Document ID: FERC-2015-1636-0001
Agency: ferc
Document Type: Rule
Title: Third-Party Provision of Primary Frequency Response Service
Posted Date: 2015-11-27T05:00Z

[Federal Register Volume 80, Number 228 (Friday, November 27, 2015)]
[Rules and Regulations]
[Pages 73965-73977]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-30140]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM15-2-000; Order No. 819]

Third-Party Provision of Primary Frequency Response Service

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
revising its regulations to foster competition in the sale of primary 
frequency response service. Specifically, the Commission amends its 
regulations governing market-based rates for public utilities pursuant 
to the Federal Power Act (FPA) to permit the sale of primary frequency 
response service at market-based rates by sellers with market-based 
rate authority for sales of energy and capacity.

DATES: This Final Rule will become effective February 25, 2016.

FOR FURTHER INFORMATION CONTACT: 
Rahim Amerkhail (General Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-8266.
Gregory Basheda (Market Power Screening Information), Office of Energy 
Market Regulation, Federal Energy Regulatory Commission, 888 First 
Street NE., Washington, DC 20426, (202) 502-6479.
Lina Naik (Legal Information), Office of the General Counsel, Federal 
Energy Regulatory Commission, 888 First Street NE., Washington, DC 
20426, (202) 502-8882.

SUPPLEMENTARY INFORMATION: 

Order No. 819

Final Rule

(Issued November 20, 2015)
    1. The Federal Energy Regulatory Commission (Commission) is 
revising

[[Page 73966]]

its regulations to foster competition in the sale of primary frequency 
response service.\1\ Specifically, the Commission amends its 
regulations to revise Subpart H to Part 35 of Title 18 of the Code of 
Federal Regulations governing market-based rates for public utilities 
pursuant to sections 205 and 206 of the Federal Power Act (FPA) \2\ to 
permit the sale of primary frequency response service at market-based 
rates by sellers with market-based rate authority for sales of energy 
and capacity.
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    \1\ As described in more detail below, this Final Rule defines 
primary frequency response service as a resource standing by to 
provide autonomous, pre-programmed changes in output to rapidly 
arrest large changes in frequency until dispatched resources can 
take over.
    \2\ 16 U.S.C. 824d, 824e (2012).
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    2. This proceeding derives from Order No. 784,\3\ in which the 
Commission revised Part 35 of its regulations to reflect reforms to its 
Avista policy \4\ governing the sale of certain ancillary services at 
market-based rates to public utility transmission providers. 
Specifically, Order No. 784 found that when appropriate intra-hour 
transmission scheduling practices are in place, the Avista restrictions 
need not apply to the sale of Energy Imbalance, Generator Imbalance, 
Operating Reserve-Spinning and Operating Reserve-Supplemental services, 
because with those scheduling practices in place the existing market 
power screens for sales of energy and capacity can also be applied to 
sales of those ancillary services.\5\
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    \3\ Third-Party Provision of Ancillary Services; Accounting and 
Financial Reporting for New Electric Storage Technologies, Order No. 
784, 78 FR 46,178 (July 30, 2013), FERC Stats. & Regs. ] 31,349 
(2013).
    \4\ Avista Corp., 87 FERC ] 61,223, order on reh'g, 89 FERC ] 
61,136 (1999) (Avista). Outside the markets operated by regional 
transmission organizations and independent system operators, Avista 
authorizes suppliers who cannot show a lack of market power with 
respect to certain ancillary services to nevertheless sell such 
services, subject to certain restrictions. As relevant to this Final 
Rule, these restrictions prohibit sales to a public utility that is 
purchasing ancillary services to satisfy its own Open Access 
Transmission Tariff (OATT) requirements to offer ancillary services 
to its own customers, or sales to a traditional, franchised public 
utility affiliated with the third-party seller, or where the 
underlying transmission service is on the transmission system of the 
affiliated public utility.
    \5\ Order No. 784, FERC Stats. & Regs. ] 31,349 at P 4, PP 57-
58.
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    3. However, because of the unique technical and geographic 
requirements associated with Reactive Supply and Voltage Control (under 
OATT Schedule 2) and Regulation and Frequency Response (under OATT 
Schedule 3),\6\ the Commission only allowed market-based rate sales of 
Schedule 2 and Schedule 3 services to a public utility that is 
purchasing ancillary services to satisfy its OATT requirements if 
either: (a) The sale is made pursuant to a competitive solicitation 
that meets certain specified requirements; or (b) the sale is made at 
or below the buying public utility transmission provider's own Schedule 
2 or 3 rate, as applicable. The Commission further stated its intention 
to gather more information regarding the technical, economic and market 
issues concerning the provision of these services in a separate 
proceeding.
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    \6\ Id. PP 59-61. Although the title of Schedule 3 addresses 
both frequency response and regulation, the two services are 
distinct from each other. Frequency response is a resource standing 
by to provide autonomous, pre-programmed changes in output to 
rapidly arrest large changes in frequency until dispatched resources 
can take over while regulation service is centrally dispatched 
through automatic generation control (AGC) and is not focused 
exclusively on frequency control.
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    4. Commission staff held a workshop on April 22, 2014 in this 
proceeding and then issued a notice of proposed rulemaking that 
distinguished between regulation service and primary frequency response 
service, and proposed to allow sales of primary frequency response 
service at market-based rates by entities granted market-based rate 
authority for sales of energy and capacity.\7\ In response to the NOPR, 
19 sets of comments were submitted.
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    \7\ Third-Party Provision of Primary Frequency Response Service, 
Notice of Proposed Rulemaking (NOPR), 80 FR 10,426 (Feb. 26, 2015), 
FERC Stats. & Regs. ] 32,705 (2015).
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I. Background

