Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 58393-58405 [2015-24283]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 80, Number 188 (Tuesday, September 29, 2015)]
[Proposed Rules]
[Pages 58393-58405]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-24283]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM15-24-000]


Settlement Intervals and Shortage Pricing in Markets Operated by 
Regional Transmission Organizations and Independent System Operators

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
proposing to revise its regulations to require that each regional 
transmission organization (RTO) and independent system operator (ISO) 
settle energy

[[Page 58394]]

transactions in its real-time markets at the same time interval it 
dispatches energy and settle operating reserves transactions in its 
real-time markets at the same time interval it prices operating 
reserves. The Commission also proposes to revise its regulations to 
require that each RTO/ISO trigger shortage pricing for any dispatch 
interval during which a shortage of energy or operating reserves 
occurs. Adopting these reforms would align prices with resource 
dispatch instructions and operating needs, providing appropriate 
incentives for resource performance.

DATES: Comments are due November 30, 2015.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways:
     Electronic Filing through https://www.ferc.gov. Documents 
created electronically using word processing software should be filed 
in native applications or print-to-PDF format and not in a scanned 
format.
     Mail/Hand Delivery: Those unable to file electronically 
may mail or hand-deliver comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT:
Stanley Wolf (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-6841, stanley.wolf@ferc.gov.
Eric Vandenberg (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-6283, eric.vandenberg@ferc.gov.
Joshua Kirstein (Legal Information), Office of General Counsel, Federal 
Energy Regulatory Commission, 888 First Street, NE., Washington, DC 
20426, (202) 502-8519, joshua.kirstein@ferc.gov.

SUPPLEMENTARY INFORMATION: 

 
                            Table of Contents
 
                                                              Paragraph
                                                               Numbers
 
I. Background..............................................          11.
II. Discussion.............................................          14.
    A. Settlement Intervals................................          15.
        1. Comments on Settlement Intervals................          16.
        2. Need for Reform of Settlement Intervals.........          26.
        3. Commission Proposal.............................          34.
    B. Shortage Pricing Triggers...........................          41.
        1. Comments on Shortage Pricing Triggers...........          41.
        2. Need for Reform of Shortage Pricing Triggers....          46.
        3. Commission Proposal.............................          51.
III. Compliance............................................          55.
IV. Information Collection Statement.......................          58.
V. Regulatory Flexibility Act Certification................          63.
VI. Environmental Analysis.................................          65.
VII. Comment Procedures....................................          66.
VIII. Document Availability................................          70.
Regulatory Text............................................
APPENDIX A: List of Short Names/Acronyms of Commenters.....
 

    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) is proposing to address two existing 
practices that may fail to compensate resources at prices that reflect 
the value of the service resources provide to the system, thereby 
distorting price signals. In certain instances, this creates a 
disincentive for resources to respond to dispatch signals. The 
Commission proposes to require that each regional transmission 
organization (RTO) and independent system operator (ISO) align 
settlement and dispatch intervals by settling energy transactions in 
its real-time markets at the same time interval it dispatches energy 
and settling operating reserves transactions in its real-time markets 
at the same time interval it prices operating reserves.\1\ The 
Commission is also proposing to require that each RTO/ISO trigger 
shortage pricing \2\ for any dispatch interval during which a shortage 
of energy or operating reserves \3\ occurs.
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    \1\ In this NOPR, the Commission sometimes uses the term 
``dispatch'' as shorthand when describing how RTOs/ISOs acquire and 
price energy and operating reserves. We clarify that our proposal 
with respect to operating reserves refers to the intervals at which 
they are acquired and priced. For instance, the Commission does not 
use the term ``dispatch'' to refer to the four-to-five second signal 
sent to resources on Automatic Generation Control.
    \2\ Shortage pricing is triggered under two general scenarios: 
when the system operator does not have enough resources available to 
meet energy and operating reserve requirements, and when an RTO or 
ISO establishes a price above which it will choose to be deficient 
of operating reserves rather than procure resources that may be 
available to meet the minimum requirement, but cost more than the 
established price. Federal Energy Regulatory Commission, Price 
Formation in Organized Wholesale Electricity Markets: Staff Analysis 
of Shortage Pricing, Docket No. AD14-14-000, at 9 (Oct. 2014), 
available at https://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricing-rto-iso-markets.pdf (Shortage Pricing Paper).
    \3\ The Commission's regulations define an operating reserve 
shortage as ``a period when the amount of available supply falls 
short of demand plus the operating reserve requirement.'' 18 CFR 
35.28(b)(6).
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    2. The Commission requires that rates for jurisdictional 
electricity service be just and reasonable and not unduly 
discriminatory or preferential. This requirement extends to market- and 
cost-based rates. The Commission has taken action to correct rates that 
become unjust and unreasonable, and has done so not only when the rates 
do not reflect costs but also when the underlying features, rate 
design, or market design fail to align.\4\ It is paramount that 
resources have appropriate incentives to

[[Page 58395]]

respond to an energy or operating reserve shortage and that each 
resource is compensated based on a price that reflects the value of the 
service it provides.
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    \4\ See, e.g., Frequency Regulation Compensation in the 
Organized Wholesale Power Markets, Order No. 755, FERC Stats. & 
Regs. ] 31,324, at P 3 (2011), order on reh'g, Order No. 755-A, 138 
FERC ] 61,123 (2012) (``requir[ing] RTOs and ISOs to compensate 
frequency regulation resources based on the actual service provided, 
including a capacity payment that includes the marginal unit's 
opportunity costs and a payment for performance that reflects the 
quantity of frequency regulation service provided by a resource when 
the resource is accurately following the dispatch signal'').
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    3. It has become apparent that there are instances in which certain 
current RTO/ISO practices may fail to reflect the value of providing a 
given service, thereby distorting price signals and failing to provide 
appropriate signals for resources to respond to the actual operating 
needs of the market. One such practice that the Commission has 
identified and proposes to reform occurs when RTOs/ISOs dispatch 
resources every five minutes but perform settlements based on an hourly 
integrated price.\5\ This misalignment between dispatch and settlement 
intervals may distort the price signals sent to resources and fail to 
reflect the actual value of resources responding to operating needs 
because compensation will be based on average output and average prices 
across an hour rather than output and prices during the periods of 
greatest need within a particular hour.
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    \5\ Hourly integrated prices are equal to the average price of 
all the individual dispatch intervals across an hour.
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    4. The Commission also preliminarily finds that a second problem 
occurs if there is a delay between the time when a system experiences a 
shortage of energy and operating reserves and the time when prices 
reflect the shortage condition. This can be particularly problematic 
when, for example, a shortage is required to last a minimum time period 
before shortage pricing is triggered. In this instance, short-term 
prices may fail to reflect potential reliability costs, as well as the 
value of both internal and external market resources responding to a 
dispatch signal.
    5. To address the problems associated with differing dispatch 
intervals and settlement intervals, as well as with shortage pricing 
triggers, the Commission proposes to require that each RTO/ISO (1) 
settle energy transactions in its real-time markets at the same time 
interval it dispatches energy and settle operating reserves 
transactions in its real-time markets at the same time interval it 
prices operating reserves, and (2) trigger shortage pricing for any 
dispatch interval during which a shortage of energy or operating 
reserves occurs.\6\ The settlement interval and shortage pricing 
reforms proposed herein will help ensure that resources have price 
signals that provide incentives to conform their output to dispatch 
instructions, and that prices reflect operating needs at each dispatch 
interval.
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    \6\ Operating reserves refer to certain ancillary services 
procured in the wholesale market that have different definitions in 
each RTO/ISO. Operating reserves typically include:
    (a) Regulating Reserve, used to account for very short-term 
deviations between supply and demand (e.g. 4 to 6 seconds); (b) 
Spinning, or Synchronous Reserve, which is capacity held in reserve 
and synchronized to the grid and able to respond within a relatively 
short amount of time (e.g., within 10 minutes), to be used in case 
of a contingency, such as the loss of a generator; and, (c) Non-
Spinning Reserve, capacity that is not synchronized to the grid and 
which can take longer to respond (e.g., within 10-30 minutes) in 
case of a contingency.
    Federal Energy Regulatory Commission, Price Formation in 
Organized Wholesale Electricity Markets: Staff Analysis of Shortage 
Pricing, Docket No. AD14-14-000, at 3 n.7 (Oct. 2014), available at 
https://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricing-rto-iso-markets.pdf (Shortage Pricing Paper).
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    6. In Docket No. AD14-14-000, the Commission initiated a proceeding 
to evaluate issues regarding price formation in the energy and 
ancillary services markets operated by RTOs/ISOs (price formation 
proceeding). The Commission stated that the goals of price formation 
are to (1) maximize market surplus for consumers and suppliers; (2) 
provide correct incentives for market participants to follow commitment 
and dispatch instructions, make efficient investments in facilities and 
equipment, and maintain reliability; (3) provide transparency so that 
market participants understand how prices reflect the actual marginal 
cost of serving load and the operational constraints of reliably 
operating the system; and (4) ensure that all suppliers have an 
opportunity to recover their costs.\7\
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    \7\ See Notice Inviting Post-Technical Workshop Comments, Docket 
No. AD14-14-000, at 2 (Jan. 16, 2015); Notice, Docket No. AD14-14-
000 (June 19, 2014).
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    7. The action the Commission takes herein is the first step to 
advancing the goals of the Commission's price formation proceeding. The 
Commission expects to undertake further action addressing various price 
formation topics, including offer price caps, mitigation, uplift 
transparency, and uplift drivers. The proposed reforms in this NOPR 
advance at least two of the Commission's goals with respect to price 
formation. Specifically, the proposed reforms will help provide correct 
incentives for market participants to follow commitment and dispatch 
instructions, to make efficient investments in facilities and 
equipment, and to maintain reliability. The proposed reforms will also 
help provide transparency and certainty so that market participants 
understand how prices reflect the actual marginal cost of serving load 
and the operational constraints of reliably operating the system. Price 
signals that reflect operating needs and system conditions would 
enhance incentives for resources to respond to dispatch 
instructions.\8\ In the long-term, the Commission expects that 
appropriate price signals would produce prices that consistently 
reflect operating needs and system conditions which, in turn, would 
help to encourage efficient investments in facilities and equipment, 
enabling reliable service.\9\
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    \8\ The Commission notes that the reforms proposed herein would 
further augment existing mechanisms in each RTO/ISO market that 
provide incentives to follow dispatch instructions, such as 
penalties for excessive or deficient energy and the allocation of 
commitment and dispatch costs to deviations from energy dispatch 
targets. See, e.g., MISO, FERC Electric Tariff, Sec. Sec.  40.3.3(a) 
(36.0.0) (allocating Revenue Sufficiency Guarantee costs to, inter 
alia, resources providing excessive or deficient energy), 40.3.4 
(33.0.0) (charges for excessive or deficient energy deployment).
    \9\ See, e.g., Scarcity and Shortage Pricing, Offer Mitigation 
and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 42:13-19 (Oct. 
28, 2014).
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    8. Requiring settlement intervals to match dispatch intervals would 
make resource compensation more transparent by, among other things, 
increasing the proportion of resource payment provided through payments 
of energy and operating reserves rather than uplift.\10\ Apportioning a 
greater proportion of a resource's revenue through payments for energy 
and operating reserves, rather than through uplift payments, increases 
transparency to the market by reflecting the costs of meeting system 
needs in settlement prices that are factored into a market price. In 
contrast, uplift payments bundle together a multitude of costs that are 
not factored into a market price. This increased transparency, in turn, 
better informs decisions to build or maintain resources and enhances 
consumers' ability to hedge. The benefits summarized above and 
discussed in detail below would ultimately help to ensure just and 
reasonable rates.
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    \10\ RTOs and ISOs provide make-whole payments, or uplift 
payments, to resources whose commitment and dispatch resulted in a 
shortfall between the resource's offer and the revenue earned 
through market clearing prices. See, e.g., Federal Energy Regulatory 
Commission, Price Formation in Organized Wholesale Electricity 
Markets: Staff Analysis of Uplift in RTO and ISO Markets, Docket No. 
AD14-14-000, at 2 (Aug. 2014), available at https://www.ferc.gov/legal/staff-reports/2014/08-13-14-uplift.pdf (Uplift Paper).
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    9. Implementing shortage pricing for any dispatch interval during 
which a shortage of energy or operating reserves occurs would provide 
an incentive for resources to ensure that they are available to respond 
to high prices, which should help alleviate shortages

