be 
displaced or bumped by a firm Intraday 2 nomination. In approving this 
arrangement (referred to as the ``No-Bump Rule''), the Commission found 
that it would create a fair balance between firm and interruptible 
shippers and provide necessary stability in the nomination system.
---------------------------------------------------------------------------

    \135\ Transwestern Pipeline Company, 99 FERC ] 61,356, at P 12 
(2002) (``the Commission's long standing policy on firm service is 
that once scheduled, whether at primary or alternate points, the 
service may not be bumped by a nomination by another firm 
shipper'').
    \136\ 18 CFR 284.12(b)(1)(i) (2014); Standards for Business 
Practices of Interstate Natural Gas Pipelines, Order No. 587-G, 63 
FR 20072 (Apr. 16, 1998), FERC Stats. & Regs., Regulations Preamble 
1996-2000 ] 31,062, at 30,672 (1998).
    \137\ Id. at 30,671.
---------------------------------------------------------------------------

    74. Individual pipelines may offer additional scheduling 
opportunities beyond the standard nomination cycles. However, shippers 
transporting gas over multiple pipeline systems may have limited 
ability to use these additional scheduling opportunities if the 
upstream or downstream pipelines cannot confirm those scheduling 
changes. Currently, several pipelines offer enhanced nomination 
services \138\ and some pipelines permit more frequent nominations than 
the four required by the current NAESB standards. Even if additional 
nomination cycles are not detailed in the pipeline's tariff, some 
pipelines' tariffs provide that the pipeline will make best efforts to 
accommodate such incremental nominations throughout the day on a best 
efforts basis.\139\
---------------------------------------------------------------------------

    \138\ See, e.g., Texas Gas, 137 FERC ] 61,093, order on 
compliance, 138 FERC ] 61,176; Gulf South, 141 FERC ] 61,262.
    \139\ See, e.g., Tennessee Gas Pipeline Company, LLC's Tariff, 
GT&C Section IV.2(e).
---------------------------------------------------------------------------

B. Natural Gas Transportation Day-Ahead Cycles

    75. The most liquid time to acquire natural gas supply for the next 
day occurs before the 11:30 a.m. CCT deadline for submitting 
nominations in the Timely Nomination Cycle. As a result, natural gas 
purchasers may have to pay a premium to obtain supply after the Timely 
Nomination Cycle, because there are fewer willing sellers later in the 
day. Also, it may be more difficult to obtain next-day firm 
transportation capacity after the Timely Nomination Cycle, because firm 
transactions scheduled in the Timely Nomination Cycle cannot be bumped 
in later nomination cycles and shippers may have already made capacity 
release arrangements for the next day.\140\ After the Timely Nomination 
Cycle, the Evening Nomination Cycle, beginning at 6:00 p.m. CCT, offers 
the only standard opportunity to reschedule gas transportation for the 
next Gas Day.
---------------------------------------------------------------------------

    \140\ The Commission's current capacity release program allows a 
firm shipper to sell (or release) its capacity to another entity 
when it is not using it. The releasing shipper releases its capacity 
by returning its capacity to the pipeline for reassignment to the 
replacement shipper. The pipeline contracts with, and receives 
payment from, the replacement shipper and then issues a credit to 
the releasing shipper. The results of all releases are posted by the 
pipeline on its Internet Web site and made available through 
standardized, downloadable files.
---------------------------------------------------------------------------

    76. Wholesale electricity markets operated by the ISOs and RTOs 
also use a day-ahead energy market to set contractual commitments for 
the next operating day. Market participants place day-ahead offers and 
bids to sell and purchase, and these participants must make such 
commitments prior to the close of the market. If the market clearing 
process accepts these commitments, they become binding for the 
following day. The following table shows for each ISO and RTO the 
deadline for submission of generator bids and the time the winning bids 
are posted by ISOs and RTOs in the day-ahead markets. As demonstrated 
by Table 6, all ISOs and RTOs (with the exception of NYISO) publicize 
accepted day-ahead dispatch bids after the current 11:30 a.m. CCT 
nomination deadline for the Timely Nomination Cycle.

       Table 6--Electric Commitment Results Publication Timetable
------------------------------------------------------------------------
                                                           Time for
                                       Time for       publication of day-
            ISO/RTO               submission of bids   ahead commitment
                                        (CCT)             bids (CCT)
------------------------------------------------------------------------
California Independent System    12:00 p.m..........  3:00 p.m.
 Operator Corporation (CAISO).
ISO New England Inc. (ISO-NE)..  9:00 a.m...........  12:30 p.m.
PJM Interconnection, LLC (PJM).  11:00 a.m..........  3:00 p.m.
Midcontinent Independent System  10:00 a.m..........  2:00 p.m.
 Operator, Inc. (MISO).
New York Independent System      4:00 a.m...........  10:00 a.m.
 Operator, Inc. (NYISO).
Southwest Power Pool, Inc.       11:00 a.m..........  4:00 p.m.
 (SPP).
------------------------------------------------------------------------

[[Page 23212]]

    77. Because day-ahead electric generation commitments generally 
occur after the natural gas transportation Timely Nomination Cycle, a 
natural gas-fired generator must either submit its nomination for 
natural gas transportation services before it knows when and how much 
electricity it will be committed to produce the next day, or it must 
wait until it receives its day-ahead commitment to nominate natural gas 
transportation services, with the risk that during some periods natural 
gas supply and transportation capacity may not be available or 
economical, given the ISO and RTO day-ahead market clearing price.\141\ 
If a gas-fired generator acquires natural gas and transportation prior 
to learning whether it is dispatched, it runs the risk of having to 
sell off excess natural gas supply and pipeline transportation capacity 
during the less liquid Evening or intraday Nomination Cycles to the 
extent its bid does not clear the day-ahead market.\142\ If the gas-
fired generator waits to acquire natural gas supply and transportation 
until its bid clears the day-ahead market, it would be doing so during 
the less liquid Evening or intraday Nomination Cycles, where the 
generator may be unable to acquire transportation capacity if the 
pipeline is fully scheduled. While during many periods of the year, 
gas-fired generators may be able to obtain natural gas and interstate 
natural gas capacity throughout the day, their ability to procure 
natural gas and transportation in the most liquid Timely Nomination 
Cycle may be critical to their ability to provide service during 
periods when the pipeline is constrained.
---------------------------------------------------------------------------

    \141\ A natural gas-fired generator also faces different risks 
depending on whether it enters into long-term natural gas purchase 
arrangements or relies on short-term spot market natural gas 
purchases.
    \142\ See, e.g., Equipower Resources Corp. Comments, Docket No. 
AD12-12-000, at 3-4 (filed Mar. 30, 2012) (a generator that 
purchases capacity and gas during the timely cycle and is not 
dispatched ``is forced to sell excess volumes or purchase the volume 
it is short in the intraday market. But the intraday market is 
highly illiquid and sometimes nonexistent, resulting in the 
generator: (1) Being exposed to imbalance penalties on the pipeline 
if it cannot find a market for excess gas; (2) being unable to 
operate its generator at expected output; (3) having to purchase 
additional supplies at a premium; or (4) having to sell excess 
supply at a discount'').
---------------------------------------------------------------------------

1. NOPR Proposal
    78. The NOPR proposed to move the deadline for submitting 
nominations in the Timely Nomination Cycle from 11:30 a.m. CCT to 1:00 
p.m. CCT to provide sufficient time for electric utilities to complete 
their processes for selecting day-ahead generating resources before the 
Timely Nomination Cycle. The NOPR did not propose any other changes to 
the Timely Nomination Cycle, including the existing 4:30 p.m. CCT 
deadline for the pipeline to provide notice of scheduled quantities. 
Thus, the NOPR proposed to shorten the time required to complete the 
Timely Nomination Cycle from five hours (11:30 a.m. CCT to 4:30 p.m. 
CCT) to three and one-half hours (1:00 p.m. CCT to 4:30 p.m. CCT). The 
NOPR did not propose any changes to the existing Evening Nomination 
Cycle, under which nominations must be submitted by 6:00 p.m. CCT, 
confirmations are completed by 9:00 p.m. CCT, and the pipeline notifies 
shippers of their scheduled quantities by 10:00 p.m. CCT.
    79. In an order issued contemporaneously with the NOPR, the 
Commission instituted a proceeding under section 206 of the FPA 
requiring each ISO and RTO within ninety days after the publication of 
a Final Rule in this docket to: (1) Make a filing that proposes tariff 
changes to adjust the time at which the results of its day-ahead energy 
market and reliability unit commitment process (or equivalent) are 
posted to a time that is sufficiently in advance of the Timely and 
Evening Nomination Cycles, respectively, to allow gas-fired generators 
to procure natural gas supply and pipeline transportation capacity to 
serve their obligations; or (2) show cause why such changes are not 
necessary.\143\
---------------------------------------------------------------------------

    \143\ Section 206 Order, 146 FERC ] 61,202.
---------------------------------------------------------------------------

    80. The NOPR proposed that moving the Timely Nomination Cycle to 
1:00 p.m. CCT, along with examining whether the ISOs and RTOs should 
modify their day-ahead market processes, could expand the options 
available to gas-fired generators. Under the NOPR proposal, gas-fired 
generators would have the option of arranging natural gas supply and 
pipeline transportation at the Timely Nomination Cycle knowing the 
results of the day-ahead electric market. This could minimize 
situations in which gas-fired generators, particularly those that opt 
to procure natural gas supply and pipeline transportation after the 
day-ahead electric market results are posted, are unable to procure 
sufficient resources to fulfill their electric market commitments and 
to contribute to reliable electric system operation. If gas-fired 
generators know whether they were committed in the day-ahead electric 
market prior to the Timely Nomination Cycle, they may have a greater 
opportunity to procure natural gas transportation in the Timely 
Nomination Cycle--when there is the greatest opportunity to procure 
pipeline capacity. This, in turn, could reduce the potential for gas-
fired generators to engage in costly actions that raise real-time 
electric market prices. Thus, electric market outcomes may better 
reflect expected operating costs if gas-fired generators were provided 
with day-ahead market results prior to the Timely Nomination Cycle.
    81. It was recognized in the NOPR that moving the Timely Nomination 
Cycle to later in the day may impose systems and administrative costs 
on other interstate natural gas pipeline shippers. However, the NOPR 
concluded a 1:00 p.m. CCT start time for the Timely Nomination Cycle 
would appear to provide a reasonable balance of the electric and 
natural gas industries' concerns. The NOPR concluded that the long-term 
benefits of ensuring a better coordinated natural gas and electric 
industry appear to warrant this change.
2. Revised NAESB Day-Ahead Nomination Cycles
    82. Consistent with the NOPR, NAESB revised its standards to move 
the start of the Timely Nomination Cycle to 1:00 p.m. CCT, with 
scheduled quantities becoming effective at the start of the next Gas 
Day. However, unlike the NOPR, NAESB revised its standards to move the 
deadline for the pipeline to notify shippers of their scheduled 
quantities from 4:30 p.m. CCT to 5:00 p.m. CCT, stating the pipelines 
require at least four hours to complete the Timely Nomination Cycle.
    83. While the NOPR did not propose any changes to the Evening 
Nomination Cycle, NAESB revised its standards to provide that that 
cycle be completed in three hours, rather than the current four hours, 
with shippers being notified of their scheduled quantities at 9:00 p.m. 
instead of 10:00 p.m. Under both the NOPR and NAESB's revised 
standards, bumping of interruptible service is permitted in the Evening 
Nomination Cycle and, consistent with current Commission policy, 
already scheduled secondary firm service cannot be bumped. A comparison 
of the current NAESB day-ahead nomination cycles and the revised NAESB 
day-ahead nomination cycles are shown in Table 7 below.