    5. The Commission in Order No. 888 \8\ delineated two categories of 
ancillary services: Those that the transmission provider is required to 
provide to all of its basic transmission customers \9\ and those that 
the transmission provider is only required to offer to provide to 
transmission customers serving load in the transmission provider's 
control area.\10\ With respect to the second category, the Commission 
reasoned that the transmission provider is not always uniquely 
qualified to provide the services, and customers may be able to more 
cost-effectively self-supply them or procure them from other entities. 
The Commission contemplated that third parties (i.e., parties other 
than a transmission provider supplying ancillary services pursuant to 
its OATT obligation) could provide these ancillary services on other 
than a cost-of-service basis if such pricing was supported, on a case-
by-case basis, by analyses that demonstrated that the seller lacks 
market power in the relevant product market.\11\
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    \8\ See Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g, 
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order 
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. 
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \9\ The first category consists of Scheduling, System Control 
and Dispatch service and Reactive Supply and Voltage Control from 
Generation Sources service.
    \10\ The second category consists of Regulation and Frequency 
Response service, Energy Imbalance service, Operating Reserve-
Spinning service, and Operating Reserve-Supplemental service. Order 
No. 890 later added an additional ancillary service to this 
category: Generator Imbalance service. See Preventing Undue 
Discrimination and Preference in Transmission Service, Order No. 
890, FERC Stats. & Regs. ] 31,241, at P 85, order on reh'g, Order 
No. 890-A, FERC Stats. & Regs. ] 31,261 (2007), order on reh'g, 
Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No. 
890-C, 126 FERC ] 61,228 (2009), order on clarification, Order No. 
890-D, 129 FERC ] 61,126 (2009).
    \11\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-21.
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    6. Subsequently, in Avista,\12\ the Commission adopted a policy 
allowing third-party ancillary service providers that could not perform 
a market power study to sell certain ancillary services at market-based 
rates with certain restrictions.\13\
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    \12\ See supra n.4.
    \13\ These ancillary services included: Regulation and Frequency 
Response, Energy Imbalance, Operating Reserve-Spinning, and 
Operating Reserve-Supplemental. The Commission did not extend this 
Avista policy to Reactive Supply and Voltage Control from Generation 
Sources service, which means that third parties wishing to sell this 
ancillary service at market-based rates would be required to present 
specific evidence of a lack of market power in the provision of this 
specific product before the Commission would authorize sales of this 
service at market-based rates. The Commission also did not extend 
the Avista policy to Scheduling, System Control and Dispatch 
service. Because only balancing area operators can provide this 
ancillary service, it does not lend itself to competitive supply. 
Order No. 784, FERC Stats. & Regs. ] 31,349 at n.17.
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    7. As noted earlier, the instant proceeding derives from Order No. 
784 in which the Commission found that when appropriate intra-hour 
transmission scheduling practices are in place, the Avista restrictions 
need not apply to the sale of Energy Imbalance, Generator Imbalance, 
Operating Reserve-Spinning and Operating Reserve-Supplemental services, 
because with those practices in place, the results of the existing 
market power screens for sales of energy and capacity can also be 
applied to sales of these ancillary services.\14\
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    \14\ Because energy and generator imbalance services merely 
require the ability to respond to dispatch within the hour, the 
Commission found that any sub-hourly transmission scheduling 
interval would be sufficient. Order No. 784-A, 146 FERC ] 61,114 at 
P 12 (2012). As the operating reserve services require more rapid 
response within the hour (spinning reserves must be available 
immediately and supplemental reserves must be available within a 
short period of time), the Commission required potential sellers of 
operating reserve services to satisfactorily explain, in their 
market-based rate applications, how the particular intra-hour 
transmission scheduling practices or other protocols in their 
regions permit resources in one balancing authority area to respond 
to contingencies in a neighboring balancing authority area within 
these tight time frames. Order No. 784-A, 146 FERC ] 61,114 at PP 
13-15.

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[[Page 73967]]

    8. However, the Commission also found in Order No. 784 that the 
record developed to that point did not support expanding these market-
based rate authorizations to include sales of Reactive Supply and 
Voltage Control (under OATT Schedule 2) (Schedule 2 service) and 
Regulation and Frequency Response (under OATT Schedule 3) services 
(Schedule 3 service).\15\ Instead, the Commission allowed market-based 
rate sales of Schedule 2 and Schedule 3 services to a public utility 
that is purchasing ancillary services to satisfy its OATT requirements, 
provided the sale is made pursuant to a competitive solicitation that 
meets certain specified requirements \16\ or the sale is made at or 
below the buying public utility transmission provider's own Schedule 2 
or 3 rate, as applicable.\17\ The Commission further stated its 