[[Page 58396]]

and avoid shortage pricing during subsequent dispatch intervals. This 
reform would also ensure that resources operating during a shortage are 
compensated for the value of the service that they provide, regardless 
of whether the shortage is short-lived.
    10. The Commission seeks comment on these proposed reforms sixty 
(60) days after publication of this NOPR in the Federal Register.

I. Background

    11. The Commission has addressed price formation in organized 
markets on prior occasions. In Order No. 719, the Commission addressed 
shortage pricing \11\ and required RTOs/ISOs to develop and implement 
shortage pricing rules that would apply during operating reserve 
shortages to ``ensure that the market price for energy reflects the 
value of energy during an operating reserve shortage.'' \12\ The 
Commission required such rules out of concern that inappropriate price 
signals during an operating reserve shortage would provide an 
insufficient incentive for market participants to take appropriate 
actions.
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    \11\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719, FERC Stats. & Regs. ] 31,281, at PP 192-194 
(2008), order on reh'g, Order No. 719-A, FERC Stats. & Regs. ] 
31,292, order on reh'g, Order No. 719-B, 129 FERC ] 61,252 (2009).
    \12\ Id. P 194.
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    12. On June 19, 2014, the Commission initiated the price formation 
proceeding. In initiating that proceeding, the Commission stated that 
there may be opportunities for the RTOs/ISOs to improve the energy and 
ancillary service price formation process. The Commission explained 
that locational marginal prices (LMPs) used in energy and ancillary 
services markets ideally ``would reflect the true marginal cost of 
production, taking into account all physical system constraints, and 
these prices would fully compensate all resources for the variable cost 
of providing service.'' \13\ The Commission directed staff to conduct 
outreach and to convene technical workshops on the following four 
general issues: (1) Use of uplift payments; (2) offer price mitigation 
and offer price caps; (3) scarcity and shortage pricing; and (4) 
operator actions that affect prices.\14\ During the fall of 2014, staff 
convened technical workshops and issued reports on these topics. In one 
of those reports, issued in October 2014, staff analyzed shortage 
pricing issues.\15\
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    \13\ Notice, Docket No. AD14-14-000, at 2 (June 19, 2014).
    \14\ Id. at 1, 3-4.
    \15\ See Shortage Pricing Paper.
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    13. In its January 2015 Notice Inviting Comments, the Commission 
invited comments on specific questions that arose from the price 
formation technical workshops.\16\ In response, among other price 
formation issues, commenters addressed settlement intervals and 
shortage pricing, as detailed below.
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    \16\ Notice Inviting Post-Technical Workshop Comments, Docket 
No. AD14-14-000 (Jan. 16, 2015). A list of commenters and the 
abbreviated names the Commission will use for them in this document 
appears in Appendix A.
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II. Discussion

    14. In the following section, for each of the two proposals, the 
Commission first summarizes the views of commenters in the price 
formation proceeding on settlement intervals and triggers for shortage 
pricing. The Commission then explains the need for the reform set forth 
in the proposal and describes the proposed reform in detail. To remedy 
the potential unjust and unreasonable rates that are based on the use 
of hourly integrated prices for settlement as well as on restrictions 
on shortage pricing discussed more fully herein, the Commission 
proposes, pursuant to section 206 of the Federal Power Act (FPA),\17\ 
to require that each RTO/ISO (1) settle energy transactions in its 
real-time markets at the same time interval it dispatches energy and 
settle operating reserves transactions in its real-time markets at the 
same time interval it prices operating reserves, and (2) trigger 
shortage pricing for any dispatch interval during which a shortage of 
energy or operating reserves occurs.\18\
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    \17\ 16 U.S.C. 824e.
    \18\ The Commission is not at this time proposing to change the 
price paid by any RTO/ISO when shortage pricing is triggered.
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A. Settlement Intervals

    15. Some RTOs/ISOs do not settle resources at the same intervals at 
which they dispatch resources in their real-time energy markets.\19\ 
Rather, they settle resources based on hourly average prices, as shown 
below.
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    \19\ California Independent System Operator Corporation (CAISO), 
New York Independent System Operator, Inc. (NYISO), and Southwest 
Power Pool, Inc. (SPP) currently use a settlement interval that 
matches the dispatch interval. ISO New England Inc. (ISO-NE) and 
Midcontinent Independent System Operator, Inc. (MISO) are 
considering moving to five-minute settlements. PJM Interconnection, 
L.L.C. (PJM) has stated that PJM settles hourly and does not 
currently anticipate proposing to move to a different interval. See 
Scarcity and Shortage Pricing, Offer Mitigation and Offer Caps 
Workshop, Docket No. AD14-14-000, Tr. 52:21-53:1, 53:11-54:11, 
54:22-55:10 (Oct. 28, 2014).