[[Page 23213]]

                  Table 7--Day-Ahead Nomination Cycles
------------------------------------------------------------------------
                                  Current NAESB         Revised NAESB
 Time Shifts--all times CCT         standards             standards
------------------------------------------------------------------------
Timely:
    Nomination Deadline.....  11:30 a.m...........  1:00 p.m.
    Schedule Issued.........  4:30 p.m............  5:00 p.m.
    Start of Gas Flow.......  9:00 a.m............
Evening:
    Nomination Deadline.....  6:00 p.m............  6:00 p.m.
    Schedule Issued.........  10:00 p.m...........  9:00 p.m.
    Start of Gas Flow.......  9:00 a.m............
------------------------------------------------------------------------

3. NOPR Comments
    84. The large majority of commenters support moving the start time 
for the Timely Nomination Cycle from 11:30 a.m. CCT to 1:00 p.m. CCT, 
including commenters that do not generally support NAESB's intraday 
nomination timeline.\144\ Many of the commenters that support NAESB's 
nomination timeline state that, consistent with the Commission's 
proposal, moving the Timely Nomination Cycle nomination deadline to 
1:00 p.m. CCT will provide generators more time to acquire natural gas 
supply and pipeline transportation after learning their electric 
dispatch obligations, provided changes are made to the ISO and RTO 
scheduling processes.\145\ Several commenters state that moving the 
Timely Nomination Cycle deadline later will also reduce costs and 
improve efficiency among gas-fired generation units.\146\
---------------------------------------------------------------------------

    \144\ AGA Comments at 22; Ameren Comments at 1; ANGA Comments at 
3; BHE Comments at 16-17; Calpine Comments at 7; Castex (Producer 
Coalition) Comments at 7; CenterPoint Comments 3-4; Con Edison 
Companies Comments at 9; CPG Comments at 5; Direct Energy Comments 
at 2; Dominion Comments at 3; DTE Gas Comments at 3; Duke Energy 
Comments at 3; EDF et al. Comments at 7-8; Enhanced Reliability 
Coalition Comments at 29; EPSA Comments at 7; Equipower Comments at 
9; ESI Comments at 3-4; Exelon Comments at 6; Gas Processors 
Association Comments at 1-2; INGAA Comments at 5; IOGA Comments at 
5; IPPA Comments at 2; IRC Comments at 3; Kinder Morgan Comments at 
6; National Fuel Distribution at 2-3; National Grid Comments at 1-2; 
Natural Gas Council Comments at 1-2; New England LDCs Comments at 
30; NGSA Comments at 1-2; Nisource Comments at 2; Northwest Gas 
Association Comments at 2-3; Northwest Industrial Gas Users Comments 
at 5-6; PGC Comments at 4; PUCO Comments at 6-8; Puget Comments at 
10; Sequent Comments at 6; Southern Companies Comments at 11; 
Southern Star Comments at 3; Spectra Comments at 4; Texas Pipeline 
Association Comments at 9; TVA Comments at 2; WBI Energy Comments at 
4.
    \145\ See, e.g., Calpine Comments at 8; CPG Comments at 6; Duke 
Energy Comments at 2-4; EquiPower Comments at 9; INGAA Comments at 
5; National Grid Comments 1-2; New England LDCs Comments at 31; 
NESCOE Comments at 4-5; PGC Comments at 4-5; PUCO Comments at 5-6.
    \146\ See, e.g., EDF et al. Comments at 7-8; PUCO Comments at 5-
6.
---------------------------------------------------------------------------

    85. A few commenters support moving the Timely Nomination Cycle, 
but believe that the 1:00 p.m. nomination deadline is too early in the 
day. Xcel Energy and SPP believe that the start time for the Timely 
Nomination Cycle should be extended to 1:30 p.m. CCT and 2:00 p.m. CCT, 
respectively, arguing that a 1:00 p.m. CCT nomination deadline would 
not allow power generators in MISO's and SPP's market sufficient time 
to secure the gas necessary to support their bids.\147\ Similarly, 
Puget states that ISO and RTO bids will need to be awarded at least 1.5 
hours prior to the NAESB Timely Nomination Cycle nomination deadline to 
allow energy schedulers adequate time to confirm transactions, exchange 
contracts, and enter nominations on pipelines.\148\
---------------------------------------------------------------------------

    \147\ SPP Comments at 2-3; Xcel Energy Comments at 3-5.
    \148\ Puget Comments at 13.
---------------------------------------------------------------------------

    86. MSCG does not support moving the Timely Nomination Cycle 
nomination deadline, arguing that the proposed change affects one 
hundred percent of the gas market while only benefitting about a third 
of energy markets and without providing additional liquidity in the 
market for natural gas.\149\
---------------------------------------------------------------------------

    \149\ MSCG Comments at 15-16.
---------------------------------------------------------------------------

4. Commission Determination
    87. The Commission is amending its regulations at Part 284 to 
incorporate by reference NAESB's revised standards, which provide that 
the nomination deadline for the Timely Nomination Cycle shall be 1:00 
p.m. CCT, with notice to shippers of scheduled quantities at 5:00 p.m. 
CCT, and the nomination deadline for the Evening Nomination Cycle shall 
remain at 6:00 p.m. CCT, with notice to shippers of scheduled 
quantities at 9:00 p.m. CCT. These changes, along with being generally 
consistent with the NOPR's proposed 1:00 p.m. CCT start time for the 
Timely Nomination Cycle, are supported by the vast majority of the 
commenters, from both the gas and electric industries, including 
commenters that do not generally support NAESB's revised intraday 
nomination timeline. NAESB's revised 1:00 p.m. CCT start time for the 
Timely Nomination Cycle, like the NOPR's proposed 1:00 p.m. CCT start 
time, will provide generators more time to acquire natural gas supply 
and pipeline transportation after learning their electric dispatch 
obligations, provided changes are made to the ISO and RTO scheduling 
processes. NAESB's proposal to provide notice of scheduled quantities 
at 5:00 p.m. also enables gas industry participants to complete the 
Timely Nomination Cycle by the end of the business day, while still 
providing sufficient time for the nomination, confirmation and 
scheduling process.
    88. The Commission declines to extend the deadline for submitting 
nominations in the Timely Nomination Cycle past 1:00 p.m. CCT, as 
requested by a few commenters. Such an extension would likely require 
corresponding changes in the remainder of the Timely Nomination Cycle 
process, including moving back NAESB's proposed 5:00 p.m. CCT deadline 
for posting scheduled quantities. However, as many commenters point 
out, there needs to be sufficient time between the scheduled quantity 
posting of one cycle and the nomination deadline for the next cycle to 
enable shippers to review their transportation needs prior to the next 
nomination deadline.\150\ Further extending the Timely Nomination Cycle 
nomination deadline would reduce or do away completely with the time 
between when the Timely Nomination Cycle schedule is issued and the 
6:00 p.m. deadline for submitting nominations in the Evening Nomination 
Cycle. Also, commenters in the natural gas industry contend that the 
further the Timely Nomination Cycle process falls outside of regular 
business hours, the more likely it is that producers, point operators, 
and shippers will be harder to reach to resolve nomination,

[[Page 23214]]

confirmation and scheduling errors.\151\ Given the support for the 
revised NAESB schedule and the problems created in moving the time any 
later, the concerns of the commenters with the coordination of the 
current scheduling processes of MISO and SPP relative to natural gas 
scheduling are best addressed in the section 206 proceedings the 
Commission instituted for each ISO and RTO.
---------------------------------------------------------------------------

    \150\ See, e.g., Exelon Comments at 7; NGSA Comments at 16.
    \151\ See, e.g., INGAA Comments at 8.
---------------------------------------------------------------------------

C. Intraday Nomination Cycles

    89. In addition to the Timely and Evening Nomination Cycles, 
pipelines currently must offer shippers at least two opportunities to 
nominate natural gas during the day that gas is flowing. These 
nomination opportunities are known as the Intraday 1 and Intraday 2 
Nomination Cycles. The current Intraday 1 Nomination Cycle begins at 
10:00 a.m. CCT on the day of gas flow, with pipelines issuing scheduled 
quantities at 2:00 p.m. CCT, and the start of gas flow at 5:00 p.m. 
CCT. The current Intraday 2 Nomination Cycle begins at 5:00 p.m. CCT on 
the day of gas flow, with pipelines issuing scheduled quantities at 
9:00 p.m. CCT, and gas flow also starting at 9:00 p.m. CCT. As with 
nominations made at the Timely or Evening Nomination Cycles, 
nominations for firm service at the Intra-Day 1 Nomination Cycle can 
``bump'' an already scheduled interruptible nomination. Pursuant to the 
``No-Bump Rule,'' however, nominations for firm service made at the 
Intraday 2 cycle cannot ``bump'' previously scheduled interruptible 
service.
    90. A number of commenters in response to the technical conferences 
in Docket No. AD12-12-000 stated that the standard, nation-wide 
nomination opportunities currently available may not provide gas-fired 
generators or other shippers with sufficient flexibility to adjust 
their nominations to respond to real-time changes in their need for 
natural gas.\152\ These commenters requested that the Commission 
require additional, standardized intraday nomination opportunities on 
interstate natural gas pipelines. Pipelines and other gas market 
participants indicated that they were open to the creation of the 
additional standard nomination cycles.\153\
---------------------------------------------------------------------------

    \152\ NOPR, 146 FERC ] 61,201 at P 57.
    \153\ Id. P 62.
---------------------------------------------------------------------------

1. NOPR Proposal
    91. To address concerns that the current standard, nation-wide 
intraday nomination opportunities do not provide shippers--especially 
natural gas-fired generators--with sufficient flexibility, the NOPR 
proposed to modify the current natural gas nomination timeline to add 
two additional intraday nomination cycles so that shippers would have 
four intraday cycles to reschedule gas instead of the existing two. The 
additional intraday nomination cycles would maximize shippers' ability 
to make significant changes in their intraday nominations, as well as 
provide firm shippers an additional, bumpable late-afternoon nomination 
cycle. The proposed revisions would provide gas-fired generators, as 
well as other pipeline customers, with greater flexibility to revise 
their nominations to adjust to system conditions and changes to load 
throughout the Gas Day.
    92. The timelines proposed in the NOPR were based on the proposed 
adoption of 4:00 a.m. CCT as the start of the Gas Day. The NOPR 
proposed that the Intraday 1 Nomination Cycle begin at 8:00 a.m. CCT, 
with pipelines issuing scheduled quantities at 11:00 a.m. CCT, and gas 
flow beginning at 12:00 noon CCT. The Intraday 1 Nomination Cycle would 
provide an early morning opportunity for shippers to nominate gas. The 
NOPR proposed that the Intraday 2 Nomination Cycle begin at 10:30 a.m. 
CCT, with pipelines issuing scheduled quantities at 2:00 p.m. CCT, and 
gas flow beginning at 4:00 p.m. CCT. The NOPR proposed Intraday 2 cycle 
would replace the current Intraday 1 mid-morning nomination cycle and 
permit bumping. The NOPR proposed Intraday 3 Nomination Cycle would 
begin at 4:00 p.m. CCT with pipelines issuing scheduled quantities at 
6:00 p.m. CCT, and gas flow beginning at 7:00 p.m. CCT. The NOPR 
proposed Intraday 3 Nomination Cycle would provide an additional 
bumping opportunity for firm shippers. The NOPR proposed Intraday 4 
Nomination Cycle would begin at 7:00 p.m. CCT with pipelines issuing 
scheduled quantities at 9:00 p.m. CCT, and gas flow beginning at 9:00 
p.m. CCT. The NOPR Intraday 4 Nomination Cycle would replace the 
current 5:00 p.m. no-bump cycle.
2. NAESB's Revised Intraday Nomination Cycles
    93. NAESB's revised standards provide for three intraday nomination 
opportunities, rather than the four proposed in the NOPR. In contrast 
to the NOPR proposal to start the Intraday 1 Nomination Cycle at 8:00 
a.m. CCT, NAESB's revised standards start the Intraday 1 Nomination 
Cycle at the existing 10:00 a.m. CCT time. However, the revised 
standards move the deadline for pipelines to issue scheduled quantities 
up to 1:00 p.m. CCT from the existing NAESB standard of 2:00 p.m., and 
for gas flow to begin at 2:00 p.m. CCT, rather than the existing 5:00 
p.m. CCT. NAESB's revised standards provide for the Intraday 2 
Nomination Cycle to start at 2:30 p.m. CCT, rather than 5:00 p.m., as 
it now does. Pipelines would issue scheduled quantities at 5:30 p.m. 
CCT, rather than the existing 9:00 p.m., and gas flow would begin at 
6:00 p.m. CCT, instead of the existing 9:00 p.m. NAESB's new Intraday 3 
Nomination Cycle begins at 7:00 p.m. CCT, with scheduled quantities 
issued at 10:00 p.m. CCT, and gas flow beginning at 10:00 p.m. CCT. 
NAESB's revised standards provide that bumping of interruptible service 
will be allowed during the Intraday 2 Nomination Cycle in addition to 
the Intraday 1 Nomination Cycle.\154\ NAESB's revised standards reflect 
reduced intraday processing times from the current NAESB standards 
(i.e., 3 hours instead of the current 4 hours). A comparison of the 
current NAESB intraday nomination timeline and the revised NAESB 
intraday nomination timeline is shown in the table below.
---------------------------------------------------------------------------

    \154\ A comparison of the current NAESB nomination timeline and 
the revised NAESB nomination timeline is set forth in the Appendix.

                   Table 8--Intraday Nomination Cycles
------------------------------------------------------------------------
                                  Current NAESB         Revised NAESB
 Time shifts--all times CCT         standards             standards
------------------------------------------------------------------------
Intraday 1
    Nomination Deadline.....  10:00 a.m...........  10:00 a.m.
    Schedule Issued.........  2:00 p.m............  1:00 p.m.
    Start of Gas Flow.......  5:00 p.m............  2:00 p.m.
    IT Bump Rights..........  bumpable............  bumpable.