intention to gather more information regarding the technical, economic 
and market issues concerning the provision of these services in a 
separate proceeding that considers, among other things, the ease and 
cost-effectiveness of relevant equipment upgrades, the need for and 
availability of appropriate special arrangements such as dynamic 
scheduling or pseudo-tie arrangements, and other technical requirements 
related to the provision of Schedule 2 and Schedule 3 services.\18\
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    \15\ Order No. 784, FERC Stats. & Regs. ] 31,349 at PP 59-61.
    \16\ Id. PP 99-101.
    \17\ Id. PP 82-85.
    \18\ Id. P 61.
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    9. Pursuant to that directive, Commission staff held a workshop on 
April 22, 2014 to obtain input from interested persons regarding the 
technical, economic and market issues concerning the provision of 
Schedule 2 and Schedule 3 services.\19\ Among other things, the 
workshop explored issues surrounding the sale of these services at 
market-based rates. Comments submitted in response to the workshop that 
discussed the characteristics associated with a primary frequency 
response product indicated that market-based rate sales of such a 
product are feasible.\20\
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    \19\ See Third-Party Provision of Reactive Supply and Voltage 
Control and Regulation and Frequency Response Services, Final 
Agenda, Docket No. AD14-7-000 (Apr. 22, 2014).
    \20\ For example, most commenters echo Edison Electric 
Institute's (EEI) arguments that virtually all generators can 
provide primary frequency response, and because it is provided at 
the interconnection level, balancing authority areas have more 
flexibility on the location of the resource than they would for 
other products. See, e.g., Edison Electric Institute Post-Workshop 
Comments, Docket No. AD14-7-000, at 7-8 (filed June 3, 2014).
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    10. Separately, the Commission on January 16, 2014 issued a Final 
Rule approving reliability standard BAL-003-1 \21\ under which a 
balancing authority \22\ must maintain a minimum frequency response 
obligation.\23\ While most balancing authorities should be able to meet 
the new reliability standard using their own resources,\24\ some may 
nevertheless be interested in purchasing primary frequency response 
service from others if doing so would be economically beneficial.
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    \21\ Reliability standards proposed by the North American 
Electric Reliability Corporation (NERC) are subject to the 
Commission's jurisdiction under section 215 of the Federal Power 
Act. 16 U.S.C. 824o(d). The Commission has authority to approve or 
reject such standards, and to enforce those that are approved.
    \22\ The NERC Glossary defines a balancing authority as ``(t)he 
responsible entity that integrates resource plans ahead of time, 
maintains load-interchange-generation balance within a Balancing 
Authority Area, and supports Interconnection frequency in real 
time.'' See http://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
    \23\ See Frequency Response and Frequency Bias Setting 
Reliability Standard, Order No. 794, 146 FERC ] 61,024 (2014).
    \24\ Id. PP 62-63.
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    11. Based upon information received at the workshop and in the 
subsequently-filed 11 written comments, the Commission issued a NOPR 
that differentiated between regulation service and primary frequency 
response service, analyzed the technical characteristics of primary 
frequency response service to show why the existing market power 
screens for sales of energy and capacity could be used to show lack of 
market power for sales of primary frequency response as well, and 
therefore proposed to allow sales of primary frequency response service 
at market-based rates by entities granted market-based rate authority 
for sales of energy and capacity.\25\ The NOPR sought comment on all 
aspects of this proposal.\26\
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    \25\ NOPR, FERC Stats. & Regs. ] 32,705 (2015). With respect to 
the remainder of the issues discussed in the workshop and associated 
written comments, the Commission did not see sufficient evidence to 
pursue generic reforms through this rulemaking proceeding. Id. P 10.
    \26\ Id. P 30.
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    12. Most of the 19 sets of comments submitted in response to the 
NOPR are supportive of the proposal, with some commenters seeking 
clarification of various issues. Meanwhile, the limited set of adverse 
comments fall into two broad categories: (1) Comments seeking to 
contest the technical arguments regarding market power relied upon by 
the NOPR; and (2) comments that do not relate to market power screening 
but rather relate to various aspects of the implementation of actual 
primary frequency response transactions.
    13. For the reasons described more fully below, the Commission 
finds that it is appropriate to finalize the NOPR proposal to permit 
voluntary sales of primary frequency response service at market-based 
rates for entities granted market-based rate authority for sales of 
energy and capacity. We also address various requests for 
clarification, as discussed more fully below. We emphasize that this 
Final Rule does not place any limits on the types of transactions 
available to procure primary frequency response service; they may be 
cost-based or market-based, bundled with other services or unbundled as 
discussed further below, and inside or outside of organized markets. 
This Final Rule focuses solely on how jurisdictional entities can 
qualify for market-based rates for primary frequency response service 
in the context of voluntary bilateral sales.