           Table 1--RTO/ISO Dispatch and Settlement Intervals
------------------------------------------------------------------------
                                    Real-time
                                  dispatch \20\    Real-time settlement
                                    (minutes)              \21\
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CAISO..........................               5  5 minute.
ISO-NE.........................               5  hourly average.
MISO...........................               5  hourly average.
NYISO..........................               5  5 minute.
PJM............................               5  hourly average.
SPP............................               5  5 minute.
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1. Comments on Settlement Intervals
    16. In the price formation proceeding, commenters discussed using 
shorter settlement intervals (i.e., sub-hourly) and provided 
implementation and transition recommendations.
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    \20\ See CAISO, eTariff, Sec.  34.5 (17.0.0); ISO-NE., 
Transmission, Markets and Services Tariff, Market Rule 1, Sec.  
III.2.3 (15.0.0); MISO, FERC Electric Tariff, Sec.  40.2 (34.0.0); 
NYISO Markets and Services Tariff, Sec.  4.4.2.1 (17.0.0); PJM OATT, 
Attachment K, Appendix, Sec.  2.3 (2.0.0); SPP, OATT, Sixth Revised 
Volume No. 1, Attachment AE, Sec.  6.2.2 (1.0.0).
    \21\ See CAISO, eTariff, Sec.  11.5 (2.0.0), Appendix A, 
Settlement Interval (2.0.0); ISO-NE., Transmission, Markets and 
Services Tariff, Market Rule 1, Sec.  III.2.2(b) (15.0.0); MISO, 
FERC Electric Tariff, Sec. Sec.  40.3 (32.0.0), 40.3.1 (32.0.0), 
40.3.3 (36.0.0); NYISO, NYISO Tariffs, NYISO Markets and Services 
Tariff, Sec. Sec.  4.4.2.1, 4.4.2.8 (17.0.0); PJM, Intra-PJM 
Tariffs, OATT, Attachment K, Appendix, Sec. Sec.  2.5(e), (4.0.0), 
3.2.1(e), (f) (28.0.0); SPP, OATT, Sixth Revised Volume No. 1, 
Attachment AE, Sec. Sec.  8.6, 8.6.1 (2.1.0). The above-tariff 
citations refer to internal transactions. CAISO settles its intertie 
interchange transactions on fifteen-minute intervals. See CAISO, 
CAISO eTariff, HASP Block Intertie Schedule (0.0.0).
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    17. Commenters in support of sub-hourly settlements describe 
general benefits, as well as specific related improvements, from the 
adoption of sub-hourly settlements. Commenters from a broad range of 
the industry state that sub-hourly settlement intervals would provide 
significant benefits to the market by compensating resources fully for 
their flexibility and ability to follow dispatch instructions. 
According to these commenters, sub-hourly settlement intervals would 
permit resources to be rewarded for their ability to perform by earning 
greater revenues when prices fluctuate, which in the long run should 
induce more flexibility from new and existing resources and eventually 
lower dispatch costs and improve reliability.\22\
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    \22\ See, e.g., ANGA Comments, Docket No. AD14-14-000, at 3-4 
(Mar. 6, 2015); Brookfield Comments, Docket No. AD14-14-000, at 8 
(Mar. 6, 2015); Calpine Comments, Docket No. AD14-14-000, at 11-12 
(Mar. 6, 2015); Entergy Nuclear Power Marketing Comments, Docket No. 
AD14-14-000, at 12 (Mar. 6, 2015); Exelon Comments, Docket No. AD14-
14-000, at 19 (Mar. 6, 2015); GDF SUEZ Comments, Docket No. AD14-14-
000, at 9-10 (Mar. 6, 2015); ISO-NE Comments, Docket No. AD14-14-
000, at 20-22 (Mar. 6, 2015); MISO Comments, Docket No. AD14-14-000, 
at 16-17 (Mar. 6, 2015); New York Transmission Owners Comments, 
Docket No. AD14-14-000, at 9 (Mar. 6, 2015); NYISO Comments, Docket 
No. AD14-14-000, at 12-13 (Mar. 6, 2015); PJM Comments, Docket No. 
AD14-14-000, at 11-12 (Mar. 6, 2015); Potomac Economics Comments, 
Docket No. AD14-14-000, at 10 (Mar. 6, 2015); PSEG Companies 
Comments, Docket No. AD14-14-000, at 19-22 (Mar. 6, 2015); Wisconsin 
Electric Comments, Docket No. AD14-14-000, at 8 (Mar. 6, 2015); see 
also Xcel Comments at 4-5 (supporting sub-hourly settlement 
intervals but requesting that the Commission not require reporting 
sub-hourly settlement data in the Electric Quarterly Reports and if 
need be, direct the RTOs/ISOs to report that data).
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[[Page 58397]]

18. Commenters detail other potential benefits to sub-hourly settlement 
in the real-time market. PJM Utilities Coalition notes that sub-hourly 
settlement would address price distortions and uneconomic incentives to 
produce power caused by the use of hourly settlements.\23\ PJM 
Utilities Coalition also states that sub-hourly settlement would solve 
the problem of dispatching resources just before or after the clock 
hour and the resulting implications of averaging output during the 
clock hour.\24\ Wartsila states that the transition to sub-hourly 
settlements provides valuable price signals to flexible capacity and 
notes that internal combustion engines in SPP have seen a three-fold 
increase in their capacity factor since SPP adopted sub-hourly real-
time settlements, thus increasing compensation to those resources and 
lowering overall system costs.\25\
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    \23\ PJM Utilities Coalition Comments, Docket No. AD14-14-000, 
at 10-11 (Mar. 6, 2015).
    \24\ Id.
    \25\ Wartsila Comments, Docket No. AD14-14-000, at 1-2 (Mar. 6, 
2015).
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    19. PSEG Companies state that the inefficiencies of hourly 
settlements in PJM's real-time market are evident when the LMP becomes 
relatively high during the first few dispatch intervals.\26\ PSEG 
Companies add that internal resources will ramp up to respond to the 
price signal and other resources and external suppliers will also 
schedule interchange into PJM to capture the higher prices; when demand 
falls off in the subsequent intervals, however, resources will not 
reduce output in response to the lower prices (because they know they 
will be compensated at the hourly average prices), which has led to 
operational problems.\27\ EPSA supports sub-hourly real-time market 
settlement in order to better align dispatch with price.\28\
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    \26\ PSEG Companies Comments, Docket No. AD14-14-000, at 20 
(Mar. 6, 2015).
    \27\ Id. at 20-21.
    \28\ EPSA Comments, Docket No. AD14-14-000, Attach. A, Post-
Technical Conference Questions for Comment: EPSA Responses, at 28 
(Mar. 6, 2015).
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    20. At the Scarcity and Shortage Pricing, Offer Mitigation and 
Offer Caps Workshop held on October 28, 2014, representatives from 
RTOs/ISOs discussed the effect of settlement intervals on appropriately 
compensating resources based on actual performance, on providing an 
incentive for resources to follow dispatch signals, and on reducing 
uplift.\29\ At the Uplift Workshop held on September 8, 2014, the 
representative from Potomac Economics asserted that settling 
transactions on an hourly price, when dispatch instructions change 
every five or fifteen minutes, has caused flexible units in MISO to 
operate inflexibly in order to obtain a higher hourly price. According 
to this panelist, this disparity between settlement and dispatch 
intervals has prompted development of a class of uplift payments meant 
to hold inflexible generators harmless for following dispatch 
instructions and to ensure generators' flexibility. This panelist 
suggested that aligning settlement and dispatch intervals could 
eliminate such uplift payments.\30\
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    \29\ See, e.g., Scarcity and Shortage Pricing, Offer Mitigation 
and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 52:16-55:10 
(Oct. 28, 2014).
    \30\ Uplift Workshop, Docket No. AD14-14-000, Tr. 45:4-23 (Sept. 
8, 2014).
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    21. In its comments, CAISO indicates that it uses both fifteen-
minute and five-minute settlement intervals in its real-time market and 
that these intervals provide a dynamic price signal to reflect grid 
conditions. According to CAISO, fifteen-minute intertie schedules and 
prices provide an incentive for variable energy resources to offer 
economic bids into the CAISO market, which can reduce variable energy 
resources' exposure to the difference between day-ahead and five-minute 
real-time prices.\31\
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    \31\ CAISO Comments, Docket No. AD14-14-000, at 18-19 (Mar. 6, 
2015).
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    22. Commenters in the price formation proceeding express caution 
about implementation and costs resulting from RTOs'/ISOs' adoption of 
sub-hourly settlements--costs both to RTOs/ISOs and market 
participants. SPP states that its sub-hourly settlement rules cost more 
to implement due to increased data storage and validation 
requirements.\32\ ISO-NE and GDF SUEZ state that the one impediment to 
implementing sub-hourly real-time settlements in the ISO-NE market is 
the need for five-minute revenue quality metering; ISO-NE states that, 
according to stakeholders, it could take several years to implement and 
cost up to $20 million to install the necessary equipment, software, 
and data systems.\33\ PJM similarly states that moving to sub-hourly 
settlements will require it to make software and hardware changes to 
multiple applications and systems at a cost that is anecdotally 
comparable to a moderately complex market integration proposal.\34\
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    \32\ SPP Comments, Docket No. AD14-14-000, at 4 (Mar. 6, 2015).
    \33\ ISO-NE Comments, Docket No. AD14-14-000, at 23 (Mar. 6, 
2015); GDF SUEZ Comments, Docket No. AD14-14-000, at 10 (Mar. 6, 
2015).
    \34\ PJM Comments, Docket No. AD14-14-000, at 12 (Mar. 6, 2015).
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    23. Several commenters stress that, while sub-hourly settlements 
can bring benefits and efficiencies to the real-time market, 
transitioning to that settlement structure would require significant 
expenditures. Some RTOs/ISOs assert that there will be significant 
costs to make the necessary upgrades to metering equipment, software, 
hardware, and data systems, and that some of these upgrades could take 
several years to implement. As a result of these expenditures, some 
commenters note that action to align the settlement and dispatch 
interval may not occur absent a Commission directive.\35\ Other 
commenters observe that load-serving entities might incur significant 
costs associated with telemetry and related equipment upgrades; 
increases in RTO/ISO administrative charges; and additional costs to 
meter, transfer, and store the data and to process settlements in 
accordance with RTO/ISO timelines.\36\
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    \35\ ISO-NE Comments, Docket No. AD14-14-000, at 23 (Mar. 6, 
2015); PJM Comments, Docket No. AD14-14-000, at 12 (Mar. 6, 2015). 
GDF SUEZ echoes ISO-NE's statements about cost and timing to 
implement sub-hourly settlements in the ISO-NE market and requests 
that the Commission provide direction to overcome the lack of 
incentives facing meter readers to implement sub-hourly settlements. 
GDF SUEZ Comments, Docket No. AD14-14-000, at 10 (Mar. 6, 2015).
    \36\ PJM Utilities Coalition Comments, Docket No. AD14-14-000, 
at 11 (Mar. 6, 2015); TAPS Comments, Docket No. AD14-14-000, at 16-
17 (Mar. 6, 2015).
---------------------------------------------------------------------------