[[Page 23215]]

 
Intraday 2
    Nomination Deadline.....  5:00 p.m............  2:30 p.m.
    Schedule Issued.........  9:00 p.m............  5:30 p.m.
    Start of Gas Flow.......  9:00 p.m............  6:00 p.m.
    IT Bump Rights..........  no bump.............  bumpable.
Intraday 3
    Nomination Deadline.....  ....................  7:00 p.m.
    Confirmations...........  ....................  9:30 p.m.
    Schedule Issued.........  ....................  10:00 p.m.
    Start of Gas Flow.......  ....................  10:00 p.m.
    IT Bump Rights..........  ....................  no bump.
------------------------------------------------------------------------

3. Comments
    94. The large majority of comments on this issue support or do not 
oppose NAESB's revised standards providing for three Intraday 
Nomination Cycles.\155\ Commenters state that, consistent with the 
NOPR's proposed four intraday nomination cycles, NAESB's modified three 
intraday nomination cycles will allow gas-fired generators, as well as 
other pipeline customers, more flexibility to respond to scheduling, 
operational, or weather-related changes throughout the operating 
day.\156\
---------------------------------------------------------------------------

    \155\ AGA Comments at 22; Ameren Comments at 1; ANGA Comments at 
3; BHE Comments at 16-17; Calpine Comments at 7; Castex (Producer 
Coalition) Comments at 7; CenterPoint Comments 3-4; Con Edison 
Companies Comments at 9; CPG Comments at 5; Direct Energy Comments 
at 2; Dominion Comments at 3; DTE Gas Comments at 3; Duke Energy 
Comments at 3; Enhanced Reliability Coalition Comments at 29; EPSA 
Comments at 7; Equipower Comments at 9; ESI Comments at 3-4; Exelon 
Comments at 6; Gas Processors Association Comments at 1-2; INGAA 
Comments at 5; IOGA Comments at 5; IPPA Comments at 2; Kinder Morgan 
Comments at 6; National Fuel Distribution at 2-3; National Grid 
Comments at 1-2; Natural Gas Council Comments at 1-2; New England 
LDCs Comments at 30; NGSA Comments at 1-2; Nisource Comments at 2; 
Northwest Gas Association Comments at 2-3; Northwest Industrial Gas 
Users Comments at 5-6; PGC Comments at 4; PUCO Comments at 6-8; 
Puget Comments at 10; Sequent Comments at 6; Southern Companies 
Comments at 11; Southern Star Comments at 3; Spectra Comments at 4; 
Texas Pipeline Association Comments at 9; TVA Comments at 2; WBI 
Energy Comments at 4.
    \156\ See, e.g., AGA Comments at 22-23; Ameren Comments at 5; 
CPG Comments at 5-6; Duke Energy Comments at 2-4; Exelon Comments at 
6; INGAA Comments 5-7; IOGA Comments at 5
---------------------------------------------------------------------------

    95. Many commenters state that they do not support an additional 
fourth intraday nomination cycle, as proposed in the NOPR, arguing it 
would likely result in increased costs and overlapping cycles.\157\ For 
example, Dominion states that a fourth intraday cycle may require a 
third shift of employees, which will increase costs for pipelines.\158\
---------------------------------------------------------------------------

    \157\ See, e.g., Exelon Comments at 7; Kinder Morgan Comments at 
XX; NGSA Comments at 16-17; PGC Comments at 5; Puget Comments at 17; 
WBI Energy Comments at 4-5.
    \158\ Dominion Comments at 11.
---------------------------------------------------------------------------

    96. Many commenters state that NAESB's three intraday nomination 
cycles resolve gas industry participants' concerns with the NOPR's 
proposed four intraday nomination cycles regarding overlapping cycles, 
which, left unresolved, could lead to greater instances of incorrect 
shipper nominations and scheduling errors.\159\ Commenters highlight 
several examples of overlapping cycles under the NOPR's proposed four 
intraday nomination cycles. First, commenters state that the start of 
the NOPR's proposed Evening Nomination Cycle is at 6:00 p.m. CCT, which 
would be the same time scheduled quantities are posted for the Intraday 
3 Nomination Cycle. Commenters state that this would require a shipper 
to analyze how much of its gas the pipeline scheduled to flow for the 
remainder of the current Gas Day at the same time it must nominate in 
the Evening Nomination Cycle for gas flow the next day. Second, 
commenters state that the NOPR's proposed 10:30 a.m. CCT start of the 
Intraday 2 Nomination Cycle would be before the 11:00 a.m. CCT posting 
of scheduled quantities for the Intraday 1 Nomination Cycle. Commenters 
state that under this timeline a customer would have to nominate gas in 
the Intraday 2 Nomination Cycle before learning what quantity of gas 
the pipeline scheduled in the Intraday 1 Nomination Cycle. Third, 
commenters state that the NOPR's proposed 4:30 p.m. CCT posting of 
scheduled quantities for the Timely Nomination Cycle overlaps with the 
4:00 p.m. start of the Intraday 3 Nomination Cycle, which would require 
pipelines to schedule gas for two different cycles at the same time. 
Commenters also point out that NAESB's three intraday nomination 
cycles, like its revised Timely Nomination Cycle, reflect a shortened 
processing time (i.e., 3 hours instead of 4 hours). Commenters in the 
natural gas industry claim that these processing times cannot be 
shortened any further.\160\
---------------------------------------------------------------------------

    \159\ See, e.g., Dominion Comments at 11; EPSA Comments at 6-7; 
INGAA Comments at 9; PGC Comments at 5; Southern Star Comments at 5.
    \160\ Dominion Comments at 11; Kinder Morgan Comments at 6-8; 
WBI Comments at 4; see also INGAA Comments at 8-9.
---------------------------------------------------------------------------

    97. Many commenters state that NAESB's three intraday nomination 
cycles, unlike that of the NOPR's proposed four intraday nomination 
cycles, provide sufficient time (1.5 hours) between the scheduled 
quantity posting of one cycle and the nomination deadline for the next 
cycle, so that shippers can review their pipeline transportation needs 
prior to the next nomination deadline.\161\ Under the NOPR's proposed 
four intraday nomination cycles, the 10:30 a.m. start of the Intraday 2 
Nomination Cycle is before the 11:00 a.m. posting of scheduled 
quantities for the Intraday 1 Nomination Cycle and there is only 1 hour 
between the time the schedules are posted for the Intraday 3 Nomination 
Cycle (6:00 p.m.) and the start of the Intraday 4 Nomination Cycle 
(7:00 p.m.). Many commenters also point out that NAESB's nomination 
timeline, in particular the three intraday nomination cycles, allows 
for the accomplishment of most scheduling work during regular business 
hours, or as close as possible to regular hours.\162\
---------------------------------------------------------------------------

    \161\ See, e.g., EPSA Comments 6-7; Exelon Comments at 7; INGAA 
Comments at 8-9, WBI Energy Comments at 4.
    \162\ See, e.g., Enhanced Reliability Coalition Comments at 31; 
Northwest Gas Association Comments at 2-3; PGC Comments at 4; 
Southern Companies Comments at 10-11.
---------------------------------------------------------------------------

    98. AGA, Dominion, and INGAA submit that NAESB's three intraday 
nomination cycles, in particular the Intraday 2 and Intraday 3 
Nomination Cycles, will also address the Commission's concern regarding 
gas-

[[Page 23216]]

fired generators' ability to ensure adequate gas supplies for the 
morning electric ramp by providing sufficient opportunities during the 
operating day to schedule gas to cover that morning period.\163\
---------------------------------------------------------------------------

    \163\ See, e.g., AGA Comments at 23; Dominion Comments at 9-10; 
INGAA Comments at 6-7
---------------------------------------------------------------------------

    99. ACES, AEP, Essential Power, and IRC support the four intraday 
nomination cycles proposed in the NOPR, rather than the three provided 
by NAESB's revised standards.\164\ They state that more standardized 
opportunities for electric generators to nominate gas would provide 
generators additional operational flexibility to respond to real-time 
electric system needs.
---------------------------------------------------------------------------

    \164\ ACES Comments at 9; AEP Comments at 4; Essential Power 
Comments at 4; IRC Comments at 4. IRC notes that CAISO would support 
three intraday gas nomination cycles irrespective of an earlier 
start of the Gas Day.
---------------------------------------------------------------------------

    100. While Exelon supports NAESB's proposed three intraday 
nomination cycles, it cautions that, if the start of the Gas Day 
remains at 9:00 a.m. CCT, non-bumpable interruptible shippers will 
preempt the rights of firm shippers for almost half of the Gas Day, or 
11 hours.\165\ Con Edison point out that, if the start of the Gas Day 
remains at 9:00 a.m. CCT, NAESB's last bumpable intraday cycle (2:30 
p.m. CCT) would be more than 18 hours before the current start of next 
Gas Day.\166\ Con Edison states that electric system conditions and 
load can change dramatically during an 18-hour period. Similarly, DSPS 
states that NAESB's three intraday nomination cycles makes sense from 
the perspective of a utility that operates in the Eastern-time zone, 
but notes that utilities, such as those in the Desert Southwest, that 
do not have a late afternoon nomination cycle effectively have no tools 
to ensure the reliability of their natural gas transportation during 
the last 18.5 hours of the Gas Day, assuming a 9:00 a.m. CCT start to 
the Gas Day.\167\
---------------------------------------------------------------------------

    \165\ Exelon Comments at 10-11.
    \166\ Con Edison Comments at 10.
    \167\ DSPS Comments at 19-20.
---------------------------------------------------------------------------

    101. EDF et al. does not support NAESB's addition of a single 
intraday cycle. EDF et al. urges the Commission to standardize the 
voluntary enhanced practices of certain pipelines and establish up to 
twelve intraday nominating and gas capacity trading (capacity release) 
cycles.\168\
---------------------------------------------------------------------------

    \168\ EDF et al. Comments at 12.
---------------------------------------------------------------------------

    102. TVA, DSPS, Southern Star, Southern Company, and Michigan PSC 
encourage the Commission to consider modifying or eliminating the No-
Bump Rule.\169\ TVA asserts that firm shippers paying demand charges 
under long-term firm contracts should always have priority, as firm 
capacity is charged and paid for the entire twenty-four hours of the 
Gas Day.\170\ DSPS states that the No-Bump Rule precludes a firm 
shipper from calling upon the unutilized portion of its firm contract 
to satisfy the evening peak demands if the capacity already has been 
nominated by and confirmed to an interruptible shipper.\171\
---------------------------------------------------------------------------

    \169\ DSPS Comments at 19-20; Michigan PSC Comments at 5-6; 
Southern Company Comments at 11-12; Southern Star Comments at 3; TVA 
Comments at 3.
    \170\ TVA Comments at 3.
    \171\ DSPS Comments at 20.
---------------------------------------------------------------------------

    103. Many commenters argue that the last intraday grid-wide 
nomination cycle should remain a no-bump cycle, as provided by NAESB's 
revised standards.\172\ Commenters note that retaining the no-bump 
cycle was strongly supported in the NAESB process. The Enhanced 
Reliability Coalition states that no-bump plays an important role in 
balancing the flexibility needs for interruptible transmission shippers 
with available capacity while providing priority to firm shippers (who 
incurred the firm shipping costs) over interruptible shippers through 
the NAESB Intraday 2 Nomination Cycle.\173\
---------------------------------------------------------------------------

    \172\ See, e.g., Dominion Comments at 10; Enhanced Reliability 
Coalition Comments at 31; ESPA comments at 3; IECA Comments at 4; 
National Grid Comments at 30; NGSA Comments at 18-19; WBI Comments 
at 5; PGC Comments at 5-6; Sequent Comments at 6.
    \173\ Enhanced Reliability Coalition Comments at 31.
---------------------------------------------------------------------------

4. Commission Determination
    104. The Commission is amending its regulations at Part 284 to 
incorporate by reference NAESB's revised standards, which provide three 
intraday nomination cycles. Adoption of these standards will provide 
natural gas-fired generators, as well as other pipeline shippers, with 
increased scheduling flexibility. While the Intraday 1 Nomination Cycle 
will continue to start at 10:00 a.m. CCT, pipelines will issue 
scheduled quantities at 1:00 p.m. CCT, one hour earlier than under the 
currently effective standards, and gas flow will begin at 2:00 p.m. 
CCT, three hours earlier than under the currently effective standards. 
The new bumpable Intraday 2 Nomination Cycle will start at 2:30 p.m. 
CCT, four and a half hours after the single bumpable intraday 
nomination opportunity provided by the existing Intraday 1 Nomination 
Cycle, with pipelines issuing scheduled quantities at 5:30 p.m. CCT, 
and gas flow beginning at 6:00 p.m. CCT. By adding an additional 
bumpable nomination cycle later in the day, firm shippers will have 
greater opportunity to utilize the intraday schedules to reflect load 
and weather changes consistent with the higher priority of their 
service. The later time for the bumpable nomination will help shippers 
in the west, in particular, by allowing them to reflect later changes 
in weather forecasts into their nominations. The new no-bump Intraday 3 
Nomination Cycle will start at 7:00 p.m. CCT, two hours later than the 
current no-bump Intraday 2 Nomination Cycle, with gas flow beginning at 
10:00 p.m. CCT, one hour later than under the current no-bump Intraday 
2 Nomination Cycle. The later no-bump nomination cycle will give firm 
shippers a further opportunity to adjust their nominations consistent 
with their needs, while also providing certainty to interruptible 
transactions, so shippers and pipelines can plan for flows during the 
Gas Day.
    105. These revised standards reflect a consensus of the natural gas 
industry, and the changes reflect broad support in both industries. The 
vast majority of the commenters prefer NAESB's proposed three intraday 
nomination cycles to the NOPR's proposed four intraday nomination 
cycles because the NAESB proposal allows sufficient time for processing 
gas nominations, avoids overlapping nomination cycles, and allows for 
the accomplishment of most scheduling work during regular business 
hours, or reasonably close thereto. Further, they meet the goals of the 
NOPR because they provide additional flexibility to gas-fired 
generators, as well as other pipeline shippers. While some would prefer 
further changes to address their individual or regional needs, we find 
that, on balance, these standards represent a step forward that will 
benefit all shippers. We also note that under Commission policy, 
pipelines may file enhanced services that provide additional scheduling 
flexibility for firm shippers by adding additional nomination cycles 
that allow firm shippers to bump interruptible shippers.\174\
---------------------------------------------------------------------------

    \174\ As clarified in the NOPR, pipelines may offer enhanced 
nomination opportunities that permit bumping of interruptible 
shippers at least until the time the bumping notice under the 
modified NAESB Intraday 2 Nomination schedule is issued at 5:30 p.m. 
CCT. NOPR, 146 FERC ] 61,201 at P 73. The modified NAESB Intraday 3 
Nomination Cycle guarantees that any bumped interruptible shipper 
will have an opportunity to renominate its bumped volumes at 7:00 
p.m. CCT. If a pipeline proposes enhanced nomination services that 
permit bumping of interruptible services after 5:30 p.m. CCT, the 
Commission will consider the proposal on a case-by-case basis to 
determine whether such proposal provides an adequate subsequent 
opportunity to renominate any bumped volumes. Id.