II. Discussion

    14. In the NOPR in this proceeding, the Commission proposed to 
define primary frequency response service as the ``autonomous, 
automatic, and rapid action of a generator, or other resource, to 
change its output (within seconds) to rapidly dampen large changes in 
frequency.'' \27\ Elsewhere in the NOPR, the Commission discussed the 
idea that individual autonomous responses to large changes in frequency 
will be of short duration, sustained only until dispatched regulation 
or operating reserve resources begin responding.\28\ As there are 
aspects of both statements that are important to properly defining this 
product, in this Final Rule the Commission will refine and clarify the 
NOPR's definition to state that primary frequency response service is 
defined as a resource standing by to provide autonomous, pre-programmed 
changes in output to rapidly arrest large changes in frequency until 
dispatched resources can take over.
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    \27\ Id. P 12.
    \28\ Id. P 24.

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[[Page 73968]]

A. Technical Issues Related to the Application of Existing Market Power 
Screens to Primary Frequency Response Service

1. Geographic Market and the Impact of Resource Distance
    15. The Commission analyzes horizontal market power for market-
based sales of energy and capacity \29\ using two indicative screens, 
the wholesale market share screen and the pivotal supplier screen, to 
identify sellers that raise no horizontal market power concerns and can 
otherwise be considered for market-based rate authority.\30\ The 
wholesale market share screen measures whether a seller has a dominant 
position in the relevant geographic market in terms of the number of 
megawatts of uncommitted capacity owned or controlled by the seller, as 
compared to the uncommitted capacity of the entire market.\31\ A seller 
whose share of the relevant market is less than 20 percent during all 
seasons passes the wholesale market share screen.\32\ The pivotal 
supplier screen evaluates the seller's potential to exercise horizontal 
market power based on the seller's uncommitted capacity at the time of 
annual peak demand in the relevant market.\33\ A seller satisfies the 
pivotal supplier screen if its uncommitted capacity is less than the 
net uncommitted supply in the relevant market.\34\
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    \29\ See 18 CFR 35.37(b) (2015).
    \30\ See Market-Based Rates for Wholesale Sales of Electric 
Energy, Capacity and Ancillary Services by Public Utilities, Order 
No. 697, FERC Stats. & Regs. ] 31,252 at PP 13, 62, clarified, 121 
FERC ] 61,260 (2007), order on reh'g, Order No. 697-A, FERC Stats. & 
Regs. ] 31,268, clarified, 124 FERC ] 61,055, order on reh'g, Order 
No. 697-B, FERC Stats. & Regs. ] 31,285 (2008), order on reh'g, 
Order No. 697-C, FERC Stats. & Regs. ] 31,291 (2009), order on 
reh'g, Order No. 697-D, FERC Stats. & Regs. ] 31,305 (2010), aff'd 
sub nom. Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 
2011), cert. denied, 133 S. Ct. 26 (2012). See also 18 CFR 35.37(b), 
(c)(1) (2015).
    \31\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 43.
    \32\ Id. PP 43-44, 80, 89.
    \33\ 18 CFR 35.37(c)(1) (2015).
    \34\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 42.
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    16. Passing both the wholesale market share screen and the pivotal 
supplier screen creates a rebuttable presumption that the seller does 
not possess horizontal market power; failing either screen creates a 
rebuttable presumption that the seller possesses horizontal market 
power.\35\ A seller that fails one of the screens may present evidence, 
such as a delivered price test, to rebut the presumption of horizontal 
market power.\36\ In the alternative, a seller may accept the 
presumption of horizontal market power and adopt some form of cost-
based mitigation.\37\
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    \35\ 18 CFR 35.37(c)(1) (2015).
    \36\ 18 CFR 35.37(c)(2) (2015). For purposes of rebutting the 
presumption of horizontal market power, sellers may use the results 
of the delivered price test to perform pivotal supplier and market 
share analyses and market concentration analyses using the 
Herfindahl-Hirschman Index (HHI). The HHI is a widely accepted 
measure of market concentration, calculated by squaring the market 
share of each firm competing in the market and summing the results. 
The Commission has stated that a showing of an HHI less than 2,500 
in the relevant market for all season/load periods for sellers that 
have also shown that they are not pivotal and do not possess a 
market share of 20 percent or greater in any of the season/load 
periods would constitute a showing of a lack of horizontal market 
power, absent compelling contrary evidence from intervenors. Order 
No. 697, FERC Stats. & Regs. ] 31,252 at P 111.
    \37\ 18 CFR 35.37(c)(3) (2015).
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    17. Three of the key components of the analysis of horizontal 
market power are the definition of products, the determination of 
appropriate geographic scope of the relevant market for each product, 
and the identification of the uncommitted generation supply within the 
relevant geographic market. In Order No. 697, the Commission adopted a 
default relevant geographic market for sales of energy and 
capacity.\38\ Specifically, the Commission generally uses a seller's 
balancing authority area plus directly interconnected (first-tier) 
balancing authority areas, or uses the Regional Transmission 
Organization (RTO) or Independent System Operator (ISO) market if 
applicable, as the default relevant geographic market. However, where 
the Commission has made a specific finding that there is a submarket 
within an RTO/ISO, that submarket becomes the default relevant 
geographic market for sellers located within the submarket for purposes 
of the market-based rate analysis. The Commission also provided 
guidance as to the factors the Commission will consider in evaluating 
whether, in a particular case, to adopt an alternative larger or 
smaller geographic market instead of relying on the default geographic 
market.\39\
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    \38\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 15.
    \39\ A necessary condition that must be satisfied to justify an 
alternative market is a demonstration regarding whether there are 
frequently binding transmission constraints during historical peak 
seasons examined in the screens and at other competitively 
significant times that prevent competing supply from reaching 
customers within the proposed alternative geographic market. Id. P 
268.
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    18. The Commission stated in the NOPR that, because primary 
frequency response service can be effectively supplied by any resource 
throughout an interconnection and have the same ability to dampen 
harmful changes in interconnection-wide frequency, the geographic 
market for market power analysis of a primary frequency response 
product could be the entire interconnection within which the buyer 
resides, and in any event would be no smaller than the geographic 
market represented in the existing market power screens; \40\ i.e., the 
home balancing authority area of the seller plus first-tier balancing 
authority areas or the RTO/ISO market if applicable. The Commission 
therefore proposed to apply the existing market power screens used for 
energy and capacity sales, without modification as to geographic 
market, to sales of primary frequency response service.
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    \40\ NOPR, FERC Stats. & Regs. ] 32,705 at P 23.
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    19. Most commenters either express specific support for this 
finding,\41\ or are silent on the issue.\42\ However, American Public 
Power Association, the National Rural Electric Cooperative Association, 
and the Transmission Access Policy Study Group (together, TAPS), PJM 
Interconnection, L.L.C. (PJM), and Midcontinent Independent System 
Operator, Inc. (MISO) raise limited, technical concerns regarding this 
finding.
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    \41\ See, e.g., American Wind Energy Association (AWEA) at 6; 
Calpine Corporation (Calpine) at 5; EEI at 2; Electricity Consumers 
Resources Council (ELCON) at 3.
    \42\ See Dominion Resources Services, Inc. (Dominion) at 2; Duke 
Energy Corporation (Duke) at 3; Electric Power Supply Association 
(EPSA) at 3; Energy Storage Association (ESA) at 1; Idaho Power 
Company (Idaho Power) at 2; Public Interest Organizations at 2.
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    20. TAPS argues that while remote generators may be capable of 
responding, there is reason to be concerned that frequency response 
from a distant generator would be less effective than frequency 
response from a nearby generator, and that this alleged impact of 
distance would upset the Commission's proposal to rely on the existing 
market-based rate screens used for energy and capacity sales to ensure 
that sellers of primary frequency response service lack market power 
when making sales to public utility transmission providers.\43\
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    \43\ TAPS at 5-6.
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    21. PJM similarly asserts, without elaboration, that questions 
remain as to whether there is sufficient substitutability of units 
across the Eastern Interconnection so as to support the conclusion that 
market power issues are of limited concern in the provision of primary 
frequency response. PJM also asserts that the kind of communications 
infrastructure, protocols, and compensation policies necessary to 
permit PJM to obtain primary frequency

[[Page 73969]]