    24. Due to the anticipated costs, several commenters request that 
the Commission require cost-benefit analyses before adoption of sub-
hourly settlements, or that the Commission leave the decision to adopt 
sub-hourly settlements to RTO/ISO stakeholders.\37\ Some commenters 
assert that RTO/ISO stakeholders must vet the implementation of sub-
hourly settlements to ensure that appropriate market power mitigation 
measures are in place.\38\ Exelon states that, while sub-hourly 
settlements can improve market efficiency, the timing and 
prioritization

[[Page 58398]]

of adopting sub-hourly settlements should be evaluated when RTOs/ISOs 
develop work plans to analyze the causes of uplift.\39\
---------------------------------------------------------------------------

    \37\ Direct Energy Comments, Docket No. AD14-14-000, at 8 (Mar. 
6, 2015); OMS Comments, Docket No. AD14-14-000, at 4 (Mar. 2, 2015); 
PJM Utilities Coalition Comments, Docket No. AD14-14-000, at 11 
(Mar. 6, 2015); TAPS Comments, Docket No. AD14-14-000, at 16 (Mar. 
6, 2015).
    \38\ APPA and NRECA Comments, Docket No. AD14-14-000, at 38 
(Mar. 6, 2015); see also PJM Utilities Coalition Comments, Docket 
No. AD14-14-000, at 11 (Mar. 6, 2015).
    \39\ Exelon Comments, Docket No. AD14-14-000, at 19 (Mar. 6, 
2015).
---------------------------------------------------------------------------

    25. Commenters also provide the Commission with recommendations for 
implementation of sub-hourly settlement. PJM Utilities Coalition 
recommends that any move to sub-hourly settlements include at least one 
year notice of intent to allow for system readiness.\40\ PJM Utilities 
Coalition suggests that RTOs/ISOs could first transition to fifteen-
minute settlement intervals before moving to five-minute settlement 
intervals with stakeholders vetting the costs and benefits.\41\ ANGA 
recommends that, to the extent possible, five-minute settlement 
intervals be made consistent across different RTOs/ISOs. According to 
ANGA, inconsistencies across RTO/ISO boundaries can increase market and 
interchange volatility and result in large price fluctuations that are 
not based upon market fundamentals and which could create an incentive 
for gaming between markets as market participants arbitrage distorted 
prices.\42\
---------------------------------------------------------------------------

    \40\ PJM Utilities Coalition Comments, Docket No. AD14-14-000, 
at 11 (Mar. 6, 2015).
    \41\ Id.
    \42\ ANGA Comments, Docket No. AD14-14-000, at 4 (Mar. 6, 2015).
---------------------------------------------------------------------------

2. Need for Reform of Settlement Intervals
    26. The Commission preliminarily finds that the use of hourly 
integrated prices for real-time settlement may have the unintended 
effect of distorting price signals and, in certain instances, 
contributing to markets failing to respond appropriately to operating 
needs. Specifically, hourly integrated prices for real-time settlement 
may (1) not accurately reflect the value a resource provides to the 
system; (2) discourage resources from following dispatch instructions; 
and (3) cause increased uplift payments. Therefore, the Commission 
preliminarily finds that the use of hourly integrated prices for real-
time settlement may result in rates that are unjust and unreasonable.
    27. First, because hourly prices are an integrated average of sub-
hourly dispatch interval prices over an hour, the hourly price does not 
reflect system needs and costs within a dispatch interval; thus, 
resources are not necessarily paid a price that reflects the value of 
the service they provide to the system during the dispatch interval. 
For example, a resource providing energy during high-priced dispatch 
intervals, that is then paid based on a lower hourly integrated price, 
is not compensated based on a price that reflects actual market 
conditions or the price at which it was economic to dispatch this 
resource.
    28. Real-time settlement using prices that are averaged over an 
hour cannot capture the varying value of the service resources provide 
over the hour, which decreases the efficiency of RTO/ISO operations 
because RTOs/ISOs require resources to move within the hour to address 
changing operating conditions. Such settlement prices become the prices 
made transparent to the market and, when they are averaged to the point 
of not reflecting operating conditions and resultant supply and demand 
conditions, they may be unjust and unreasonable. In Order No. 719, the 
Commission found that then-existing rules on shortage pricing ``that do 
not allow for prices to rise sufficiently during an operating reserve 
shortage to allow supply to meet demand'' may be unjust and 
unreasonable.\43\ Similarly, the Commission preliminarily finds here 
that market rules that settle real-time transactions at hourly 
integrated prices may be unjust and unreasonable because they result in 
settlement prices that do not reflect actual operating conditions or 
the value of energy resulting from supply and demand.
---------------------------------------------------------------------------

    \43\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 192.
---------------------------------------------------------------------------

    29. Second, the use of hourly integrated prices for settling 
transactions can provide an unwarranted incentive for resources to 
disregard dispatch instructions. For example, PSEG Companies and PJM 
Utilities Coalition explain that high prices in the beginning of an 
hour can cause internal resources to ramp up and external transactions 
to schedule into PJM to capture higher prices; when demand and prices 
fall in subsequent intervals, however, hourly integrated prices create 
an incentive to continue producing or importing energy, regardless of 
dispatch instructions to reduce output.\44\
---------------------------------------------------------------------------

    \44\ PSEG Companies Comments, Docket No. AD14-14-000, at 20 
(Mar. 6, 2015); PJM Utilities Coalition Comments, Docket No. AD14-
14-000, at 10-11 (Mar. 6, 2015).
---------------------------------------------------------------------------

    30. As PSEG Companies illustrate by example, the use of hourly 
integrated prices for real-time settlement can create incentives that 
do not necessarily align with the system operator's dispatch 
instructions.\45\ Consider a resource with $100/MWh cost, and an LMP 
that is $500/MWh for the first fifteen minutes of the hour (three 
intervals). Even if the LMP dropped to $0/MWh for the remainder of the 
hour, the hourly integrated price ($125/MWh) would still exceed the 
resource's cost of production. This settlement structure would provide 
an incentive to generate as much energy as possible, not only during 
the first fifteen minutes of very high prices, but during the entire 
hour, irrespective of the five-minute price thereafter. Studies have 
shown that, due to the incentives created by hourly integrated 
settlements, resources can earn significant additional payments by not 
following dispatch signals.\46\
---------------------------------------------------------------------------

    \45\ PSEG Companies Comments, Docket No. AD14-14-000, at 20 & 
n.25 (Mar. 6, 2015).
    \46\ An analysis of actual LMP data showed how hourly settlement 
price signals can allow a resource to earn nearly twice the profit 
compared to if the resource is paid based on five-minute LMP price 
signals. See E. Ela et al., National Renewable Energy Laboratory and 
Argonne National Laboratory, Evolution of Wholesale Electricity 
Market Design with Increasing Levels of Renewable Generation, at 62-
66 (Sept. 2014), available at https://www.nrel.gov/docs/fy14osti/61765.pdf.
---------------------------------------------------------------------------

    31. Failing to follow dispatch instructions can impair the ability 
of the system operator to manage dispatch costs. Specifically, failing 
to follow dispatch instructions can result in power imbalances that the 
system operator must address by taking action, such as increasing use 
of regulating reserves or committing additional resources, which may 
result in increased uplift. These actions result in additional costs 
that are ultimately passed on to consumers. Because hourly integrated 
prices can impair the ability of the system operator to manage dispatch 
and the costs of dispatch, the Commission finds preliminarily that 
hourly integrated prices for real-time settlement can lead to unjust 
and unreasonable rates.\47\
---------------------------------------------------------------------------

    \47\ In Order No. 764, the Commission similarly found that 
impairing the ability of the system operator to manage costs 
resulted in unjust and unreasonable rates; it determined a need for 
reform of scheduling practices and data reporting practices where 
``existing practices . . . impair[ed] the ability of public utility 
transmission providers and their customers to manage costs 
associated with [Variable Energy Resource] integration 
effectively.'' Integration of Variable Energy Resources, Order No. 
764, FERC Stats. & Regs. ] 31,331, at PP 21-22, order on reh'g and 
clarification, Order No. 764-A, 141 FERC ] 61,232 (2012), order on 
clarification and reh'g, Order No. 764-B, 144 FERC ] 61,222 (2013). 
It adopted reforms to those practices to ``remedy undue 
discrimination and ensure just and reasonable rates through more 
efficient utilization of transmission and generation resources.'' 
Id. P 22.
---------------------------------------------------------------------------

    32. Third, as MISO notes, dispatching resources within the hour 
based on their offers, but then compensating those resources based on a 
lower hourly integrated price can result in uplift costs because 
additional uplift payments are then necessary to enhance incentives for 
resources to follow dispatch instructions.\48\ A study by Potomac

[[Page 58399]]