---------------------------------------------------------------------------

[[Page 23217]]

    106. Some commenters suggest that because firm service has a higher 
priority than interruptible service, firm shippers should always be 
able to bump interruptible service, and more generally, that all 
nomination cycles should be bumpable. We find sufficient support for 
retaining a no-bump cycle and respecting the gas industry consensus 
that was achieved.\175\ As several commenters maintain, and as the 
Commission has previously recognized, interruptible shippers need some 
stability in the nomination system. In Order No. 587-G, the Commission 
accepted a consensus of the gas industry, including both firm and 
interruptible shippers, and accepted standards that provide that the 
last intraday nomination opportunity would not permit bumping of 
interruptible service. In adopting this standard, the Commission 
recognized that making the last intraday nomination opportunity no-bump 
would provide stability to the nomination system.\176\ Moving the last 
bump cycle to later in the day helps to accommodate the needs of the 
firm shippers, while maintaining the No-Bump Rule during NAESB's 
Intraday 3 Nomination Cycle will provide stability for interruptible 
shippers. As such, we find that it achieves a reasonable balance of 
interests.
---------------------------------------------------------------------------

    \175\ Standards for Business Practices of Interstate Natural Gas 
Pipelines, Order No. 587, 61 FR 39053 (July 26, 1996), FERC Stats. & 
Regs., Regulations Preambles ] 31,038 (July 17, 1996) (``Since it is 
the industry that must operate under these standards, deferring to 
the considered judgment of the consensus of the industry is both 
reasonable and appropriate'').
    \176\ Order No. 587-G, FERC Stats. & Regs., ] 31,062, order on 
reh'g, Order No. 587-I, 63 FR 53565, 53569 (Oct. 6, 1998), FERC 
Stats. & Regs., Regulations Preambles 1996-2000 ] 31,067 (1998).
---------------------------------------------------------------------------

    107. While NAESB's modified standards represent an improvement over 
the currently effective standards, we continue to recognize that 
additional intraday nomination opportunities could promote more 
efficient use of existing pipeline infrastructure and provide 
additional operational flexibility to all pipeline shippers, including 
gas-fired generators. The modified NAESB standards reflect reduced 
intraday processing times from the current NAESB standards (i.e., three 
hours instead of the current four hours), and existing operational 
limitations, including the manual processes utilized by pipelines for 
processing nominations, may affect the ability of the gas industry to 
add additional standard nomination cycles applicable to all shippers. 
However, the use of computerized scheduling would appear to provide an 
opportunity for faster and more frequent scheduling of intraday 
nominations for those shippers and their confirming parties willing to 
commit to scheduling electronically. We request that gas and electric 
industries, through NAESB, explore the potential for faster, 
computerized scheduling when shippers and confirming parties all submit 
electronic nominations and confirmations, including a streamlined 
confirmation process if necessary. Providing such an option would 
enable those entities that need greater scheduling flexibility to have 
their requests processed expeditiously.

V. DSPS Proposal

A. Background

    108. In its proposal, DSPS asserts that the fundamental issue in 
the Desert Southwest is that firm transportation shippers do not have 
the necessary tools to access their firm transportation capacity in 
order to properly respond to operating contingencies, including 
unexpected changes in renewable generation, that occur during their 
evening peak demand period. DSPS suggests that three Commission 
policies preclude firm shippers in the Desert Southwest from accessing 
their transportation capacity during their evening peak demand period. 
First, DSPS states that the intraday nomination cycles do not align 
with the evening peak periods of demand in the Desert Southwest which 
occur between 7:00 p.m. and 9:00 p.m. CCT. Second, DSPS states that the 
rule that interruptible service cannot be bumped in the last intraday 
nomination cycle precludes firm transportation shippers from accessing 
their transportation capacity during the evening peak period if an 
interruptible shipper is already flowing gas on the system. Finally, 
DSPS states that the Commission's rule that, once scheduled, secondary 
firm service cannot be bumped in any subsequent nomination cycle,\177\ 
also interferes with the ability of firm shippers to schedule primary-
firm service after the Timely Nomination Cycle. DSPS states that it is 
concerned that some shippers are contracting for primary firm 
transportation rights on unused pipeline paths and then scheduling 
secondary firm service on a more heavily used path outside their 
primary path in the Timely or Evening Nomination Cycles. DSPS states 
that this blocks shippers holding primary firm rights to the more 
heavily used path, including DSPS members, from using their primary 
firm service in subsequent nomination cycles.
---------------------------------------------------------------------------

    \177\ The Commission's long standing policy on firm service is 
that once scheduled, whether at primary or secondary points, the 
service may not be bumped by a nomination by another firm shipper.
---------------------------------------------------------------------------

    109. DSPS notes that geographical factors also present unique 
challenges in the Desert Southwest. DSPS indicates that the Desert 
Southwest does not have local market area gas storage which makes it 
difficult to respond to unexpected changes in demand. Further, DSPS 
contends that the Desert Southwest is the home of a growing percentage 
of renewable energy resources. DSPS claims that electric utilities 
require both the transportation capacity and the natural gas commodity 
be available to respond to the immediate generation demands caused by 
the drop in renewable energy.
    110. Accordingly, DSPS proposes changes on a national basis and on 
a regional basis, as discussed below.

B. DSPS's Proposed National Changes

    111. On a national basis, DSPS requests that the Commission: (1) 
Start the Evening Nomination Cycle at 7:00 p.m. CCT (instead of 6:00 
p.m. CCT, as in both the NOPR and NAESB's revised standards); and (2) 
modify the Commission's policy on natural gas scheduling priority to 
allow primary-firm shippers to bump secondary firm shippers during the 
Evening Nomination Cycle. DSPS contends that moving the Evening 
Nomination Cycle to 7:00 p.m. CCT provides a timely opportunity to 
address operating contingencies. DSPS also contends that, unlike the 
alternative of establishing a bumpable 7:00 p.m. CCT intraday 
nomination cycle, this proposal dispenses with the concerns surrounding 
interrupting flowing gas, the need for a subsequent no-bump cycle, and 
the fact such a late intraday nomination cycle would have little value 
due to the elapsed pro-rata flow of the gas. DSPS asserts that its 
proposal to modify the Commission's policy on secondary firm 
nominations would increase the value of firm contracts involving 
primary points and encourage long-term contracting, which in turn 
promotes infrastructure development.
1. Comments
    112. In its October 15, 2014 notice, the Commission specifically 
sought comment on the DSPS proposals. None of the commenters on DSPS's 
proposal support DSPS's proposal to change the Evening Nomination Cycle 
from 6:00

[[Page 23218]]

p.m. to 7:00 p.m. CCT.\178\ While most commenters oppose modifying 
Commission policy to permit primary-firm nominations to bump secondary 
firm nominations in the Evening Nomination Cycle, a few commenters 
support this proposal.
---------------------------------------------------------------------------

    \178\ ACES Comments at 13; AGA Comments at 33; Dominion Comments 
at 12-13; Enhanced Reliability Coalition Comments at 32-33; EPSA 
Comments at 8; INGAA Comments at 9-10; IPAA Comments at 3; Kinder 
Morgan Comments at 10; National Grid Comments at 5; New England LDCs 
Comments at 32; Natural Gas Council Comments at 6; NGSA Comments at 
22; PGC Comments at 8; Sequent Comments at 6; Southwest IS Comments 
at 2-3; Transwestern Comments at 4; WBI Energy Comments at 7.
---------------------------------------------------------------------------

    113. Many of those commenters opposing the DSPS proposal to change 
the Evening Nomination Cycle contend that the change is contrary to the 
NAESB efforts to establish a coordinated nomination and scheduling 
timeline.\179\ PGC states that during the NAESB discussion and voting 
process, a 7:00 p.m. CCT Evening Nomination Cycle was thoroughly vetted 
and ultimately rejected by a majority of the industry 
participants.\180\ Other commenters state that the proposed time would 
coincide with the start of the NAESB Intraday 3 Nomination Cycle.\181\ 
Several commenters also state that DSPS has not sufficiently explained 
why its proposed 7:00 p.m. Evening Nomination Cycle would address its 
concerns about operating contingencies occurring in the late afternoon 
of a Gas Day as nominations made during the Evening Nomination Cycle 
are for gas flow on the following Gas Day.\182\
---------------------------------------------------------------------------

    \179\ See, e.g., INGAA Comments at 9-10; National Grid Comments 
at 5; New England LDCs Comments at 32; PGC Comments at 8; 
Transwestern Comments at 4.
    \180\ PGC Comments at 9.
    \181\ See, e.g., AGA Comments at 33; BHE Comments at 6-7; 
Dominion Comments at 12-13.
    \182\ See, e.g., Dominion Comments at 12-13; PGC Comments at 9; 
Southwest IS Comments at 6.
---------------------------------------------------------------------------

    114. With respect to DSPS's proposal to change the scheduling 
priority of secondary firm/alternate nominations in the Evening 
Nomination Cycle, NGSA and PGC contend the DSPS proposal would de-value 
secondary firm service \183\ and AGA argues that the DSPS proposal 
would adversely affect gas customers by reducing revenues from 
secondary market sales that are used to mitigate the costs of holding 
firm capacity.\184\
---------------------------------------------------------------------------

    \183\ NGSA Comments at 23; PGC Comments at 10.
    \184\ AGA Comments at 34.
---------------------------------------------------------------------------

    115. Several pipelines state that the proposal to allow primary-
firm nominations to bump secondary firm nominations in the Evening 
Nomination Cycle would also negatively affect pipeline operations.\185\ 
INGAA states that pipeline operators need sufficient time after 
scheduling nominations, based on priority, to set up the pipeline 
system for the next Gas Day. INGAA contends that the adoption of the 
DSPS's proposal effectively would shift this work from the period 
following the Timely Nomination Cycle to the period following the 
Evening Nomination Cycle because firm shippers will have little or no 
reason to submit primary firm nominations prior to the Evening 
Nomination Cycle. WBI and INGAA further note that the DSPS proposal 
would move the major confirmation and scheduling period outside of 
normal business hours, making it more difficult for a pipeline operator 
to confirm a shipper's nomination with receipt and delivery point 
operators, producers and shippers.
---------------------------------------------------------------------------

    \185\ INGAA Comments at 11-12; Kinder Morgan Comments at 11; WBI 
Comments at 7.
---------------------------------------------------------------------------

    116. Similarly, PGC and INGAA assert that delaying the posting of 
scheduled quantities until 10:00 p.m. CCT would cause uncertainty among 
firm shippers until after business hours, when few suppliers are 
staffed sufficiently to reroute or resell gas and the commodity market 
is not liquid, to learn whether the shipper's gas was scheduled to flow 
the next Gas Day or be bumped.\186\
---------------------------------------------------------------------------

    \186\ PGC Comments at 11; INGAA Comments at 11-12.
---------------------------------------------------------------------------

    117. Kinder Morgan notes that NAESB has recently developed capacity 
release standards (in conjunction with moving the Timely Nomination 
Cycle back to 1:00 p.m.) that will allow shippers to acquire released 
capacity in time to be nominated in the Timely Nominated Cycle.\187\ 
Kinder Morgan states that the DSPS proposal would negate the benefit of 
this enhancement.
---------------------------------------------------------------------------

    \187\ Kinder Morgan Comments at 12.
---------------------------------------------------------------------------

    118. Southern Company supports allowing primary-firm nominations to 
bump secondary firm nominations in the Evening Nomination Cycle.\188\ 
Southern Company suggests that a critical component of its plans for 
providing reliable, cost-effective electricity supply to customers 
calls for the maintenance of firm gas transportation and storage 
capacity to serve its gas-fired generators. Southern Company suggests 
that the value of holding firm transportation service to serve gas-
fired generators is undermined, however, when an electric generator 
attempts to react to changes in demand only to find its contracted firm 
transportation capacity unavailable as a result of other shippers' 
prior, secondary firm nominations. Southern Company believes the 
current policy sends the wrong signal to market participants who might 
otherwise choose to invest in firm service if they could be confident 
of their rights to exercise it as needed.
---------------------------------------------------------------------------

    \188\ Southern Companies at 11-12.
---------------------------------------------------------------------------

    119. Along the same lines, TVA argues that secondary out-of-path 
service should have no higher priority than interruptible 
transportation.\189\ TVA states that its access to its firm, in-path 
capacity is being jeopardized by shippers contracting for firm 
transportation on pipeline paths that do not deliver to their markets 
and subsequently nominating secondary firm transportation outside their 
primary path on a perpetual basis. This practice limits primary firm 
shippers' ability to utilize their capacity after the Timely Nomination 
Cycle. TVA states that capacity is only built to support the primary 
path of firm transportation contracts and will not materialize when a 
shipper contracts for a specified firm transportation path, but chooses 
to nominate and flow on an entirely unrelated path.
---------------------------------------------------------------------------

    \189\ TVA Comments at 4.
---------------------------------------------------------------------------

    120. Many commenters support consideration of the DSPS proposal on 
a regional basis by individual pipelines.\190\ Transwestern states that 
the proposal is workable and has been adopted on other pipelines.\191\
---------------------------------------------------------------------------

    \190\ See, e.g., Dominion Comments at 13; Enhanced Reliability 
Coalition at 31-32; Sequent Comments at 6; NGSA Comments at 22.
    \191\ Transwestern Comments at 4-5.
---------------------------------------------------------------------------

2. Commission Determination
    121. The Commission declines to adopt DSPS' proposal to move the 
Evening Nomination Cycle to 7:00 p.m. CCT or to modify the Commission's 
policy on natural gas scheduling priority to require all pipelines to 
permit primary firm nominations to bump secondary firm nominations in 
the Evening Nomination Cycle.
    122. With respect to the proposed change to the Evening Nomination 
Cycle, DSPS fails to make clear how moving the start time of the 
Evening Nomination Cycle one hour later to 7:00 p.m. CCT provides 
shippers in its region with a more timely opportunity to address 
operating contingencies that arise fourteen hours later during the Gas 
Day. Starting the Evening Nomination Cycle at 7:00 p.m. CCT does not 
appear to address DSPS's concerns with demand fluctuations, given that 
the Evening Nomination Cycle is for gas scheduled to flow the next Gas 
Day, not the current Gas Day. Also, under DSPS' proposal, the Evening 
Nomination Cycle would occur at the same time as

[[Page 23219]]

NAESB's Intraday 3 Nomination Cycle. Given the wide support for the 
revised NAESB Evening Nomination Cycle and the largely unexplained 
benefits of moving the Evening Nomination Cycle later, we find that 
making such a change to the Evening Nomination Cycle is unwarranted.
    123. Regarding modifying Commission policy to require all pipelines 
to permit primary firm nominations to bump scheduled secondary firm 
service in the Evening Nomination Cycle, the Commission finds that the 
benefits of that proposal do not outweigh the burdens that would be 
placed on all interstate pipelines and secondary firm shippers as a 
result of such proposal. Based on the comments, allowing primary firm 
to bump secondary firm would move the major confirmation and scheduling 
period outside of normal business hours, making it more difficult for a 
pipeline operator to confirm a shipper's nomination with point 
operators, producers and shippers. It could also disrupt the liquid 
secondary market for capacity by reducing the value of obtaining 
released capacity. For these reasons, the Commission declines to adopt 
this proposal on a national basis.