response from resources outside of its market do not yet exist.\44\
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    \44\ PJM at 4.
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    22. MISO argues that, while the NOPR is correct that any resource 
anywhere in an interconnection can help stabilize the frequency of that 
interconnection following a load or resource loss, there may be 
negative reliability impacts caused by flows to very remote locations, 
particularly if there are weak or transmission-limited interfaces.\45\
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    \45\ MISO at 5.
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Commission Determination
    23. We adopt the NOPR proposal to apply the existing market power 
screens used for energy and capacity sales, without modification as to 
geographic market, to sales of primary frequency response service. With 
respect to TAPS's arguments, the Commission finds that the delay in 
sensing a change in frequency associated with resource distance does 
not undermine the NOPR's proposal to rely upon the default geographic 
market reflected in the existing market power screens for sales of 
energy and capacity; i.e., the home balancing authority area of the 
seller plus first-tier balancing authority areas or the RTO/ISO market 
if applicable. While TAPS is correct that a resource located far across 
an interconnection from the site of a contingency event should sense 
the resulting change in frequency later than would a closer resource, 
studies of this issue \46\ indicate that this delay would be within the 
NOPR's product definition that requires primary frequency response 
resources to change their output within seconds in response to a large 
change in frequency.\47\
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    \46\ See, e.g., http://fnetpublic.utk.edu/eventsamples/20110823175058_E.jpg. See also, John Undrill, Power and Frequency 
Control as it Relates to Wind-Powered Generation (2010), available 
at http://www.ferc.gov/CalendarFiles/20110120114503-Power-and-Frequency-Control.pdf.
    \47\ NOPR, FERC Stats. & Regs. ] 32,705 at P 12.
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    24. With respect to PJM's assertion that questions remain as to the 
substitutability of units across the Eastern Interconnection, PJM has 
not explained what those questions may be, and in any event the NOPR 
does not propose to test market power based on an interconnection-wide 
geographic market.
    25. With respect to PJM's argument that the kind of communications 
infrastructure, protocols, and compensation policies necessary to 
permit PJM to obtain primary frequency response from resources outside 
of its market do not yet exist, the Commission partially agrees and 
partially disagrees as described below, but even where we partially 
agree, this would not impact the NOPR proposal regarding market power 
screening.
    26. With respect to communications protocols, the Commission agrees 
that in order to effectuate actual voluntary primary frequency response 
transactions, it may be necessary to further develop or refine existing 
communications protocols, as more detailed data may be needed for 
purposes of verifying primary frequency response activity than for 
other activities. However, this refinement should not pose such a 
fundamental barrier to sales of primary frequency response service from 
one balancing authority area to another that it calls into question the 
default geographic market of the existing market power screens. This is 
because, as will be discussed further below, there are existing 
information sharing systems and protocols that should be able to 
accommodate the more detailed information associated with primary 
frequency response transactions without requiring an unreasonable 
amount of effort from affected parties. Hence, for market power 
screening purposes, resources in first-tier balancing authority areas 
should remain viable competitors to supply primary frequency response 
to the home balancing authority area.
    27. With respect to compensation policies, the Commission disagrees 
with PJM that compensation policies necessary to support this Final 
Rule do not yet exist. As will be further discussed below, this Final 
Rule does not require development of organized markets for primary 
frequency response service, but rather is focused on voluntary 
bilateral sales of primary frequency response at market-based rates. In 
bilateral markets, compensation would be negotiated between the buyer 
and the seller pursuant to the seller's market-based rate authority. As 
such, bilateral transactions will be strictly voluntary and the buyer 
will presumably only agree to them if it sees an economic reason to do 
so. Therefore, no further compensation policies are necessary in 
connection with this Final Rule.
    28. Finally, MISO argues that there may be negative reliability 
impacts caused by flows to very remote locations, particularly if there 
are weak or transmission-limited interfaces. The Commission agrees but 
sees this as a practical consideration relevant to particular bilateral 
transactions rather than a universal issue that invalidates the use of 
existing market power screens to show lack of market power for sales of 
primary frequency response service. Accordingly, this argument does not 
invalidate the NOPR proposal regarding market power screening for 
sellers of primary frequency response service.
2. Need for Transmission Reservation and Scheduling
    29. With respect to potential barriers related to transmission 
scheduling or reservation, the Commission stated in the NOPR that 
primary frequency response service should not require any transmission 
reservation or scheduling, because by definition individual frequency 
responses would not be sustained for long enough periods to trigger a 
need for transmission service or schedule changes. Rather, such 
individual primary frequency responses should be rapidly replaced by 
resources centrally dispatched by the relevant balancing authority.\48\
---------------------------------------------------------------------------

    \48\ NOPR, FERC Stats. & Regs. ] 32,705 at P 24.
---------------------------------------------------------------------------

    30. Most commenters either specifically agree that transmission 
scheduling and reservation should not be necessary in connection with 
the temporary, autonomous changes in output associated with primary 
frequency response service,\49\ or remain silent on the issue. However, 
EEI asserts that transmission reservation or scheduling may be needed 
in some cases. According to EEI, the duration of primary frequency 
response products could range from a minute or two to supplement a 
response for only large events, to an unbounded number of minutes for 
as long as frequency remains beyond a given frequency deadband. In the 
case of longer durations, according to EEI, transmission providers may 
have to assess the potential transmission impact of third-party 
resources providing primary frequency response through their service 
territory for extended periods of time.\50\ Duke makes similar 
arguments.\51\
---------------------------------------------------------------------------

    \49\ See, e.g., AWEA at 6; ELCON at 3; MISO at 1.
    \50\ EEI at 8.
    \51\ Duke at 7-8.
---------------------------------------------------------------------------

    31. Similarly, TAPS argues that the Commission did not adequately 
examine in the NOPR the implications of remote provision of primary 
frequency response on transmission availability and co-optimization of 
energy and ancillary services. TAPS argues the Commission should 
provide additional analysis of how remote supply of frequency response 
service will affect transmission reserve margin and available transfer 
capability, how the associated costs are borne, and whether this will 
have adverse

[[Page 73970]]

consequences for market efficiency, particularly in RTOs.\52\
---------------------------------------------------------------------------

    \52\ TAPS at 9-11.
---------------------------------------------------------------------------

Commission Determination
    32. The Commission continues to believe that transmission 
reservation and scheduling will not create a barrier to sales of 
frequency response within an interconnection. While the Commission 
concedes that in some cases transmission capacity may need to be 
reserved to support a sale of primary frequency,\53\ we continue to 
believe that in the vast majority of cases the sale of primary 
frequency response service should not require any transmission 
reservation or scheduling because, by definition, individual frequency 
responses would not be sustained for long enough periods to trigger a 
need for transmission service or schedule changes. With respect to 
EEI's arguments, the Commission disagrees that primary frequency 
response, as defined in this Final Rule, could last for an unbounded 
number of minutes. By the definition of primary frequency response 
provided in this Final Rule, individual primary frequency responses 
shall be short, lasting only until dispatched resources can take over. 
Thus, even if a deviation from target frequency lasts longer than the 
typical short responses envisioned by our primary frequency response 
product definition, this does not necessarily mean that a particular 
resource that continues to respond to that deviation is doing so 
through extended periods of primary frequency response service as EEI 
suggests.
---------------------------------------------------------------------------

    \53\ The Commission expects that sales of primary frequency 
response from resources in transmission constrained areas would 
constitute the most likely scenario where a reservation of 
transmission capacity might be needed to support the sale. 
Naturally, the added cost of such transmission purchases would 
likely be considered by the potential purchaser in deciding whether 
or not to enter into such purchase.
---------------------------------------------------------------------------