Economics shows that changes to sub-hourly settlement intervals can 
reduce uplift payments. Specifically, Potomac Economics estimates that, 
if MISO had implemented a real-time settlement interval that was equal 
to its dispatch interval (i.e., five minutes) in 2014, it would have 
reduced uplift payments by approximately $6.6 million.\49\
---------------------------------------------------------------------------

    \48\ MISO Comments, Docket No. AD14-14-000, at 17-18 (Mar. 6, 
2015).
    \49\ Potomac Economics, 2014 State of the Market Report for the 
MISO Electricity Markets at 43-44 & Figure 19 (2015), available at 
https://www.misoenergy.org/Library/Repository/Report/IMM/2014%20State%20of%20the%20Market%20Report.pdf.
---------------------------------------------------------------------------

    33. For these reasons, the Commission proposes to require that each 
RTO/ISO settle energy transactions in its real-time markets at the same 
time interval it dispatches energy and settle operating reserves 
transactions in its real-time markets at the same time interval it 
prices operating reserves. The Commission also seeks comment on two 
additional aspects of the proposal, relating to intertie transactions 
and to operating reserves.
3. Commission Proposal
    34. To remedy any potentially unjust and unreasonable rates caused 
by the use of hourly integrated prices for real-time settlement, the 
Commission proposes, pursuant to section 206 of the FPA,\50\ to require 
that each RTO/ISO settle energy transactions in its real-time markets 
at the same time interval it dispatches energy and settle operating 
reserves transactions in its real-time markets at the same time 
interval it prices operating reserves.\51\
---------------------------------------------------------------------------

    \50\ 16 U.S.C. 824e.
    \51\ All RTOs/ISOs dispatch internal resources using five-minute 
intervals. See supra Table 1. Some RTOs/ISOs, however, such as 
CAISO, schedule external transactions, such as intertie 
transactions, on a different interval.
---------------------------------------------------------------------------

    35. As explained further below, in the short term, the settlement 
interval reform proposed in this NOPR should improve incentives for 
resources to respond quickly to dispatch instructions, which should in 
turn lead to operators taking fewer out-of-market actions to ensure 
that supply meets demand. In the long-term, these reforms should 
provide more accurate price signals, which should provide, together 
with other market price signals, the appropriate incentives to build or 
maintain resources that can respond to an energy or operating reserve 
deficiency. In addition, where settlement and dispatch intervals are 
aligned, resources dispatched economically during high-priced periods 
would receive those high prices rather than an hourly average of the 
dispatch interval LMPs, thereby reducing the need to make uplift 
payments. Apportioning a greater proportion of a resource's revenue 
through payments for energy and operating reserves, rather than through 
uplift payments, would increase transparency to the market by 
reflecting the costs of resource dispatch in settlement prices that are 
factored into a market price. In contrast, uplift payments bundle 
together a multitude of costs that are not factored into a market 
price. This increased transparency, in turn, better informs decisions 
to build or maintain resources and enhances consumers' ability to 
hedge.
    36. By improving resources' response to dispatch instructions, the 
settlement interval reform proposed herein would result in a more 
efficient use of generation resources to the benefit of all consumers. 
As described above, Wartsila explains that internal combustion engines 
have seen a three-fold increase in their capacity factor since SPP 
adopted sub-hourly real-time settlements, thus increasing compensation 
to those resources and lowering overall system costs.\52\
---------------------------------------------------------------------------

    \52\ Wartsila Comments, Docket No. AD14-14-000, at 1-2 (Mar. 6, 
2015).
---------------------------------------------------------------------------

    37. As the Commission has concluded in the past, more efficient use 
of generation resources can ensure that jurisdictional services are 
provided at rates, terms, and conditions of service that are just and 
reasonable and not unduly discriminatory or preferential, in accord 
with the Commission's statutory obligations.\53\
---------------------------------------------------------------------------

    \53\ Order No. 764, FERC Stats. & Regs. ] 31,331 at P 5 (reforms 
adopted ``allow for the more efficient utilization of transmission 
and generation resources to the benefit of all customers. This, in 
turn, fulfills our statutory obligation to ensure that Commission-
jurisdictional services are provided at rates, terms, and conditions 
of service that are just and reasonable and not unduly 
discriminatory or preferential.'').
---------------------------------------------------------------------------

    38. While the Commission expects that the settlement interval 
reform proposed in this NOPR should provide significant benefits, the 
Commission understands that modifying settlement systems can be a 
complex and costly endeavor.\54\ Accordingly, the Commission proposes 
to allow twelve months from the date of the compliance filings for 
implementation of reforms to settlement systems to become effective. 
Further, the Commission seeks comment on the potential cost and time 
necessary to implement the reforms proposed in this NOPR. Specifically, 
the Commission seeks comment on required software changes, increased 
data storage and validation, and required changes to market participant 
metering or other equipment that would result from implementing the 
reforms proposed in this NOPR. The Commission also seeks comment on 
whether the changes necessary to implement the settlement interval 
reform proposed in this NOPR would be necessary in whole or in part to 
implement other reforms planned by the RTOs/ISOs or sought by 
stakeholders. The Commission further requests comments concerning 
whether such a long implementation period is necessary and how that 
implementation period may be shortened.
---------------------------------------------------------------------------

    \54\ See, e.g., ISO-NE Comments, Docket No. AD14-14-000, at 23 & 
nn.28-30 (Mar. 6, 2015) (citing Meter Reader Working Group, Sub-
hourly Time & Cost Estimate, at slide 9 (July 10, 2014), available 
at https://www.iso-ne.com/committees/markets/meter-reader) (citing 
estimates from meter reader entities in New England that 
implementation of five-minute market settlements could cost more 
than $20 million and take more than seven years).
---------------------------------------------------------------------------

    39. The Commission also seeks comment on two aspects of the 
substance of the settlement interval proposal relating to external 
transactions and to operating reserves. First, the logic underlying our 
reforms to settlement of internal transactions appears to apply equally 
to intertie transactions. While the Commission does not propose to 
extend the reforms to intertie transactions, the Commission seeks 
comment on whether settlement reforms are appropriate for intertie 
transactions that are scheduled on intervals different from the 
intervals on which RTOs/ISOs dispatch internal real-time energy.\55\ 
The Commission also seeks comment on whether it is necessary to align 
the settlement interval for intertie transactions with external 
scheduling intervals, i.e., fifteen minutes.
---------------------------------------------------------------------------

    \55\ The Commission clarifies that it is not proposing to modify 
the scheduling requirements adopted in Order No. 764.
---------------------------------------------------------------------------

    40. Second, the Commission recognizes that dispatch and pricing of 
energy and operating reserves are closely linked through co-
optimization in the real-time market. This co-optimization ensures that 
resources are compensated for following RTO/ISO instructions and are 
indifferent to providing either energy or operating reserves during 
periods of high energy or operating reserves prices. Despite the close 
linkage between energy and operating reserves, the Commission 
understands that some of the problems associated with the use of hourly 
integrated prices for settling energy transactions might not apply as 
fully to settling operating reserves transactions. Further, the 
Commission recognizes the set of resources that are paid the real-time 
operating reserve price are potentially much smaller than the set of 
resources that are paid the real-time

[[Page 58400]]

energy price. The Commission understands that certain RTOs/ISOs acquire 
operating reserves on a different interval than these RTOs/ISOs 
dispatch energy. Accordingly, the Commission seeks comment on whether 
the Commission should require RTOs/ISOs to settle all real-time 
operating reserves transactions at the same interval as real-time 
energy dispatch and settlement intervals or whether a settlement 
interval that differs from an RTO's/ISO's real-time energy dispatch 
interval would be appropriate for some operating reserves transactions.

B. Shortage Pricing Triggers

1. Comments on Shortage Pricing Triggers
    41. Panelists at the October 28, 2014 Shortage Pricing/Mitigation 
Workshop and commenters in the price formation proceeding discussed 
shortage pricing triggers. Panelists and commenters were divided on 
whether all shortage events should trigger shortage pricing.\56\ Some 
favored such a trigger. These panelists explained that triggering 
shortage pricing for any shortage would allow pricing to reflect 
fluctuations across the hour better and also to offer more granular and 
accurate compensation.\57\ In contrast, the panelist from PJM was more 
hesitant in sending a shortage price signal when a combined-cycle 
turbine with a thirty-minute startup time took five additional minutes 
to come online, explaining that a shortage price signal during such an 
event would diverge from an operator's understanding that the system is 
not experiencing a shortage.\58\
---------------------------------------------------------------------------

    \56\ See, e.g., Scarcity and Shortage Pricing, Offer Mitigation 
and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 38:19-51:8 
(Oct. 28, 2014).
    \57\ Id. at 46:1-47:17, 50:13-19.
    \58\ Scarcity and Shortage Pricing, Offer Mitigation and Offer 
Caps Workshop, Docket No. AD14-14-000, Tr. 48:13-49:7 (Oct. 28, 
2014).
---------------------------------------------------------------------------

    42. In its comments, EPSA argues that it is a high priority for all 
markets to establish shortage pricing based on operating reserves 
demand curves and co-optimized with the energy market.\59\ New York 
Transmission Owners argue that if the electric system is short of 
resources, even for only five or ten minutes, that shortage should 
trigger shortage pricing.\60\ Similarly, NYISO and Potomac Economics 
state that pricing each shortage, even a ``transient shortage,'' 
provides incentives to resources that have the capability to respond to 
brief-duration shortages.\61\
---------------------------------------------------------------------------