C. 1-Year Pilot Program

    124. DSPS also requests that Commission require, on a 1-year pilot 
program basis, the pipelines serving the Desert Southwest (i.e., El 
Paso Natural Gas, Transwestern and TransCanada-North Baja Pipelines) to 
allow firm shippers experiencing an unexpected increase in demand 
during the evening of the current Gas Day to submit a separate ``retro/
make-up'' nomination during the Evening Nomination Cycle that would not 
take effect until the start of the next Gas Day but would make up for 
the unscheduled service they take during the current Gas Day. DSPS also 
proposes that the Pilot Program: (a) Provide that imbalance charges/
penalties only apply to imbalances that are not corrected by gas that 
flows at the start of the Gas Day; and (b) prohibit shippers from 
submitting a combination of a retro/make-up nomination and a daily 
nomination that exceeds the shipper's Maximum Daily Quantity of its 
firm contract. DSPS states that, by allowing a retro/make up nomination 
to be submitted in the Evening Nomination Cycle, the firm shipper would 
be ensuring that the gas it uses to address the operating contingency 
would be injected into the pipeline beginning at the start of the next 
Gas Day.
1. Comments
    125. Kinder Morgan states that its pipelines that serve the DSPS 
stakeholders have been engaged in discussions with DSPS regarding their 
unique issues.\192\ Kinder Morgan states that the regional needs of the 
DSPS are best addressed on a pipeline-specific basis. Kinder Morgan 
also notes that El Paso has previously added additional nomination 
intraday cycles and offers various types of hourly services. Kinder 
Morgan states that the DSPS pilot program incorrectly assumes that 
pipelines have available unused capacity or other flexibility that 
would allow a shipper to unilaterally take whatever amount of gas it 
wants at 7:00 p.m. CCT and that the pipeline would entertain a retro or 
make-up nomination recognizing the shipper took the gas and returned it 
to the pipeline later. Kinder Morgan states that this proposal poses 
substantial problems for a pipeline by requiring the pipeline to keep 
the shipper whole for a good portion of the 24-hour Gas Day, placing 
its other deliveries at risk. Kinder Morgan states that in actuality 
this type of transaction calls for a no-notice type of transportation 
service and potentially requires new facilities, including storage.
---------------------------------------------------------------------------

    \192\ Kinder Morgan Comments at 12.
---------------------------------------------------------------------------

    126. Transwestern states that, while further clarification is 
needed as to exactly what DSPS intends, Transwestern is willing to work 
with DSPS and other regional entities to structure retro/make-up 
nominations and help customers manage their loads in view of the unique 
operating circumstances of the Desert Southwest.\193\
---------------------------------------------------------------------------

    \193\ Transwestern Comments at 5.
---------------------------------------------------------------------------

2. Commission Determination
    127. As noted elsewhere in this Final Rule, regional solutions may 
work best to address certain needs arising from increased use of 
natural gas. While the Commission will not require the pipelines 
serving the Desert Southwest (i.e., El Paso Natural Gas, Transwestern 
and TransCanada-North Baja Pipelines) to implement DSPS's proposed 1-
year pilot program, we encourage continued discussion in the region. 
The record here is insufficient for the Commission to require the 
pipelines to institute DSPS' requested pilot program of make-up 
nominations. The comments of the pipelines affected by this proposal 
indicate that they are uncertain of the operational feasibility of 
instituting a make-up nomination, but are interested in discussing this 
issue further with the DSPS shippers. Given the comments, we lack any 
evidence that requiring these pipelines to offer make-up nominations 
during the Evening Nomination Cycle is operationally feasible for all 
the pipelines. However, one or more pipelines appear willing to discuss 
potential service offerings that may help Desert Southwest shippers and 
we encourage those discussions to proceed.

VI. Multi-Party Transportation Contracts

A. Background

    128. The Commission's regulations require that all transfers of 
firm pipeline capacity from one shipper to another shipper take place 
pursuant to the capacity release program in section 284.8 of our 
regulations to ensure that such capacity transfers are transparent and 
not unduly discriminatory.\194\ Utilizing capacity release to 
effectuate sharing of capacity between entities can make sharing of 
capacity less efficient due to the need to comply with the capacity 
release posting and bidding requirements, as well as the need for the 
replacement shipper to enter into a contract with the pipeline for each 
release. In recent years, however, the Commission has accepted several 
pipeline proposals to offer multiple shippers the option of entering 
into a single contract for transportation service, with a single agent 
or asset manager managing the capacity under the contract.\195\ As 
approved by the Commission, this option permits several shippers to 
share the subject capacity without the need to use the capacity

[[Page 23220]]

release program to transfer the capacity among themselves. In order to 
satisfy the Commission's shipper-must-have-title policy, the pipelines 
proposed, and the Commission accepted, tariff provisions ensuring that 
each shipper under a multi-party transportation contract agree to be 
jointly and severally liable for all obligations of all shippers and 
the agent under the single service agreement.\196\ The Commission has 
permitted multi-party transactions even when the shippers under such an 
agreement are not affiliated with one another.\197\
---------------------------------------------------------------------------

    \194\ See Pipeline Service Obligations and Revisions to 
Regulations Governing Self-Implementing Transportation and 
Regulation of Natural Gas Pipeline After Partial Wellhead Decontrol, 
Order No. 636, FERC Stats. & Regs. ] 30,939, at 30,416-20, order on 
reh'g, Order No. 636-A, FERC Stats. & Regs. ] 30,950, at 30,554 
(1992). See also Regulation of Short-Term Natural Gas Transportation 
Services and Regulation of Interstate Natural Gas Transportation 
Services, Order No. 637, FERC Stats. & Regs. ] 31,091, at 31,300 
(2000).
    \195\ Southern Natural Gas Co., 124 FERC ] 61,145 (2008) 
(Southern) (pipeline modified Rate Schedule FT to allow a single 
contract option for multiple shippers affiliated with a single agent 
or asset manager); Florida Gas Transmission Co., LLC, 128 FERC ] 
61,284 (2009), order on compliance filing, Docket No. RP09-922-001 
(Nov. 17, 2009) (delegated letter order) (pipeline modified 
provisions of Rate Schedules FT and IT to allow a single contract 
option for multiple shippers that have designated a single agent on 
their behalf); Transcontinental Gas Pipe Line Corp., Docket No. 
RP10-1099-000 (Sept. 14, 2010) (delegated letter order) (pipeline 
modified provisions of Rate Schedules IT, PAL and Pooling, and ICTS 
to allow a single contract option for multiple shippers that have 
designated a single agent on their behalf); Tennessee Gas Pipeline 
Co., L.L.C., 142 FERC ] 61,200 (2013) (Tennessee) (pipeline modified 
provisions of Rate Schedules FT, IT and PAL to allow a single 
contract option for multiple shippers that have designated a single 
agent on their behalf).
    \196\ See, e.g., Southern, 124 FERC ] 61,145 at P 12. As the 
Commission explained, multi-party contracts must include joint and 
several liability to comply with the Commission's shipper-must-have-
title policy. Without joint and several liability, shippers under 
the multi-party contracts that are not liable for the total charges 
under the agreement would be in violation of the Commission's 
shipper-must-have-title policy to the extent they used capacity in 
excess of that for which they were liable to pay.
    \197\ See, e.g., Florida Gas Transmission Co., LLC, 126 FERC ] 
61,055 (2009).
---------------------------------------------------------------------------

    129. This contracting flexibility has been utilized by entities to 
meet their collective load obligations in a more efficient manner. For 
example, certain affiliated utilities of Southern Company, which have 
long operated as an integrated public utility electric system through 
the joint commitment and economic dispatch of their gas-fired 
generating resources, have entered into a single interstate natural gas 
pipeline transportation service agreement, with Southern Company 
Services (their affiliated agent) arranging for the gas supplies used 
in their generating facilities.\198\ Under this single transportation 
service agreement, on any given day Southern Company Services can use 
up to its overall contractual entitlement under the service agreement 
to provide service to any one of its affiliated utilities.
---------------------------------------------------------------------------

    \198\ See, e.g., Southern Natural Gas Co., Transmittal, Docket 
No. RP01-205-016 (May 14, 2009); Southern, 124 FERC ] 61,145. The 
affiliates were Alabama Power Company, Georgia Power Company, Gulf 
Power Company, Mississippi Power Company, Savannah Electric and 
Power Company and Southern Power Company.
---------------------------------------------------------------------------

B. NOPR Proposal

    130. The NOPR proposed to revise Part 284 of the Commission's 
regulations to require interstate natural gas pipelines that offer firm 
transportation service under subpart B or G of Part 284 to allow 
multiple shippers associated with a designated agent or asset manager 
to be jointly and severally liable under a single firm transportation 
service agreement, subject to reasonable terms and conditions. 
Consistent with the multi-party contract tariff provisions the 
Commission previously approved, the NOPR stated that such reasonable 
terms and conditions may include requirements that: (1) The shippers 
and agent demonstrate their agency relationship in writing; and (2) the 
shippers are willing to be treated collectively as one shipper for 
nomination, allocation, and billing purposes under the contract.
    131. As explained in the NOPR, the use of shared capacity can make 
the purchase of firm pipeline capacity more affordable, including for 
gas-fired generators. For example, a gas-fired generator could decide 
to defray its pipeline capacity costs by sharing capacity among a 
number of generators or by sharing capacity with a LDC that has 
differing peak needs for natural gas transportation service. Similarly, 
an industrial plant, which has a relatively constant need for gas when 
its plant is operating but which has the flexibility to reduce its 
operations and gas usage on relatively short notice, could arrange to 
share its capacity with another shipper, such as a gas-fired generator, 
which only needs gas during short intervals and which has less control 
over when it runs. Permitting such entities to enter into a single 
contract with the pipeline gives those entities the flexibility to 
choose contracting partners with complementary needs for pipeline 
capacity and to enter into an ongoing contractual relationship 
concerning how they will share the capacity.
    132. The Commission's NOPR proposal would only require pipelines to 
offer multi-party service agreements for firm service because a primary 
benefit of such service agreements is that they permit entities to 
share firm capacity without the need to engage in capacity releases. 
However, in recognition of the fact that some pipelines currently offer 
multi-party service agreements to interruptible customers as well, the 
Commission requested comment on whether it should also require 
pipelines to offer multi-party service agreements for interruptible 
transportation service.

C. Comments

    133. Ten commenters either support or do not oppose the NOPR 
proposal.\199\ They contend that the proposal will provide shippers, 
including gas-fired generators, with greater flexibility and facilitate 
more efficient use of pipeline capacity.
---------------------------------------------------------------------------

    \199\ AGA Comments at 37-38; AGLR LDCs Comments at 3; Duke 
Comments at 4-5; FirstEnergy Comments at 9; MSCG Comments at 18; 
National Grid Comments at 5; New England LDCs at 34; NiSource 
Comments at 3; PUCO Comments at 8-9; Southern Star Comments at 6.
---------------------------------------------------------------------------

    134. Many commenters express varying degrees of qualified support 
for the NOPR proposal.\200\ IOGA asserts that the concept could be 
valuable not just for gas-fired generators, but also for small 
producers as an alternative to interruptible transportation and a tool 
to help optimize capacity and ensure that they have a firm outlet for 
gas.\201\ IOGA, along with EnerVest, urges the Commission, however, to 
grant blanket waivers of the shipper-must-have-title policy in order to 
facilitate multi-party transportation agreements.\202\ Several 
commenters argue that the Commission should leave it to individual 
pipelines to propose such services in response to customer needs.\203\ 
INGAA states that even on pipelines that currently allow multi-party 
contracts, customer response has been limited.\204\ INGAA requests that 
the Commission either reconsider the addition of section 
284.12(b)(1)(v) to the Commission's regulations or modify the 
regulatory text to provide that:
---------------------------------------------------------------------------

    \200\ AF&PA Comments at 4; BHE Comments at 17-18; EnerVest 
Comments at 7; IECA Comments at 2-4; INGAA Comments at 32-33; IOGA 
Comments at 5-6; Kinder Morgan Comments at 15; NGSA Comments at 24-
25; PGC Comments at 7; Spectra Comments at 9.
    \201\ IOGA Comments at 5-6.
    \202\ EnerVest Comments at 7-8; IOGA Comments at 6.
    \203\ Dominion Comments at 28-29; INGAA Comments at 31-32; 
Kinder Morgan Comments at 14-16; Southern Comments at 13.
    \204\ INGAA Comments at 31.