    33. Rather, after the initial autonomous response, any continuing 
response would be deemed to occur as a result of dispatch instructions 
from the relevant balancing authority, which would most likely 
constitute either use of regulation or operating reserves. Accordingly, 
while a transmission reservation may sometimes be needed to support a 
sale of primary frequency response, there should never be a need to 
actually schedule transmission or change a transmission schedule in 
connection with primary frequency response service. Hence, transmission 
scheduling should pose no barrier to sales of primary frequency 
response service, and in the open access transmission environment 
created by Order No. 888, reservation by itself does not present any 
undue barrier to participation. Indeed, all other ancillary service 
transactions, at least in bilateral markets, are expected to include 
needed transmission reservation.
    34. With respect to TAPS's argument, the Commission agrees that 
transmission providers may in some cases need to set aside additional 
transmission capacity to support particular sales of primary frequency 
response from remote resources. However, the possibility that 
particular transactions involving remote resources may require 
additional transmission capacity to be set aside does not undermine the 
NOPR proposal to grant market-based rate authority for voluntary sales 
of primary frequency response to entities that pass the existing market 
power screens for sales of energy and capacity. These screens already 
limit consideration of imports from first-tier balancing authority 
areas based on simultaneous transmission import limits as a way to test 
market power under realistic conditions based on a reasonable 
simulation of historical conditions.\54\ No further consideration of 
transmission impacts is necessary to test for seller market power. 
Analysis of (1) how remote supply of primary frequency response service 
in particular transactions might affect transmission reserve margin and 
available transfer capability; (2) how the associated costs would be 
borne; or (3) whether this might have adverse consequences for market 
efficiency are concerns that are not relevant to the Commission's 
market power assessment. Rather, these are concerns that may impact a 
balancing authority's decision as to whether to enter into any given 
primary frequency response transaction, or that may become relevant if 
any RTO or ISO voluntarily chooses to develop an organized market for 
primary frequency response--something that is not required by this 
Final Rule.
---------------------------------------------------------------------------

    \54\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 354.
---------------------------------------------------------------------------

    35. With respect to TAPS's arguments regarding potential distortion 
of co-optimized RTO/ISO energy and ancillary service markets, this 
Final Rule merely clarifies the appropriate method for ex ante market 
power screening for potential sellers of primary frequency response 
service. It does not require any entity, including RTOs and ISOs, to 
purchase primary frequency response. Nor does it require RTOs and ISOs 
to develop organized markets for primary frequency response. The 
Commission finds it reasonable to assume that if an RTO or ISO ever 
decides to purchase primary frequency response service, it will only do 
so if the RTO or ISO can address its and its stakeholders' concerns as 
to the impact on its co-optimized markets. Furthermore, if such 
purchases require any tariff modifications, the RTO or ISO would also 
need to submit a filing to the Commission for its review addressing 
such issues. Accordingly, in the context of this Final Rule focusing on 
market power screens, these concerns are premature and beyond the 
scope.

B. Requests for Clarification

1. Purchases Required or Optional
    36. A variety of entities request clarification that this Final 
Rule does not require purchases of primary frequency response or the 
development of organized markets for primary frequency response.\55\ At 
the other end of the spectrum, Calpine argues that RTOs and ISOs should 
be given a deadline to develop tariff changes that would enable them to 
implement primary frequency response compensation mechanisms.\56\
---------------------------------------------------------------------------

    \55\ EEI at 1-2; California Independent System Operator 
Corporation (CAISO) at 2; MISO at 1; PJM at 2, 5.
    \56\ Calpine at 9.
---------------------------------------------------------------------------

    37. The Commission grants the requests to clarify that this Final 
Rule does not require any entity to purchase primary frequency response 
from third parties or to develop an organized market for primary 
frequency response. This Final Rule is limited to issues associated 
with market power screening for voluntary bilateral sellers of primary 
frequency response service. In light of this clarification, we deny 
Calpine's request for RTOs and ISOs to be given a deadline to develop 
tariff changes that would enable them to implement primary frequency 
response compensation mechanisms.
2. Interaction With Regulation Service
    38. EEI and Duke both request that sellers be able to retain the 
reference to ``Regulation and Frequency Response Service'' in their 
current market-based rate tariffs, and that the Final Rule make clear 
that providing market-based rate authorization for primary frequency 
response service is not intended to limit the options that buyers have 
in procuring these ancillary services.\57\
---------------------------------------------------------------------------

    \57\ EEI at 4; Duke at 3-7.
---------------------------------------------------------------------------

    39. The Commission does not intend to limit the options that buyers 
have in procuring these ancillary services but will nevertheless affirm 
the NOPR proposal to require a separate listing of regulation service 
and primary frequency response service in market-

[[Page 73971]]

based rate tariffs. However, to address EEI's and Duke's concerns, the 
Commission clarifies that, even though we require that regulation 
service and primary frequency response service be separately listed in 
sellers' market-based rate tariffs, this does not mean that buyers and 
sellers cannot agree to combined transactions involving both regulation 
service and primary frequency response service with appropriate 
restrictions. Those restrictions involve the need for the market-based 
regulation service component to be limited to the buyer's OATT rate for 
regulation or the outcome of a competitive solicitation as described in 
Order No. 784.\58\ No such restrictions would apply to the primary 
frequency response service component of such combined transactions.
---------------------------------------------------------------------------

    \58\ Order No. 784, FERC Stats. & Regs. ] 31,349 at PP 82 and 
99-101.
---------------------------------------------------------------------------

    40. Duke also expresses concern as to what impact splitting the 
services in the ``Third Party Provider'' section of the market-based 
rate tariff would have on transmission providers and any transmission 
customers self-providing service under Schedule 3 of the OATT.\59\
---------------------------------------------------------------------------

    \59\ Duke at 6, 8.
---------------------------------------------------------------------------

    41. The Commission clarifies that OATT Schedule 3 serves a 
different purpose from the market-based rate tariff (cost-based sales 
from the OATT provider versus market-based sales from third parties), 
and so OATT Schedule 3 does not need modification as a result of this 
Final Rule. However, to the extent that a particular OATT provider 
purchases primary frequency response from a third party in order to 
help serve its OATT customers, it may propose in a section 205 filing 
to include such costs in its OATT Schedule 3 rates.
3. Information Sharing and Measurement and Verification
    42. A variety of entities emphasize the importance of adequate 
information sharing and measurement and verification if primary 
frequency response service is to be traded.\60\ In this regard, 
SmartSenseCom, Inc. (SmartSenseCom) also argues that in order to 
support the broadest base of available resources to provide primary 
frequency response services, potential providers should have 
flexibility in their ability to select any monitoring device that meets 
or exceeds applicable industry standards for accuracy as a means to 
measure frequency and trigger the primary frequency response at a given 
set point.\61\
---------------------------------------------------------------------------