    \59\ EPSA Comments, Docket No. AD14-14-000, at 36 (Mar. 6, 
2015).
    \60\ New York Transmission Owners Comments, Docket No. AD14-14-
000, at 23 (Mar. 6, 2015).
    \61\ NYISO Comments, Docket No. AD4-14-000, at 28-29 (Mar. 6, 
2015); Potomac Economics Comments, Docket No. AD14-14-000, at 26 
(Mar. 6, 2015).
---------------------------------------------------------------------------

    43. Several commenters favor triggering shortage pricing without 
any minimum duration for the event.\62\ Arguments in favor of 
triggering shortage pricing for any shortage rely on the need to send 
price signals that provide an incentive for resources to offer their 
full flexibility and for market entry by reflecting actual system 
conditions in real time.\63\ EEI states that generators should be able 
to recover reasonable and supportable costs incurred in unexpected 
circumstances.\64\ PSEG Companies maintain that, while the ISO-NE and 
NYISO markets' rules (which price all shortages, no matter the 
duration) enable them to provide accurate price signals, PJM's market 
rules (which restrict ``transient shortage'' events from triggering 
shortage pricing) can distort its market prices.\65\
---------------------------------------------------------------------------

    \62\ See, e.g., CAISO Comments, Docket No. AD14-14-000, at 40 
(Mar. 6, 2015); Calpine Comments, Docket No. AD14-14-000, at 20 
(Mar. 6, 2015); GDF SUEZ Comments, Docket No. AD14-14-000, at 19 
(Mar. 6, 2015); NYISO Comments, Docket No. AD14-14-000, at 28 (Mar. 
6, 2015); Potomac Economics Comments, Docket No. AD14-14-000, at 25 
(Feb. 24, 2015).
    \63\ Calpine Comments, Docket No. AD14-14-000, at 20 (Mar. 6, 
2015); NYISO Comments, Docket No. AD14-14-000, at 28-29 (Mar. 6, 
2015); Potomac Economics Comments, Docket No. AD14-14-000, at 25-26 
(Feb. 24, 2015).
    \64\ EEI Comments, Docket No. AD14-14-000, at 5 (Mar. 6, 2015).
    \65\ PSEG Companies Comments, Docket No. AD14-14-000, at 31 
(Mar. 6, 2015).
---------------------------------------------------------------------------

    44. In contrast, Wisconsin Electric and PJM prefer that a shortage 
event last a minimum duration before triggering shortage pricing. 
Wisconsin Electric argues that there should be a minimum duration for 
invoking shortage pricing, and that this duration should allow 
flexibility to account for the nature of transmission limits and 
reserve levels in the operating environment, with shorter minimum 
intervals to invoke shortage pricing applicable under extreme load and 
temperatures.\66\ PJM states that the minimum duration for shortage 
pricing should be at least as long as (and perhaps longer than) the 
settlement interval and that a minimum interval for triggering shortage 
pricing is required to stimulate investment.\67\
---------------------------------------------------------------------------

    \66\ Wisconsin Electric Comments, Docket No. AD14-14-000, at 16 
(Mar. 6, 2015).
    \67\ PJM Comments, Docket No. AD14-14-000, at 22 (Mar. 6, 2015).
---------------------------------------------------------------------------

    45. Some commenters argue that a ``transient'' or relatively brief 
shortage is not a ``real'' shortage because either the shortage is 
merely a mathematical artifact of the modeling, or the shortage will 
soon be resolved before generators can respond to shortage prices, even 
though the system is technically short of resources.\68\
---------------------------------------------------------------------------

    \68\ MISO Comments, Docket No. AD14-14-000, at 37 (Mar. 6, 
2015); OMS Comments, Docket No. AD14-14-000, at 6 (Mar. 2, 2015); 
PG&E Comments, Docket No. AD14-14-000, at 6 (Mar. 6, 2015); PJM 
Comments, Docket No. AD14-14-000, at 22 (Mar. 6, 2015); SCE 
Comments, Docket No. AD14-14-000, at 7 (Mar. 6, 2015); TAPS 
Comments, Docket No. AD14-14-000, at 24 (Mar. 6, 2015).
---------------------------------------------------------------------------

2. Need for Reform of Shortage Pricing Triggers

    46. Shortage prices send a short-term price signal to provide an 
incentive for the performance of existing resources and help to 
maintain reliability.\69\ However, some RTOs/ISOs currently restrict 
the triggering of shortage pricing to shortages due only to certain 
causes, or they require a shortage to exist for a certain time, e.g., 
thirty minutes, before invoking shortage pricing.\70\
---------------------------------------------------------------------------

    \69\ See Shortage Pricing Paper at 4-5.
    \70\ See Scarcity and Shortage Pricing, Offer Mitigation and 
Offer Caps Workshop, Docket No. AD14-14-000, Tr. at 30:15-31:16 and 
47:19-49:12 (describing PJM's practice); SPP, OATT, Sixth Revised 
Volume No. 1, Attachment AE, Sec. Sec.  5.1.2.1 (1.0.0), 8.3.4.2 
(0.0.0).
---------------------------------------------------------------------------

    47. As several commenters during the price formation proceeding 
noted, not invoking shortage pricing when there is a shortage 
(regardless of the duration or cause of that shortage) distorts price 
signals that are designed to elicit increased supply and to compensate 
resources for the value of the services they provide when the system 
needs energy or operating reserves. Moreover, prices in each dispatch 
interval should reflect the value provided by dispatched resources. In 
times of shortage, the value of services a resource provides increases 
because operating needs have increased. When shortage pricing is not 
applied when a shortage exists, the resulting price fails to reflect 
adequately the value that a resource provides to the system. This 
failure impairs efficient system dispatch and hinders appropriate 
incentives for resources to address an energy or operating reserves 
shortage. Because of such effects, the Commission finds preliminarily 
that the resulting price is not just and reasonable.
    48. In making this preliminary finding, the Commission's rationale 
here is similar to the rationale the Commission relied on in Order No. 
719. In that order, the Commission required shortage pricing in RTOs 
and ISOs. The Commission reasoned that ``rules that do not allow for 
prices to rise sufficiently during an operating reserve shortage to 
allow supply to meet demand are unjust, unreasonable, and

[[Page 58401]]

may be unduly discriminatory.'' \71\ The Commission added: ``In 
particular, [such rules] may not produce prices that accurately reflect 
the value of energy. . . .'' \72\ For similar reasons, the Commission 
now believes that not invoking shortage pricing during a shortage may 
result in unjust and unreasonable rates because prices do not 
accurately reflect the value of energy during a shortage. Accordingly, 
the Commission preliminarily finds that restricting shortage pricing to 
shortages lasting longer than one dispatch interval, or not invoking 
shortage pricing during relatively brief shortages, even though a 
shortage exists, results in rates that may be unjust and unreasonable.
---------------------------------------------------------------------------

    \71\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 192.
    \72\ Id.
---------------------------------------------------------------------------

    49. Commenters that do not support triggering shortage pricing 
during ``transient shortages'' argue that such shortages can be either 
merely a mathematical artifact of the modeling, or a shortage that will 
soon be resolved before generators can respond to shortage prices, even 
though the system is technically short of resources.\73\ The 
Commission, however, believes there are steps an RTO/ISO can take to 
mitigate seemingly artificial shortages, such as using the RTO's/ISO's 
look-ahead capability to prevent or minimize the occurrence of 
shortages that are caused by modeling or other operating 
deficiencies.\74\ The Commission believes that reflecting the shortage 
in prices is still necessary even when a reserve shortage is so short-
lived that resources may be unable to respond to the price signal, so 
that resources operating during the shortage are compensated for the 
value of the service that they provide. The Commission acknowledges 
that an RTO/ISO may need to calibrate administrative shortage prices to 
better reflect the value of the service.\75\
---------------------------------------------------------------------------

    \73\ MISO Comments, Docket No. AD14-14-000, at 37 (Mar. 6, 
2015); OMS Comments, Docket No. AD14-14-000, at 6 (Mar. 2, 2015); 
PG&E Comments, Docket No. AD14-14-000, at 6-7 (Mar. 6, 2015); PJM 
Comments, Docket No. AD14-14-000, at 22-23 (Mar. 6, 2015); SCE 
Comments, Docket No. AD14-14-000, at 7-8 (Mar. 6, 2015); TAPS 
Comments, Docket No. AD14-14-000, at 24 (Mar. 6, 2015).
    \74\ One panelist at the Scarcity and Shortage Pricing, Offer 
Mitigation and Offer Caps Workshop stated that a look-ahead process 
can position resources so that changing operating conditions do not 
lead to reserve shortages. See Scarcity and Shortage Pricing, Offer 
Mitigation and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 
43:23-45:3 (Oct. 28, 2014) (``One of the drivers of putting in our 
forward-looking dispatch tools, our dispatch tools are looking out 
60 minutes in a time-link dispatch, so they see upcoming system 
events.'').
    \75\ See, e.g., Scarcity and Shortage Pricing, Offer Mitigation 
and Offer Caps Workshop, Docket No. AD14-14-000, Tr. 40:1-42:12 
(Oct. 28, 2014) (``So now in MISO, most of those scarce, transient 
events are really very small shortages against their total 
requirement produces a much smaller pricing impact, but we still 
think it's important. A shortage is a shortage. We should try and 
make some estimation of what the marginal value of that shortage is 
and include that in pricing.'').
---------------------------------------------------------------------------