    Within 60 days upon a shipper request, a pipeline will file to 
make appropriate tariff changes at the Commission to allow multiple 
shippers associated with a designated agent or asset manager to be 
jointly and severally liable under a single firm transportation 
service agreement, subject to reasonable terms and conditions. 
---------------------------------------------------------------------------
(emphasis added)

    135. AF&PA, IECA, NGSA, and PGC support the concept of making 
multi-party transportation contracts more widely available, provided 
that the Commission can ensure that multi-party contracts are 
transparent, do not adversely affect existing shippers, comply with all 
pipeline tariffs, and do not unduly discriminate against other 
shippers.\205\ Along those lines, AF&PA, IECA, and PGC urge the 
Commission to clarify that individual shippers must be publicly 
disclosed, not just the designated contract agent or asset manager 
under the multi-party transportation contract.\206\ AF&PA, IECA, and 
NGSA also suggest that the

[[Page 23221]]

Commission should closely monitor and take action if increased 
utilization of multi-party contracts substantially reduces the 
competitiveness of the secondary market.\207\
---------------------------------------------------------------------------

    \205\ AF&PA Comments at 3-5; IECA Comments at 2-4; NGSA Comments 
at 24-26; PGC Comments at 6-8.
    \206\ AF&PA Comments at 3-5; IECA Comments at 2-4; PGC Comments 
at 6-8.
    \207\ AF&PA Comments at 3-5; IECA Comments at 2-4; NGSA Comments 
at 24-26.
---------------------------------------------------------------------------

    136. Other commenters urge the Commission to require certain 
provisions that have already been approved in other proceedings 
involving multi-party transportation contracts (e.g., shippers and 
agents must demonstrate their agency relationship in writing).\208\ BHE 
supports the NOPR proposal, provided the affected interstate natural 
gas pipelines are adequately protected financially by way of 
creditworthiness terms and conditions.\209\
---------------------------------------------------------------------------

    \208\ See, e.g., INGAA Comments at 32-33; Kinder Morgan Comments 
at 15; Spectra Comments at 9.
    \209\ BHE Comments at 18.
---------------------------------------------------------------------------

    137. Several commenters who support the concept of multi-party 
transportation contracts, nevertheless request a number of 
clarifications regarding the terms and conditions of service for multi-
party transportation contracts. MSCG urges the Commission to clarify 
scenarios involving liability, events of default, billing and payment, 
and shipper-must-have-title.\210\ NGSA requests several clarifications 
on confidentiality and the consolidation of existing agreements into a 
single multi-party transportation contract.\211\ Puget requests that 
the Commission clarify how capacity and costs are shared amongst the 
parties under a multi-party transportation agreement.\212\
---------------------------------------------------------------------------

    \210\ MSCG Comments at 18-19.
    \211\ NGSA Comments at 26.
    \212\ Puget Comments at 31-32.
---------------------------------------------------------------------------

    138. Some commenters assert that the Commission should convene 
technical conferences or workshops or perform further evaluation to 
further explore some of the issues discussed above and other 
implementation issues before adopting the proposed regulation.\213\
---------------------------------------------------------------------------

    \213\ Dominion Comments at 28-29; EEI Comments at 5-6; Exelon 
Comments at 12; Puget Comments at 32; Sequent Comments at 9-10; 
Southern Comments at 13-14.
---------------------------------------------------------------------------

    139. Idaho Power, Sequent, and Tenaska oppose the NOPR proposal, 
arguing that multi-party transportation contracts will not offer any 
additional benefits to the reliability of gas supply to generators than 
the Commission's current capacity release program or current pipeline 
service offerings.\214\ For example, Tenaska asserts that the NOPR's 
proposal would carve out an exception to the capacity release rules for 
multi-party transportation contracts and would depart from the goals of 
the program, including those regarding transparency, allocation to the 
party that values the released capacity the most, and by allowing 
private groups to control a certain amount of capacity outside of the 
capacity release process.\215\ Tenaska also states that the NOPR 
proposal does not address whether or how any amount of the shared 
capacity, once under a multi-party transportation contract, can be re-
released, or whether the designated agent or Asset Manager may use the 
capacity.
---------------------------------------------------------------------------

    \214\ Idaho Power Comments at 2; Sequent Comments at 8; Tenaska 
Comments at 5.
    \215\ Tenaska Comments at 6-7.
---------------------------------------------------------------------------

    140. Sequent is concerned that the parties to a multi-party service 
agreement could receive preferential treatment or status over non-
multi-party capacity bidders in terms of capacity allocation, posting 
and bidding rules (including those for affiliates), credit 
requirements, application of shipper-must-have-title policy, 
prohibition on buy-sell arrangements, tying and other capacity release 
requirements. Sequent also requests clarification regarding open 
seasons and the consolidation of existing transportation agreements 
into a single multi-party transportation contract.\216\
---------------------------------------------------------------------------

    \216\ Sequent Comments at 9.
---------------------------------------------------------------------------

    141. In response to the NOPR's question regarding whether the 
Commission should require pipelines to offer multi-party interruptible 
contracts, AF&PA, Duke, EnerVest, NGSA, and PGC support or do not 
oppose offering multi-party transportation contracts for interruptible 
service.\217\ However, Dominion, INGAA, and Kinder Morgan argue against 
it.\218\ EnerVest argues that, in the case of affiliated capacity-
sharing shippers, allowing a single affiliated agent or asset manager 
to interface with the pipeline in connection with interruptible 
transportation services would provide potential administrative benefits 
for both shippers and pipelines alike, and would contribute to greater 
efficiency in overall utilization of total interstate natural gas 
pipeline transportation capacity.\219\ To the contrary, INGAA argues 
that an interruptible transportation multi-party service agreement 
would not provide generators with any additional ability to offset the 
costs of holding an interruptible transportation contract, since there 
are none, and would not provide any additional incentives for 
generators to enter into an interruptible transportation agreement, 
since that incentive is there already.\220\ Dominion makes similar 
arguments.\221\
---------------------------------------------------------------------------

    \217\ AF&PA Comments at 5; Duke Comments at 5; EnerVest Comments 
at 9; NGSA Comments at 26; PGC Comments at 7 & n.7.
    \218\ Dominion Comments at 29; INGAA Comments at 33-34; Kinder 
Morgan Comments at 16.
    \219\ EnerVest Comments at 9.
    \220\ INGAA Comments at 33-34.
    \221\ Dominion Comments at 29.
---------------------------------------------------------------------------

D. Commission Determination

    142. In this Final Rule, the Commission adopts section 
284.12(b)(1)(iii) as proposed in the NOPR, with the modification 
requested by INGAA. Instead of requiring all interstate pipelines at 
this time to modify their tariffs to offer multi-party firm 
transportation contracts, the Commission will only require pipelines to 
offer such an option if requested to do so by a shipper. Specifically, 
section 284.12(b)(1)(iii) as adopted in this Final Rule, requires that 
within 60 days of a shipper request, a pipeline must file to make 
appropriate tariff changes to allow multiple shippers associated with a 
designated agent or asset manager to be jointly and severally liable 
under a single firm transportation service agreement, subject to 
reasonable terms and conditions.
    143. As noted by many commenters, the availability of multi-party 
firm transportation contracts will provide shippers, including gas-
fired generators, with greater flexibility and facilitate more 
efficient use of pipeline capacity. In addition, section 
284.12(b)(1)(iii) as adopted ensures that pipelines are responsive to 
shipper requests when, and if, a shipper is interested in pursuing a 
multi-party transportation agreement, while not requiring pipelines to 
implement tariff provisions offering that option where there is no 
shipper interest. Postponing implementation in this regard would not 
appear to unduly delay use of multi-party transportation contracts by 
interested shippers given the time necessarily involved in finalizing a 
multi-party arrangement,
    144. Upon an individual pipeline's filing to implement multi-party 
transportation contracts, customers and other interested persons will 
have the opportunity to raise any concerns regarding the pipeline's 
filing, including any accompanying terms and conditions proposed by the 
individual pipeline. Commenters who have raised questions or requested 
clarifications in this proceeding regarding accompanying terms and 
conditions, such as creditworthiness, capacity release, open seasons, 
existing agreements, events of default, liability, and billing and 
payment, will have the opportunity to seek such clarifications in the 
individual pipeline proceedings, thereby giving the individual pipeline

[[Page 23222]]

the first opportunity to address any such concerns.
    145. Tenaska and other commenters raise concerns regarding 
transparency and the impact of the multi-party transportation contracts 
on the capacity release market. In recent years, the Commission has 
accepted several pipeline proposals to offer multiple shippers the 
option of entering into a single contract for transportation service, 
with a single agent or asset manager managing the capacity under the 
contract.\222\ The Commission has received no indication of any 
problems surrounding such multi-party transportation contracts or of a 
negative impact on the capacity release market resulting from such 
contracts. Furthermore, as INGAA notes, customer use of such contracts 
has been limited.\223\ There are also safeguards in the revised 
regulatory text and under existing regulations. The revised regulatory 
text requires shippers under a multi-party contract to be jointly and 
severally liable in order to satisfy the Commission's shipper-must-
have-title policy, thereby limiting the option to shippers who value 
the capacity sufficiently to agree to be liable for all payments under 
the contract. Commission regulations also require that all interstate 
pipelines must publicly post information regarding any contract for 
firm transportation, or revision thereto, including shipper name and 
the rate charged under the contract.\224\ Interstate pipelines would 
continue to have this obligation with respect to multi-party 
transportation contracts, including posting the name of each shipper 
that is a party to the multi-party contract. With respect to concerns 
about undue discrimination or preference, section 4(b) of the NGA 
prohibits undue discrimination or preference by interstate pipelines. 
On balance, the Commission believes that the regulation adopted by this 
Final Rule, together with existing safeguards, strikes a reasonable 
balance between offering shippers greater contracting flexibility and 
protecting other shippers, as well as the pipeline. The Commission will 
also continue to monitor the use of multi-party transportation 
contracts.
---------------------------------------------------------------------------

    \222\ See, e.g., Southern, 124 FERC ] 61,145; Florida Gas, 128 
FERC ] 61,284, order on compliance filing, Docket No. RP09-922-001 
(Nov. 17, 2009) (delegated letter order); Transcontinental Gas Pipe 
Line Corp., Docket No. RP10-1099-000 (Sept. 14, 2010) (delegated 
letter order); Tennessee, 142 FERC ] 61,200.
    \223\ INGAA Comments at 31.
    \224\ See 18 CFR 284.13 (2014).
---------------------------------------------------------------------------

    146. The Commission denies EnerVert and IOGA's alternative request 
that the Commission grant a blanket waiver of the shipper-must-have-
title policy to permit shippers to more easily share capacity. As the 
Commission has previously explained, the capacity release program was 
designed with the shipper-must-have-title rule as its foundation. That 
rule ensures that transfers of capacity among shippers must take place 
through the capacity release program, thus ensuring that such capacity 
transfers are transparent and not unduly discriminatory.\225\ 
Therefore, the Commission will not grant a generic waiver of the 
shipper-must-have-title rule in this rulemaking proceeding. However, 
the Commission is open to considering requests for waiver of its 
capacity release regulations and/or the shipper-must-have-title rule on 
a case-by-case basis, where it is shown that such a waiver would be in 
the public interest, for example by assisting natural gas-fired 
generators in obtaining access to firm transportation service in a 
transparent and not unduly discriminatory manner.\226\
---------------------------------------------------------------------------

    \225\ Order No. 637, FERC Stats & Regs. ] 31,091 at 31,300 
(2000).
    \226\ See Georgia Pub. Serv. Comm'n, 107 FERC ] 61,024, at P 36 
(2004), reh'g granted in part, denied in part, 110 FERC ] 61,048 
(2005), reh'g denied, 111 FERC ] 61,178 (2005), and Promotion of a 
More Efficient Capacity Release Market, Order No. 712-A, FERC Stats. 
& Regs. ] 31,284, at P 146 (2008), order on reh'g and clarification, 
Order No. 712-B, 127 FERC ] 671,051 (2009).
---------------------------------------------------------------------------

    147. Several commenters raise questions regarding the rights and 
responsibilities of the individual parties to a multi-party 
transportation contract, as well as the responsibilities of the agent 
or asset manager. In general, rights and responsibilities related to 
the shippers' relationship to the pipeline will be determined by the 
individual pipeline's tariff, but rights and responsibilities as 
between the shippers and their agent or asset manager, such as how 
capacity is allocated between the contracting parties on any given day, 
will be determined by the parties and the agent or asset manager to the 
transportation contract.
    148. The Commission will not require multi-party service contracts 
for interruptible transportation. As INGAA points out, unlike firm 
shippers, interruptible shippers do not have any obligation to pay a 
monthly reservation charge and only pay transportation charges when 
they utilize the service. Thus, there is no existing financial 
impediment to generators or others entering into interruptible 
transportation contracts. Unlike multi-party contracts for firm 
service, an interruptible multi-party transportation contract would not 
provide generators with any additional ability to offset the costs of 
holding an interruptible transportation agreement. The limited 
administrative benefits identified by EnerVest do not appear to warrant 
requiring interstate pipelines to provide such contracts for 
interruptible transportation.