    \60\ CAISO at 2-3; EEI at 5; MISO at 1-4; Duke at 7-8; Dominion 
at 3; Idaho Power at 2.
    \61\ SmartSenseCom at 9-10.
---------------------------------------------------------------------------

    43. The Commission agrees that these matters are important, and 
expects that potential buyers will ensure that the resources from which 
they purchase are capable of providing the service in a useful manner, 
consistent with relevant NERC requirements and guidelines as discussed 
earlier. This would require that, among other things, the parties agree 
to appropriate information sharing and measurement and verification. At 
this stage, and given the voluntary nature of any primary frequency 
response transactions that may result from this Final Rule, the 
Commission sees no need to be more prescriptive regarding specific 
methods of information sharing and measurement and verification.
    44. In a related matter, TAPS asserts that the NOPR's statement 
that telemetry sharing should not pose any significant barrier to the 
use of remote resources for the purposes of market-based rates requires 
further evaluation. TAPS argues that transmitting the telemetry data 
from one balancing authority area to just one other balancing authority 
area effectively doubles (or more) the number of points at which the 
data can be intercepted or attacked. Thus, TAPS argues that the 
Commission should provide additional analysis to evaluate whether these 
potential technical barriers will impede the ability of remote 
generators to compete to make market-based rate sales of primary 
frequency response across balancing authorities and to multiple 
balancing authorities.\62\
---------------------------------------------------------------------------

    \62\ TAPS at 6-9.
---------------------------------------------------------------------------

    45. As mentioned earlier, the Commission finds that balancing 
authorities already share with their neighbors the same type of 
operational information contemplated here, both on a day-to-day basis, 
and occasionally through special arrangements like pseudo-ties or 
dynamic schedules, though they may not do so with as much detail as 
would be required for primary frequency response. In sharing such 
information, they use secure protocols such as Inter-Control Center 
Communications Protocol.\63\ There appears to be nothing unique about 
information related to primary frequency response transactions, which 
would largely involve the real-time operational state of the resources 
in question as a way of verifying both their readiness to respond and 
actual responses to relevant frequency deviations, that could not be 
accommodated by this existing secure protocol widely used by the 
electric utility industry. As a result, the Commission continues to 
believe that the information sharing required to facilitate sales of 
primary frequency response service will not create a barrier to such 
sales and thus we find in this Final Rule that the market power screens 
used for energy and capacity are valid for primary frequency response 
service.
---------------------------------------------------------------------------

    \63\ See International Electroctechnical Commission, Telecontrol 
equipment and systems--Part 6-802: Telecontrol protocols compatible 
with ISO standards and ITU-T recommendations--TASE.2 Object models 
(Sept. 2005), available at https://webstore.iec.ch/publication/18156.
---------------------------------------------------------------------------

4. Definition of Primary Frequency Response Service
    46. Parties request various clarifications regarding the definition 
of primary frequency response service. Calpine and EPSA assert that the 
product definition for primary frequency response service should 
include both inertial response from conventional ``spinning mass'' 
generators and primary frequency response from discretionary turbine-
governor settings.\64\ Similarly, Union of Concerned Scientists argues 
for the inclusion of synchronous and/or synthetic inertia as a market 
product that can be used to provide primary frequency response, and 
requests that the Commission clarify whether the creation of markets 
for inertia is within the scope of changes that were envisioned by the 
Commission when it issued this NOPR.\65\
---------------------------------------------------------------------------

    \64\ Calpine at 7, n.16; EPSA at 5.
    \65\ Union of Concerned Scientists at 8.
---------------------------------------------------------------------------

    47. The Commission emphasizes that this Final Rule addresses 
market-based rate authority for sales of services that fit the 
definition of primary frequency response services, i.e., resources 
standing by to provide autonomous, pre-programmed changes in output to 
rapidly arrest large changes in frequency until dispatched resources 
can take over. True inertia, while also serving an important function, 
does not fit this definition because it does not arrest large changes 
in frequency, but rather acts to oppose all changes in frequency. The 
term ``synthetic inertia'' is more complicated to address because it is 
not clear from the record whether there is actual industry consensus on 
what the term means. However, if it is assumed to mean a resource 
standing by to provide autonomous, pre-programmed changes in output to 
rapidly arrest large changes in frequency until dispatched resources 
can take over, then the Commission would simply consider it a form of 
primary frequency response subject to this Final Rule. In contrast, if 
the ``synthetic inertia'' response either cannot be sustained until 
dispatched

[[Page 73972]]

resources take over, or is merely aimed at slowing all changes in 
frequency instead of arresting large changes, then ``synthetic 
inertia'' would not be a form of primary frequency response, and sales 
of it would not be encompassed by this Final Rule.
    48. Several commenters assert that the product definition must 
differentiate based on response time in addition to magnitude of 
response.\66\ Consistent with this idea, SmartSenseCom asks the 
Commission to amend section 35.28 of its regulations by adding a new 
paragraph that states the following:
---------------------------------------------------------------------------

    \66\ Calpine at 7; AWEA at 4; Grid Storage Consulting at 2-4; 
Public Interest Organizations at 4; SmartSenseCom at 8.

Primary frequency response in ancillary service markets. Each 
Commission approved independent system operator or regional 
transmission organization that has a tariff that provides for the 
compensation for primary frequency response service must provide 
such compensation based upon the actual service provided, include a 
capacity payment that takes into account the speed of primary 
frequency response-providing resources and a payment for performance 
that reflects the quantity of primary frequency response provided by 
a resource in response to a frequency deviation.\67\
---------------------------------------------------------------------------

    \67\ SmartSenseCom at Ex. A.