    50. Based upon information gathered during the price formation 
proceeding and as discussed above, the Commission preliminarily 
determines that prices that result from a failure to trigger shortage 
pricing for any dispatch interval during which a shortage of energy or 
operating reserves occurs may be unjust and unreasonable.
3. Commission Proposal
    51. In order to remedy the potentially unjust and unreasonable 
rates caused by restrictions on shortage pricing, the Commission 
proposes, pursuant to section 206 of the FPA,\76\ to require that RTOs/
ISOs trigger shortage pricing for any dispatch interval during which a 
shortage of energy or operating reserves occurs. The Commission seeks 
comments on this proposal.
---------------------------------------------------------------------------

    \76\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    52. The shortage pricing reform in this NOPR should ensure that a 
resource is compensated based on a price that reflects the value of the 
service the resource provides. Implementing the shortage pricing reform 
proposed in this NOPR would ensure that resources have appropriate 
incentives to address energy or reserve shortages. The Commission 
expects that if shortage pricing is triggered for all shortage events, 
then resources are expected to take actions to ensure that they are 
available to respond to high prices. Resources taking actions to ensure 
their availability should, in turn, alleviate shortages and avoid 
shortage pricing during subsequent dispatch intervals.
    53. The shortage pricing reform proposed in this NOPR addresses the 
trigger for invoking shortage pricing, not the shortage price. While 
the Commission asked commenters to address the level of shortage 
pricing in the price formation proceeding,\77\ the Commission is not at 
this time proposing to change the price paid by any RTO/ISO when it 
triggers shortage pricing.
---------------------------------------------------------------------------

    \77\ Notice Inviting Post-Technical Workshop Comments, Docket 
No. AD14-14-000, at 9 (Jan. 16, 2015).
---------------------------------------------------------------------------

    54. The Commission expects that implementation of the shortage 
pricing reform proposed in this NOPR would not be as complex as 
implementing the proposed settlement interval reform. The Commission 
therefore proposes that the deadline for full implementation of the 
shortage pricing reform be effective within four months from the date 
of the compliance filing in response to a final rule in this 
proceeding. The Commission seeks comment on whether that proposed 
compliance and implementation timeline would provide sufficient time 
for RTOs/ISOs to develop and implement changes to technological systems 
and business processes in response to a final rule adopting the 
proposed shortage pricing reform.

III. Compliance

    55. The Commission proposes to require that each RTO/ISO submit a 
compliance filing within four months of the effective date of the final 
Rule in this proceeding to demonstrate that it meets the proposed 
requirements set forth in the final Rule. While the Commission believes 
that four months is a reasonable deadline for RTOs/ISOs to submit 
compliance filings, the Commission understands that the proposed 
settlement interval reform could take more time to implement than the 
proposed shortage pricing reform due to the complexity of settlement 
systems. As discussed above, the Commission proposes (1) to allow 
twelve months from the date of the compliance filings for 
implementation of reforms to settlement systems to become effective and 
(2) to allow four months from the date of the compliance filings for 
implementation of reforms to shortage pricing to become effective.
    56. The Commission seeks comment on the proposed deadline for RTOs/
ISOs to submit the compliance filing four months following the 
effective date of the final rule in this proceeding. Specifically, the 
Commission seeks comment on whether the proposed compliance timeline 
would allow sufficient time for RTOs/ISOs to develop and implement 
changes to technological systems and business processes in response to 
a final rule.
    57. To the extent that any RTO/ISO believes that it already 
complies with the settlement intervals and shortage pricing reforms 
proposed in this NOPR, the RTO/ISO would be required to demonstrate how 
it complies in the filing required four months after the effective date 
of the final rule in this proceeding. The proposed implementation 
deadlines would apply only to RTOs/ISOs to the extent they do not 
already comply with the reforms proposed in this NOPR.

[[Page 58402]]

IV. Information Collection Statement

    58. The Paperwork Reduction Act (PRA) \78\ requires each federal 
agency to seek and obtain Office of Management and Budget (OMB) 
approval before undertaking a collection of information directed to ten 
or more persons or contained in a rule of general applicability. OMB's 
regulations,\79\ in turn, require approval of certain information 
collection requirements imposed by agency rules. Upon approval of a 
collection(s) of information, OMB will assign an OMB control number and 
an expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these 
collection(s) of information unless the collection(s) of information 
display a valid OMB control number.
---------------------------------------------------------------------------

    \78\ 44 U.S.C. 3501-3520.
    \79\ 5 CFR 1320.
---------------------------------------------------------------------------

    59. The reforms proposed in this NOPR would amend the Commission's 
regulations to improve the operation of organized wholesale electric 
power markets operated by RTOs and ISOs. The Commission proposes to 
require that each RTO/ISO (1) settle energy transactions in its real-
time markets at the same time interval it dispatches energy and settle 
operating reserves transactions in its real-time markets at the same 
time interval it prices operating reserves and (2) trigger shortage 
pricing for any dispatch interval during which a shortage of energy or 
operating reserves occurs. The reforms proposed in this NOPR would 
require one-time filings of tariffs with the Commission and potential 
software and hardware upgrades to implement the reforms proposed in 
this NOPR. The Commission anticipates the reforms proposed in this 
NOPR, once implemented, would not significantly change currently 
existing burdens on an ongoing basis. With regard to those RTOs and 
ISOs that believe that they already comply with the reforms proposed in 
this NOPR, they could demonstrate their compliance in their compliance 
in the filing required four months after the effective date of the 
final rule in this proceeding. The Commission will submit the proposed 
reporting requirements to OMB for its review and approval under section 
3507(d) of the Paperwork Reduction Act.\80\
---------------------------------------------------------------------------

    \80\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    60. While the Commission expects the adoption of the reforms 
proposed in this NOPR to provide significant benefits, the Commission 
understands that implementation and modifying settlement systems can be 
a complex and costly endeavor. The Commission solicits comments on the 
accuracy of provided burden and cost estimates and any suggested 
methods for minimizing the respondents' burdens, including the use of 
automated information techniques. Specifically, the Commission seeks 
detailed comments on the potential cost and time necessary to implement 
aspects of the reforms proposed in this NOPR, including (1) hardware, 
software, and business processes changes; (2) increased data storage 
and validation; (3) changes to market participant metering or other 
equipment; and (4) processes for RTOs and ISOs to vet proposed changes 
amongst their stakeholders.
    61. The Commission also seeks comment on whether changes in 
settlement systems would disrupt existing contractual relationships 
and, if so, what burdens this might impose and how the Commission 
should address any potential issues resulting from such disruption.
    Burden Estimate and Information Collection Costs: The Commission 
believes that the burden estimates below are representative of the 
average burden on respondents, including necessary communications with 
stakeholders. The estimated burden and cost \81\ for the requirements 
contained in this NOPR follow.\82\
---------------------------------------------------------------------------

    \81\ The estimated hourly cost (salary plus benefits) provided 
in this section are based on the salary figures for May 2014 posted 
by the Bureau of Labor Statistics for the Utilities sector 
(available at https://www.bls.gov/oes/current/naics2_22.htm#13-0000) 
and scaled to reflect benefits using the relative importance of 
employer costs in employee compensation from March 2015 (available 
at https://www.bls.gov/news.release/ecec.nr0.htm). The hourly 
estimates for salary plus benefits are:
     Legal (code 23-0000), $129.87
     Computer and mathematical (code 15-0000), $58.25
     Information systems manager (code 11-3021), $94.55
     IT security analyst (code 15-1122), $63.55
     Auditing and accounting (code 13-2011), $51.11
     Information and record clerk (code 43-4199), $37.50
     Electrical Engineer (code 17-2071), $66.45
     Economist (code 19-3011), $73.04
     Computer and Information Systems Manager (code 11-
3021), $94.55
     Management (code 11-0000), $78.04
    The average hourly cost (salary plus benefits), weighting all of 
these skill sets evenly, is $74.69. The Commission rounds it to $75 
per hour.
    \82\ The RTOs and ISOs (CAISO, ISO-NE., MISO, NYISO, PJM, and 
SPP) are required to comply with the reforms proposed in this NOPR. 
Three RTOs/ISOs (CAISO, NYISO, and SPP) currently align real-time 
energy settlement with their dispatch intervals and thus likely 
would be burdened less by that aspect of the reforms proposed in 
this NOPR.

--------------------------------------------------------------------------------------------------------------------------------------------------------
      Data collection FERC 516                               Annual number of
 (modifications in NOPR in RM15-24-  Number of respondents    responses per     Total number of    Average burden hours and     Annual burden hours and
                000)                                            respondent         responses           cost per response           total annual cost
                                     (1)..................                (2)    (1) x (2) = (3)  (4).......................  (3) x (4) = (5)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Tariff filings one-time in Year 1:
    For RTOs/ISOs that currently     3 RTOs or ISOs.......                  1                  3  80 hrs; $6,000............  240 hrs;
     align real-time settlement                                                                                               $18,000.
     with dispatch intervals.
Tariff filings one-time in Year 1:
    For RTOs/ISOs that do not        3 RTOs or ISOs.......                  1                  3  160 hrs; $12,000..........  480 hrs;
     currently align real-time                                                                                                $36,000.
     settlement with dispatch
     intervals.
Related Burden Hours for
 Implementation of changes each
 year in Years 1 & 2:
    For RTOs/ISOs that currently     3 RTOs or ISOs.......                  1                  3  550 hrs;..................  1,650 hrs; $123,750.
     align real-time settlement                                                                   $41,250...................
     with dispatch intervals.