VII. Notice of Use of Voluntary Consensus Standards

    149. Office of Management and Budget Circular A-119 (Sec.  11) 
(February 10, 1998) provides that federal agencies issuing or revising 
regulations with a standard should publish a statement in the Final 
Rule identifying the adopted standard as being a voluntary consensus 
standard or a government-unique standard. In this Final Rule, the 
Commission is incorporating by reference voluntary consensus standards 
developed by the NAESB WGQ. In section 12(d) of NTT&AA, Congress 
affirmatively requires federal agencies to use technical standards 
developed by voluntary consensus standards organizations to carry out 
policy objectives or activities determined by the agencies unless use 
of such standards would be inconsistent with applicable law or 
otherwise impractical.\227\
---------------------------------------------------------------------------

    \227\ Pub. L. No. 104-113, 12(d), 110 Stat. 775 (1996), 15 
U.S.C. 272 note (1997).
---------------------------------------------------------------------------

VIII. Incorporation By Reference

    150. The Office of the Federal Register requires agencies 
incorporating material by reference in final rules to discuss, in the 
preamble of the final rule, the ways that the materials it incorporates 
by reference are reasonably available to interested parties and how 
interested parties can obtain the materials.\228\ The regulations also 
require agencies to summarize, in the preamble of the final rule, the 
material it incorporates by reference.
---------------------------------------------------------------------------

    \228\ 1 CFR 51.5 (2014). See Incorporation by Reference, 79 FR 
66267 (Nov. 7, 2014).
---------------------------------------------------------------------------

    151. The NAESB standards being incorporated by reference in this 
Final Rule are summarized in P 23, 87, 104. Our regulations provide 
that copies of the NAESB standards incorporated by reference may be 
obtained from the North American Energy Standards Board, 801 Travis 
Street, Suite 1675, Houston, TX 77002, Phone: (713) 356-0060. NAESB's 
Web site is at http://www.naesb.org/. Copies may be inspected at the 
Federal Energy Regulatory Commission, Public Reference and Files 
Maintenance Branch, 888 First Street NE., Washington, DC 20426, Phone: 
(202) 502-8371, http://www.ferc.gov.\229\
---------------------------------------------------------------------------

    \229\ 18 CFR 284.12 (2014).

---------------------------------------------------------------------------

[[Page 23223]]

    152. NAESB is a private consensus standards developer that develops 
voluntary wholesale and retail standards related to the energy 
industry. The procedures utilized by NAESB make its standards 
reasonably available to those affected by the Commission regulations. 
Participants can join NAESB, for an annual membership cost of only 
$7,000, which entitles them to full participation in NAESB and enables 
them to obtain these standards at no cost.\230\ Non-members may obtain 
the Individual Standards Manual or Booklets for each standard by email 
for $250 per manual or booklet, which in the case of these standards 
would total $1,000.\231\ Nonmembers also may obtain the complete set of 
Standards Manuals, Booklets, and Contracts on CD for $2,000. NAESB also 
provides a free electronic read-only version of the standards for a 
three business day period or, in the case of a regulatory comment 
period, through the end of the comment period.\232\ In addition, NAESB 
considers requests for waivers of the charges on a case by case basis 
depending on need. The parties affected by these Commission regulations 
are highly sophisticated and have the means to acquire the information 
they need to effectively participate in Commission proceedings.
---------------------------------------------------------------------------

    \230\ North American Energy Standards Board Membership 
Application, https://www.naesb.org/pdf4/naesbapp.pdf.
    \231\ NAESB Materials Order Form, https://www.naesb.org//pdf/ordrform.pdf.
    \232\ Procedures for non-members to evaluate work products 
before purchasing, https://www.naesb.org/misc/NAESB_Nonmember_Evaluation.pdf. See Incorporation by Reference, 79 
FR at 66271, n. 51 & 53 (Nov. 7, 2014) (citing to NAESB's procedure 
of providing ``no-cost, no-print electronic access'', NAESB Comment, 
at 1, available at http://www.regulations.gov/#!documentDetail;D=OFR-2013-0001-0023).
---------------------------------------------------------------------------

IX. Information Collection Statement

    153. The collections of information for this Final Rule are being 
submitted to the Office of Management and Budget (OMB) for review under 
section 3507(d) of the Paperwork Reduction Act of 1995 \233\ and OMB's 
implementing regulations.\234\ OMB must approve information collection 
requirements imposed by agency rules. The burden estimates for this 
Final Rule are for one-time implementation of the information 
collection requirements of this Final Rule (including tariff filing, 
documentation of the process and procedures, and IT work), and ongoing 
burden.
---------------------------------------------------------------------------

    \233\ 44 U.S.C. 3507(d) (2012).
    \234\ 5 CFR 1320 (2014).
---------------------------------------------------------------------------

    154. The Commission solicits comments from the public on the 
Commission's need for this information, whether the information will 
have practical utility, the accuracy of the burden estimates, 
recommendations to enhance the quality, utility, and clarity of the 
information to be collected, and any suggested methods for minimizing 
respondents' burden, including the use of automated information 
techniques. The burden estimates are for implementing the information 
collection requirements of this Final Rule. The Commission asks that 
any revised burden estimates submitted by commenters include the 
details and assumptions used to generate the estimates.
    155. The collections of information related to this Final Rule fall 
under FERC-545 (Gas Pipeline Rates: Rate Change (Non-Formal)) \235\ and 
FERC-549C (Standards for Business Practices of Interstate Natural Gas 
Pipelines).\236\ The following estimates of reporting burden are 
related only to this Final Rule and include the costs to pipelines to: 
(1) Incorporate by reference NAESB's modified nomination timeline, 
which includes: moving the start of the Timely Nomination Cycle from 
11:30 a.m. to 1:00 p.m. CCT and adding an additional intraday 
nomination opportunity; and (2) require interstate pipelines to file 
tariff changes with the Commission allowing multiple shippers 
associated with a designated agent or asset manager to be jointly and 
severally liable under a single firm transportation service agreement 
within 60 days of receiving a request from a shipper for a multi-party 
service agreement.
---------------------------------------------------------------------------

    \235\ FERC-545 covers rate change filings made by natural gas 
pipelines, including tariff changes.
    \236\ FERC-549C covers Standards for Business Practices of 
Interstate Natural Gas Pipelines.
    \237\ An estimated 165 natural gas pipelines (Part 284 program) 
are affected by this Rulemaking. Although the additional intraday 
nomination and the revised same-day and day-ahead trading schedules 
may affect electric plant operators, the Commission is not imposing 
the reporting burden of adopting these standards on those entities.
    \238\ The most recent hourly wage figures are published by the 
Bureau of Labor Statistics, U.S. Department of Labor, National 
Occupational Employment and Wage Estimates, United States, 
Occupation Profiles, May 2013, at http://www.bls.gov/oes/home.htm, 
and the benefits are calculated using BLS information, at http://www.bls.gov/news.release/ecec.nr0.htm. Each response to the proposed 
regulation in Column 1 is corresponds to a unique respondent.
    \239\ The average hourly burden cost (salary plus benefits) 
related to tariff filings is $70.58. This represents the average 
wage (salary and benefits) of the following occupational categories: 
``Lawyers'' ($128.94 per hour, top 10 percent of wage earners), 
``Computer Systems Analyst'' ($58.77 per hour, average composite 
hourly wage), and ``Office and Administrative'' ($24.04 per hour, 
average composite hourly wage). Wage data is available from the 
Bureau of Labor Statistics at http://www.bls.gov/oes/home.htm; 
background on the estimate of the benefits component is at http://www.bls.gov/news.release/ecec.nr0.htm.
    \240\ Some of the estimated 165 natural gas pipeline companies 
(Part 284 program) may already utilize business practices that 
satisfy the NAESB proposal elements of this Rulemaking (e.g., 
provide additional nomination opportunities). In these instances the 
full cost of industry compliance is estimated for the total number 
of potential respondents.
    \241\ The average (mean) hourly cost of tariff filings and 
implementation for interstate natural gas pipelines is $70.58. This 
represents the composite wage (salary and benefits) of the following 
occupational categories: ``Lawyers'' ($128.94 per hour, top 10 
percent of wage earners), ``Computer Systems Analyst'' ($58.77 per 
hour, average composite hourly wage), and ``Office and 
Administrative'' ($24.04 per hour, average composite hourly wage). 
Wage data is available from the Bureau of Labor Statistics at http://www.bls.gov/oes/home.htm; estimate of the benefits component at 
http://www.bls.gov/news.release/ecec.nr0.htm.
    \242\ A majority of the 165 potential respondents operate under 
tariffs filed with the Commission that include provisions for multi-
party transportation contracts. The Commission expects that 
approximately 8 of the 165 potential respondents (five percent), 
following an expression of shipper interest, will file tariffs each 
year with the Commission that support multi-party transportation 
contracts.
---------------------------------------------------------------------------

    Public Reporting Burden:

                                                                    RM14-2 Final Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                 Number of
                                                              Number of        responses per      Average burden       Total annual    Total annual cost
                                                          respondents \237\      respondent     hours per response     burden hours        ($) \238\
                                                                        (1)                (2)               (3)          (1)x(2)x(3)  .................
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       FERC-545 (OMB Control No. 1902-0154) \239\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Tariff Filing for new and revised Nomination Cycles (one-               165                  1                10                1,650     \241\ $116,457
 time) \240\............................................
Tariff Filing for Multi-Party Service Agreements (one-                    8                  1                10                   80              5,646
 time) \242\............................................
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 23224]]

 
                                                          FERC-549C (OMB Control No. 1902-0174)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Implementation of business standards, including process,                165                  1               240               39,600          2,524,500
 procedures, and IT support (one-time) \243\............
Annual operations, including 1 additional intraday                      165                365                 0.5             30,113          1,535,738
 nomination (ongoing) \244\.............................
                                                         -----------------------------------------------------------------------------------------------
    Total one-time (for FERC-545 and FERC-549C).........  .................  .................  ..................             39,680          2,646,603
                                                         -----------------------------------------------------------------------------------------------
    Total ongoing (for FERC-549C).......................  .................  .................  ..................             30,113          1,535,738
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Information Collection Costs: The Commission estimates the total 
costs for all respondents to be:
---------------------------------------------------------------------------

    \243\ The average hourly cost is $63.75. This represents the 
average wage (salary and benefits) of the following occupational 
categories: ``Lawyers'' ($128.94 per hour, top 10 percent of wage 
earners), ``Computer Systems Analyst'' ($58.77 per hour, average 
composite hourly wage), ``Gas Plant Operator'' ($43.24 per hour, 
average composite hourly wage), and ``Office and Administrative'' 
($24.04 per hour, average composite hourly wage).
    \244\ For ongoing operations, we estimate 0.5 hours per calendar 
day per respondent (or 182.5 hours annually per respondent).
    The average hourly cost is $51. This represents the average wage 
(salary and benefits) of the following occupational categories: 
``Computer Systems Analyst'' ($58.77 per hour), and ``Gas Plant 
Operator'' ($43.24 per hour).
---------------------------------------------------------------------------

     Year 1 (including the one-time tariff-filing, 
implementation, and ongoing costs): $4,182,341.
     Years 2 and 3, each (ongoing costs only): $1,535,738.
    Title: FERC-545, Gas Pipeline Rates: Rate Change (Non-Formal); and 
FERC-549C, Standards for Business Practices of Interstate Natural Gas 
Pipelines.
    Action: Proposed revisions to information collections.
    OMB Control Nos.: 1902-0154 (FERC-545) and 1902-0174 (FERC-549C).
    Respondents: Business or other for profit enterprise (Natural Gas 
Pipelines).
    Frequency of Responses: One-time filing and implementation and 
ongoing.
    Necessity of Information: This Final Rule will upgrade the 
Commission's current business practice and communication standards and 
supports the availability of multi-party firm contracts for interested 
shippers.
    156. In incorporating by reference NAESB's modified nomination 
timeline, including moving the start of the Timely Nomination Cycle 
from 11:30 a.m. to 1:00 p.m. CCT and adding an additional intraday 
nomination opportunity, the Commission intends to provide electric 
generators more time to acquire natural gas pipeline transportation, in 
order to reduce economic and resource supply constraints, additional 
flexibility to all shippers, allows sufficient time for processing, 
avoids overlapping nomination cycles, and allows for the accomplishment 
of most scheduling work during regular business hours, or reasonably 
close thereto.
    157. Broad industry consensus across the natural gas and electric 
industries during the NAESB deliberations supports the incorporation of 
the modified nomination timeline. The implementation of these standards 
and regulations will promote additional efficiency and reliability of 
the gas industry's operations.
    158. Finally, wider availability of multi-party firm transportation 
contracts provides shippers greater flexibility, including gas-fired 
generators, and facilitates the efficient use of pipeline capacity. The 
Final Rule ensures that pipelines are responsive to shipper requests 
when, and if, a shipper is interested in pursuing a multi-party 
transportation contract. As such, this Final Rule does not require 
pipelines to implement tariff provisions offering a multi-party 
transportation contract option when there is no shipper interest.
    Internal Review: The Commission has reviewed the proposed business 
practice standards of natural gas pipelines and has determined that the 
proposed revisions are necessary to establish more efficient 
coordination between the natural gas and electric industries, and to 
provide additional flexibility for all natural gas pipeline shippers. 
Requiring such information ensures common business practices for 
participants engaged in the sale of electric energy at wholesale and 
the transportation of natural gas. These requirements conform to the 
Commission's plan for efficient information collection, communication, 
and management within the natural gas pipeline industry. The Commission 
has assured itself, by means of its internal review, that there is 
specific, objective support for the burden estimates associated with 
the information requirements.
    159. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director, email: 
DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].
    160. Comments concerning the collections of information and the 
associated burden estimates should be sent to the Commission and to the 
Office of Management and Budget, Office of Information and Regulatory 
Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission, telephone: (202) 395-0710, fax: (202) 
395-4718]. For security reasons, comments to OMB should be submitted by 
email to: oira_submission@omb.eop.gov. Comments submitted to OMB should 
include OMB Control Numbers 1902-0154 and 1902-0174.

X. Environmental Analysis

    161. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\245\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a) of the Commission's

[[Page 23225]]

regulations, which provides a categorical exemption for actions that 
are clarifying, corrective, or procedural, or that do not substantively 
change the effect of legislation or regulations being amended, for 
information gathering, analysis, and dissemination, or for the sale, 
exchange, or transportation of natural gas under sections 4, 5, and 7 
of the Natural Gas Act that require no construction of facilities.\246\
---------------------------------------------------------------------------

    \245\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \246\ See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5), 380.4(a)(27) 
(2014).
---------------------------------------------------------------------------

XI. Regulatory Flexibility Act Certification

    162. The Regulatory Flexibility Act of 1980 (RFA) \247\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. The RFA 
mandates consideration of regulatory alternatives that accomplish the 
stated objectives of a rule and that minimize any significant economic 
impact on a substantial number of small entities. The Small Business 
Administration's (SBA) Office of Size Standards develops the numerical 
definition of a small business as matched to North American Industry 
Classification System Codes (NAICS).\248\ The SBA has established a 
size standard for pipelines transporting natural gas, stating that a 
firm is a small entity if its annual receipts (including those of its 
affiliates) are $27.5 million or less.\249\
---------------------------------------------------------------------------

    \247\ 5 U.S.C. 601-612.
    \248\ 13 CFR 121.101.
    \249\ U.S. Small Business Administration, Table of Small 
Business Size Standards for Pipeline Transportation of Natural Gas, 
NAICS Code 486210, available at https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf, Subsector 486.
    Matched to North American Industry Classification System Codes, 
Natural Gas Pipeline Transportation, NAICS Code 486210, page 27, 
July 14, 2014, available at https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf, Subsector 486.
---------------------------------------------------------------------------

    163. This Final Rule applies only to interstate natural gas 
pipelines. The Commission estimates that approximately 165 interstate 
pipeline entities are potential respondents subject to the data 
reporting requirements of FERC-545. For fiscal year 2013, the 
Commission estimates that 70 pipelines (42.4 percent of 165 potential 
respondents) not affiliated with larger companies had annual revenues 
less than $27.5 million or less and are defined by the SBA as ``small 
entities.'' \250\ The Commission anticipates that the estimated 
compliance cost of this Final Rule is $4,182,341 in Year 1 (an average 
of $25,348 per entity, including both one-time and ongoing costs), and 
$1,535,738 per year in Years 2 and 3 (or an annual average of $9,308 
per entity for ongoing cost), regardless of entity size. The Commission 
does not consider the estimated impact per company to be significant. 
Additionally, the incorporation by reference of the revised NAESB 
standards, which reflect broad support from both industries, helps 
ensure the reasonableness of these standards in this Final Rule. 
Pipelines will need to file new tariffs with the Commission only if a) 
they do not currently offer multi-party transportation contracts, and 
b) shippers request that the pipeline offer such contracts.
---------------------------------------------------------------------------

    \250\ Based on 13 CFR 121.201, Sectors 48-49, Subsector 486, 
NAICS Code 486210 for Pipeline Transportation of Natural Gas, the 
annual receipts indicate the maximum allowed for a concern and its 
affiliates to be considered ``small.''
---------------------------------------------------------------------------

    164. Accordingly, pursuant to Section 605(b) of the RFA,\251\ this 
Final Rule should not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \251\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

XII. Implementation Schedule

A. Comments

    165. Many commenters state that, to the extent the Commission 
adopts any changes to the gas scheduling timeline in this proceeding, 
the Commission must allow a sufficient time for implementation. INGAA, 
Kinder Morgan, and WBI state that scheduling changes would require a 
minimum of nine months to implement.\252\ A number of commenters also 
state that it will be important to implement any scheduling changes 
adopted in this proceeding when natural gas demand is low.\253\ INGAA 
states that any transition should occur outside the winter heating 
season (November through March) or summer peak season (May through 
August).\254\ April or October was suggested by INGAA.
---------------------------------------------------------------------------

    \252\ INGAA Comments at 34-35; Kinder Morgan Comments at 16-17; 
WBI Comments at 8-9.
    \253\ See, e.g., Calpine Comments at 14, Exelon Comments at 12; 
WBI Comments at 8 (citing Section 206 Order, 146 FERC ] 61,202).
    \254\ INGAA Comments at 35.
---------------------------------------------------------------------------

    166. AGA, EEI and Calpine contend that implementation of the 
changes to the natural-gas system as ordered in the Final Rule should 
occur concurrently with the implementation of the changes to electric 
system as ordered in the forthcoming ISO and RTO filings pursuant to 
the Section 206 Order.\255\
---------------------------------------------------------------------------

    \255\ Calpine Comments at 17; EEI Comments at 7; NGSA Comments 
at 36.
---------------------------------------------------------------------------

    167. NAESB explains that upon the issuance of a Final Rule, NAESB 
will respond by integrating the Commission's regulations into its 
standards within 90 days.\256\ However, NAESB notes that, while it will 
likely be able to respond to the Final Rule within the 90 day deadline 
if it can use the expedited NAESB Minor Correction Process, if the 
NAESB Standards Development Process is used to respond to the Final 
Rule it may be challenging to meet the deadline. NAESB states that 
under the latter process multiple industry and member review periods 
are required and past expedited efforts have not been completed in 
under 90 days.
---------------------------------------------------------------------------

    \256\ NAESB November 26, 2014 Report at 1-2.
---------------------------------------------------------------------------

B. Commission Determination

    168. The Commission will require interstate natural gas pipelines 
to comply with the revised NAESB standards that we are incorporating by 
reference in this Final Rule beginning on April 1, 2016. We are 
requiring this implementation schedule to give the interstate natural 
gas pipelines subject to these standards adequate time to implement 
these changes. In addition, pipelines must file tariff records to 
reflect the changed standards by February 1, 2016. The changes included 
in this Final Rule should benefit all pipeline shippers, including gas-
fired generators. Accordingly, we will not require that the changes 
included in this Final Rule be implemented simultaneously with any 
changes resulting from the 206 Proceeding.
    169. In addition, consistent with the requirements in Order No. 
587-V,\257\ the Commission is including the following compliance filing 
requirements to increase the transparency of the pipelines' 
incorporation by reference of the NAESB WGQ Standards so that shippers 
and the Commission will know which tariff provision(s) implements each 
standard as well as the status of each standard.
---------------------------------------------------------------------------

    \257\ Standards for Business Practices of Interstate Natural Gas 
Pipelines, Order No. 587-V, FERC Stats. & Regs. ] 31,332, at PP 36-
37 (2012).
---------------------------------------------------------------------------

    (1) The pipelines must designate a single tariff section or tariff 
sheet(s) under which every NAESB standard is listed.\258\
---------------------------------------------------------------------------

    \258\ This section should be a separate tariff record under the 
Commission's electronic tariff filing requirements and is to be 
filed electronically using the eTariff portal using the Type of 
Filing Code 580.
---------------------------------------------------------------------------

    (2) For each standard, each pipeline must specify in the tariff 
section or tariff sheet(s) listing all the NAESB standards:
    (a) Whether the standard is incorporated by reference;
    (b) for those standards not incorporated by reference, the tariff 
provision that complies with the standard; \259\ and
---------------------------------------------------------------------------

    \259\ For example, pipelines are required to include the full 
text of the NAESB nomination and capacity release timeline standards 
(WGQ Standards 1.3.2(i-v) and 5.3.2) in their tariffs. Standards for 
Business Practices of Interstate Natural Gas Pipelines, Order No. 
587-U, FERC Stats. & Regs. ] 31,307, at P 39 & n.42 (2010). The 
pipeline would indicate which tariff provision complies with each of 
these standards.

---------------------------------------------------------------------------

[[Page 23226]]

    (c) a statement identifying any standards for which the pipeline 
has been granted a waiver, extension of time, or other variance with 
respect to compliance with the standard.\260\
---------------------------------------------------------------------------

    \260\ Shippers can use the Commission's electronic tariff system 
to locate the tariff record containing the NAESB standards, which 
will indicate the docket in which any waiver or extension of time 
was granted.
---------------------------------------------------------------------------

    (3) If the pipeline is requesting a continuation of an existing 
waiver or extension of time, it must include a table in its transmittal 
letter that states the standard for which a waiver or extension of time 
was granted, and the docket number or order citation to the proceeding 
in which the waiver or extension was granted.
    170. This information will give Commission staff and all shippers a 
common location that identifies the manner in which the pipeline is 
incorporating all the NAESB WGQ Standards and the standards with which 
it is required to comply. The Commission will post on its eLibrary Web 
site (under Docket No. RM14-2-000) a sample tariff record, to provide 
filers an illustrative example to aid them in preparing their 
compliance filings.
    171. To reflect our decision in this Final Rule not to change the 
start of the Gas Day, NAESB will need to change its standards to 
reflect the start of the Gas Day at 9:00 a.m. CCT. Once NAESB has 
informed the Commission that it has revised its standards to make this 
change, we will incorporate these revised NAESB standards by reference 
into our regulations in an instant Final Rule.

XIII. Document Availability

    172. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington DC 20426.
    173. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    174. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

XIV. Effective Date and Congressional Notification

    175. This final rule is effective July 8, 2015. The incorporation 
by reference of certain publications listed in this rule is approved by 
the Director of the Federal Register as of July 8, 2015. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this rule is not a 
``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.\261\ This final rule is 
being submitted to the Senate, House, and Government Accountability 
Office.
---------------------------------------------------------------------------

    \261\ 5 U.S.C. 804(2).
---------------------------------------------------------------------------

List of Subjects in 18 CFR Part 284

    Natural gas, Reporting and recordkeeping requirements, 
Incorporation by reference.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends Part 284, 
Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 284--CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE 
NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES

0
1. The authority citation for part 284 continues to read as follows:

    Authority: 15 U.S.C. 717-717z, 3301-3432; 42 U.S.C. 7101-7352; 
43 U.S.C. 1331-1356.

0
2. Amend Sec.  284.12 by revising paragraphs (a)(1) introductory text 
and (a)(1)(vi) and (vii) and by adding paragraphs (a)(1)(viii) and (ix) 
and (b)(1)(iii) to read as follows:

Sec.  284.12  Standards for pipeline business operations and 
communications.

    (a) * * *
    (1) An interstate pipeline that transports gas under subparts B or 
G of this part must comply with the business practices and electronic 
communications standards as promulgated by the North American Energy 
Standards Board, as incorporated herein by reference in paragraphs 
(a)(1)(i) through (vii) of this section, and as revised by WGQ 2014 
Annual Plan Item 11c and Minor Correction MC14018, as incorporated 
herein by reference in paragraphs (a)(1)(viii) and (ix) of this 
section.
* * * * *
    (vi) Capacity Release Related Standards (Version 2.0, November 30, 
2010, with Minor Corrections Applied Through January 5, 2012);
    (vii) Internet Electronic Transport Related Standards (Version 2.0, 
November 30, 2010, with Minor Corrections Applied Through January 2, 
2011) with the exception of Standard 10.3.2;
    (viii) WGQ 2014 Annual Plan Item 11c, Parts 1 and 2 (September 22, 
2014); and
    (ix) Minor Correction/Clarification, Request No. MC14018 Approved 
September 10, 2014.
* * * * *
    (b) * * *
    (1) * * *
    (iii) Within 60 days after a shipper request, a pipeline must file 
to make appropriate tariff changes at the Commission to allow multiple 
shippers associated with a designated agent or asset manager to be 
jointly and severally liable under a single firm transportation service 
agreement, subject to reasonable terms and conditions.
* * * * *

    Note: The following appendix will not appear in the Code of 
Federal Regulations.

APPENDIX

------------------------------------------------------------------------
                                  Current NAESB         Revised NAESB
 Time shifts--all times CCT         standards             standards
------------------------------------------------------------------------
Timely:
    Timely Day-Ahead          11:30 AM............  1:00 PM
     Nomination Deadline.

[[Page 23227]]

 
    Confirmations...........  ....................  4:30 PM
    Schedule Issued.........  4:30 PM.............  5:00 PM
    Start of Gas Flow.......  9:00 AM.............
Evening:
    Evening Day-Ahead         6:00 PM.............  6:00 PM
     Nomination Deadline.
    Confirmations...........  9:00 PM.............  8:30 PM
    Schedule Issued.........  10:00 PM............  9:00 PM
    Start of Gas Flow.......  9:00 AM.............
Intraday 1:
    ID1 Nomination Deadline.  10:00 AM............  10:00 AM
    Confirmations...........  1:00 PM.............  12:30 PM
    Schedule Issued.........  2:00 PM.............  1:00 PM
    Start of Gas Flow.......  5:00 PM.............  2:00 PM
    IT Bump Rights..........  bumpable............  bumpable.
Intraday 2:
    ID2 Nomination Deadline.  5:00 PM.............  2:30 PM
    Confirmations...........  8:00 PM.............  5:00 PM
    Schedule Issued.........  9:00 PM.............  5:30 PM
    Start of Gas Flow.......  9:00 PM.............  6:00 PM
    IT Bump Rights..........  no bump.............  bumpable.
Intraday 3:
    ID3 Nomination Deadline.  ....................  7:00 PM
    Confirmations...........  ....................  9:30 PM
    Schedule Issued.........  ....................  10:00 PM
    Start of Gas Flow.......  ....................  10:00 PM
    IT Bump Rights..........  ....................  no bump.
------------------------------------------------------------------------

[FR Doc. 2015-09275 Filed 4-23-15; 8:45 am]
 BILLING CODE 6717-01-P