[[Page 58403]]

 
Related Burden Hours for
 Implementation of changes each
 year in Years 1 & 2:
    For RTOs/ISOs that do not        3 RTOs or ISOs.......                  1                  3  1,600 hrs;................  4,800 hrs; $360,000.
     currently align real-time                                                                    $120,000..................
     settlement with dispatch
     intervals.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of 
compliance as follows: \83\

    \83\ The costs for year 1 would consist of filing proposed 
tariff changes to the Commission within four months of a Final Rule 
plus initial implementation. The costs for year 2 would consist of 
any remaining implementation within the twelve months after the 
tariff filing is required.
---------------------------------------------------------------------------

 Year 1: $18,000 + $36,000 + $123,750 + $360,000 = $537,750
 Year 2: $123,750 + $360,000 = $483,750
    After Year 2, the reforms proposed in this NOPR, once implemented, 
would not significantly change existing burdens on an ongoing basis.
    The Commission notes that these estimates do not include costs for 
software and hardware. Based on comment from industry, current 
estimates of overall costs for software and hardware could be as high 
as $20,000,000, for market participants and RTOs/ISOs combined, for 
each RTO/ISO that does not yet comply with the settlement interval 
reform proposed in this NOPR.\84\ As stated above, the Commission 
requests comment on the estimated costs for any additional software and 
hardware needed to comply with the reforms proposed in this NOPR.
---------------------------------------------------------------------------

    \84\ ISO-NE Comments, Docket No. AD14-14-000, at 23 (Mar. 6, 
2015); GDF SUEZ Comments, Docket No. AD14-14-000, at 10 (Mar. 6, 
2015).
---------------------------------------------------------------------------

    Title: FERC-516, Electric Rate Schedules and Tariff Filings.
    Action: Proposed revisions to an information collection.
    OMB Control No. 1902-0096.
    Respondents for this Rulemaking: RTOs and ISOs.
    Frequency of Information: One-time during years one and two.
    Necessity of Information: The Federal Energy Regulatory Commission 
proposes this rule to improve competitive wholesale electric markets in 
the RTO and ISO regions.
    Internal Review: The Commission has reviewed the proposed changes 
and has determined that such changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    62. 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. 
Comments concerning the collection of information and the associated 
burden estimate(s), may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission, phone: (202) 395-0710, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically 
to the following email address: oira_submission@omb.eop.gov. Comments 
submitted to OMB should include FERC-516 and OMB Control No. 1902-0096.

V. Regulatory Flexibility Act Certification

    63. The Regulatory Flexibility Act of 1980 (RFA) \85\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. The RFA does 
not mandate any particular outcome in a rulemaking. It only requires 
consideration of alternatives that are less burdensome to small 
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \85\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    64. This rule would apply to six RTOs and ISOs (all of which are 
transmission organizations). The average estimated annual cost to each 
of the RTOs/ISOs is $89,625 in year 1, and $80,625 in Year 2. This one-
time cost of filing and implementing these changes is significant.\86\ 
The RTOs and ISOs, however, are not small entities, as defined by the 
RFA.\87\ This is because the relevant threshold between small and large 
entities is 500 employees and the Commission understands that each RTO 
and ISO has more than 500 employees. Furthermore, because of their 
pivotal roles in wholesale electric power markets in their regions, 
none of the RTOs/ISOs meet the last criterion of the two-part RFA 
definition a small entity: ``not dominant in its field of operation.'' 
As a result, the Commission certifies that the reforms proposed in this 
NOPR would not have a significant economic impact on a substantial 
number of small entities. The Commission does not expect other entities 
to incur compliance costs as a result of the reforms proposed in this 
NOPR, but seeks detailed comments on whether other entities, such as 
load-serving entities, would incur costs as a result of the reforms 
proposed in this NOPR.
---------------------------------------------------------------------------

    \86\ This estimate does not include costs for hardware and 
software, for which the Commission requests comment.
    \87\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3), citing to Section 3 of the Small Business Act, 15 U.S.C. 
632.
---------------------------------------------------------------------------

VI. Environmental Analysis

    65. 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.\88\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this NOPR under section 
380.4(a)(15) of the Commission's

[[Page 58404]]

regulations, which provides a categorical exemption for approval of 
actions under sections 205 and 206 of the FPA relating to the filing of 
schedules containing all rates and charges for the transmission or sale 
of electric energy subject to the Commission's jurisdiction, plus the 
classification, practices, contracts and regulations that affect rates, 
charges, classifications, and services.\89\
---------------------------------------------------------------------------

    \88\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC 
Stats. & Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \89\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VII. Comment Procedures

    66. The Commission invites interested persons to submit comments on 
the matters and issues proposed in this notice to be adopted, including 
any related matters or alternative proposals that commenters may wish 
to discuss. Comments are due November 30, 2015. Comments must refer to 
Docket Nos. RM15-24-000, and must include the commenter's name, the 
organization they represent, if applicable, and their address.
    67. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at https://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    68. Commenters that are not able to file comments electronically 
must send an original of their comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    69. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

VIII. Document Availability

    70. 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 (https://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.
    71. 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 of this document, excluding the last three digits, in 
the docket number field.
    72. 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.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Non-discriminatory open 
access transmission tariffs.

    By direction of the Commission.

    Dated: September 17, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
    In consideration of the foregoing, the Commission proposes to amend 
part 35, chapter I, title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.28 by revising paragraph (g)(1)(iv)(A) and adding 
paragraph (g)(1)(vi) to read as follows:


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (1) * * *
    (iv) * * *
    (A) Each Commission-approved independent system operator and 
regional transmission organization must modify its market rules to 
allow the market-clearing price during periods of operating reserve 
shortage to reach a level that rebalances supply and demand so as to 
maintain reliability while providing sufficient provisions for 
mitigating market power. Each Commission-approved independent system 
operator and regional transmission organization must trigger shortage 
pricing for any dispatch interval during which a shortage of energy or 
operating reserves occurs.
* * * * *
    (vi) Settlement intervals. Each Commission-approved independent 
system operator and regional transmission organization must settle 
energy transactions in its real-time markets at the same time interval 
it dispatches energy and must settle operating reserves transactions in 
its real-time markets at the same time interval it prices operating 
reserves.
* * * * *

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

APPENDIX A: List of Short Names/Acronyms of Commenters

------------------------------------------------------------------------
        Short name/acronym                        Commenter
------------------------------------------------------------------------
APPA and NRECA....................  American Public Power Association
                                     and National Rural Electric
                                     Cooperative Association.
ANGA..............................  America's Natural Gas Alliance.
Brookfield........................  Brookfield Renewable Energy
                                     Marketing LP.
CAISO.............................  California Independent System
                                     Operator Corporation.
Calpine...........................  Calpine Corporation.
Direct Energy.....................  Direct Energy Business Marketing,
                                     LLC, Direct Energy Business, LLC
                                     and affiliated companies.
EEI...............................  Edison Electric Institute.
EPSA..............................  Electric Power Supply Association.
Entergy Nuclear Power Marketing...  Entergy Nuclear Power Marketing,
                                     LLC.
Exelon............................  Exelon Corporation.
GDF SUEZ..........................  GDF SUEZ North America, Inc.
ISO-NE............................  ISO New England, Inc.
MISO..............................  Midcontinent Independent System
                                     Operator, Inc.
NYISO.............................  New York Independent System
                                     Operator, Inc.

[[Page 58405]]

 
New York Transmission Owners......  New York Transmission Owners
                                     (Central Hudson Gas & Electric
                                     Corporation, Consolidated Edison
                                     Company of New York, Inc., Power
                                     Supply of Long Island, New York
                                     Power Authority, New York State
                                     Electric & Gas Corporation, Niagara
                                     Mohawk Power Corporation d/b/a
                                     National Grid, Orange and Rockland
                                     Utilities, Inc., and Rochester Gas
                                     and Electric Corporation).
OMS...............................  Organization of MISO States.
PG&E..............................  Pacific Gas and Electric Company.
PJM...............................  PJM Interconnection, L.L.C.
PJM Utilities Coalition...........  PJM Utilities Coalition (American
                                     Electric Power Service Corporation,
                                     the Dayton Power and Light Company,
                                     FirstEnergy Service Company,
                                     Buckeye Power, Inc., and East
                                     Kentucky Power Cooperative).
Potomac Economics.................  Potomac Economics, Ltd.
PSEG Companies....................  PSEG Companies (Public Service
                                     Electric and Gas Company, PSEG
                                     Power LLC and PSEG Energy Resources
                                     & Trade LLC).
SCE...............................  Southern California Edison Company.
SPP...............................  Southwest Power Pool, Inc.
TAPS..............................  Transmission Access Policy Study
                                     Group.
Wartsila..........................  Wartsila North America, Inc.
Wisconsin Electric................  Wisconsin Electric Power Company.
Xcel..............................  Xcel Energy Services Inc.
------------------------------------------------------------------------

[FR Doc. 2015-24283 Filed 9-28-15; 8:45 am]
 BILLING CODE 6717-01-P