    49. The Commission finds that the Final Rule's product definition, 
summarized at the beginning of the discussion section above, already 
sufficiently incorporates the importance of speed. The Commission finds 
that no further differentiation based on response time or magnitude is 
necessary in connection with this Final Rule, which deals only in the 
appropriate ex ante market power screening of potential sellers of 
primary frequency response service. For this reason, and because this 
Final Rule does not require development of organized markets for 
primary frequency response, the Commission also denies as unnecessary 
the requested addition to the Commission's regulations related to 
organized RTO and ISO markets for primary frequency response.
    50. Grid Storage Consulting, LLC (Grid Storage Consulting) and 
Public Interest Organizations argue that the product definition for 
this service should require response that is immediate, bi-directional, 
proportional to the frequency deviation, continuous in the sense of not 
being prematurely interrupted by competing controls or physical 
limitations, and certain.\68\ The Commission clarifies that potential 
voluntary buyers and sellers of primary frequency response service are 
free to negotiate any refinements to the basic product definition in 
this Final Rule that they see fit, so long as such refinements remain 
consistent with the basic definition. Obviously, any market-based rate 
authority granted as a result of this Final Rule would only apply to 
products that are consistent with the definition of primary frequency 
response service described at the beginning of the discussion section 
above.
---------------------------------------------------------------------------

    \68\ Grid Storage Consulting at 4-7; Public Interest 
Organizations at 4.
---------------------------------------------------------------------------

    51. SmartSenseCom urges the Commission to define primary frequency 
response directly within the Commission's regulations.\69\ The 
Commission denies this request as unnecessary. The Commission's 
regulations do not include definitions of every particular product 
subject to its jurisdiction; it is sufficient for such product 
definitions to be described in relevant Commission orders such as this 
one.
---------------------------------------------------------------------------

    \69\ SmartSenseCom at 3.
---------------------------------------------------------------------------

5. Miscellaneous Requests for Clarification
    52. EEI encourages the Commission to make clear in the Final Rule 
that a potential third-party provider would not be disqualified from 
competing on the basis that it is interconnected to an affiliated 
transmission provider. According to EEI, not addressing the affiliate 
restriction provisions of the Avista policy could unnecessarily limit 
the pool of third-party generators that would be eligible to compete to 
provide market-based primary frequency response service.\70\
---------------------------------------------------------------------------

    \70\ EEI at 7.
---------------------------------------------------------------------------

    53. EEI's concern relates to the component of the Avista 
restrictions highlighted below:

(2) to address affiliate abuse concerns, the approach [permitting 
market-based rate sales of ancillary services without a 
corresponding market power analysis] will not apply to sales to a 
traditional, franchised public utility affiliated with the third-
party supplier, or to sales where the underlying transmission 
service is on the system of the public utility affiliated with the 
third-party supplier.\71\
---------------------------------------------------------------------------

    \71\ Avista Corp., 87 FERC ] 61,223 at n.12 (1999) (emphasis 
added).

    54. As the Commission noted in the Avista passage quoted above, 
this second Avista restriction was meant to address affiliate abuse. 
However, EEI's concern that potential third-party providers should not 
be disqualified from competing on the basis that they are 
interconnected to an affiliated transmission provider appears to be 
based on an overly broad interpretation of the language highlighted 
above; i.e., one that would prevent sales that only tangentially 
involve the affiliated public utility transmission provider's system. 
While the Commission understands this concern, we do not believe it is 
justified because the highlighted language targets a much narrower set 
of circumstances.
    55. In particular, in Ameren Marketing,\72\ the Commission approved 
a case-by-case request for market-based rates for ancillary services 
sales by a third-party seller to transmission customers located on the 
transmission system of the seller's public utility transmission 
provider affiliate where the seller offered several safeguards to 
protect against the potential for affiliate abuse.\73\ Ameren Marketing 
demonstrates the narrow scope of the Commission's concern related to 
this Avista restriction; namely, third-party sales to customers located 
on the transmission systems of affiliates. Only in these situations 
does the second Avista restriction apply, and in these situations, we 
remain willing to consider requests for market-based rate authority for 
sales of primary frequency response service on a case-by-case basis. In 
response to EEI's concern, the Commission clarifies that where the 
customer is not located on the transmission system of the third-party 
seller's affiliate, this aspect of the Avista restrictions does not 
apply.
---------------------------------------------------------------------------

    \72\ Ameren Energy Marketing Co., 95 FERC ] 61,448, at 62,626 
(2001) (Ameren Marketing).
    \73\ With respect to all three Avista restrictions, the 
Commission expressed its willingness to consider requests for 
market-based rate authority under the conditions associated with the 
restrictions on a case-by-case basis. Avista Corp., 87 FERC ] 61,223 
at n.12.
---------------------------------------------------------------------------

    56. EEI also recommends that the Commission clarify in the Final 
Rule that the location of primary frequency response purchases be 
deemed to be where the customer is located within an interconnection, 
rather than where the underlying generation resides. According to EEI, 
this would address a potential ambiguity in how the NOPR proposal is 
described in paragraph 28 of the NOPR, where the Commission stated that 
``. . . sellers passing existing market-based rate screens in a given 
geographic market should be granted a rebuttable presumption that they 
lack market power for sales of primary frequency response in that 
market.'' \74\ EEI states that if a generator has passed the 
Commission's existing market power screens (or if the screens are not 
required to be submitted based on the location of the generation) for 
the geographic market in which the buyer is located, then the generator 
should benefit from the rebuttable presumption

[[Page 73973]]

that it lacks market power with respect to sales of primary frequency 
response service throughout the entire interconnection.\75\
---------------------------------------------------------------------------

    \74\ EEI at 7 (citing NOPR, FERC Stats. & Regs. ] 32,705 at P 
28).
    \75\ Id. at 7-8.
---------------------------------------------------------------------------

    57. EEI appears to be concerned that the language in paragraph 28 
might be interpreted to mean that market-based rate sales of primary 
frequency response are only authorized in specific geographic markets. 
As will be explained next, this would be similar to how market-based 
rate sales of operating reserves are handled pursuant to Order No. 784, 
but different from how authority for market-based rate sales of energy 
and capacity is granted. With respect to energy and capacity, the 
Commission's normal practice is to test for market power in the 
seller's home balancing authority area, and, if the seller is 
vertically-integrated, first-tier balancing authority areas, because 
this is where the seller's market power likely would be greatest. 
However, the market-based rate authority granted based on passage of 
these market power screens permits sales anywhere that the seller is 
capable of transacting. In Order No. 784, the Commission had to depart 
from this standard practice with respect to market-based rate sales of 
operating reserves because of the special transmission scheduling 
practices associated with those services. Order No. 784 required 
sellers of operating reserves to first demonstrate that the scheduling 
practices in the regions within which they wish to sell could support 
sales of operating reserves from one balancing authority area to 
another, and market-based rate authority for sales of operating 
reserves would only be granted for regions where such showing was made 
successfully by the seller.\76\ Because primary frequency response is 
autonomous and individual responses are of short duration, no special 
scheduling practices would be required. Hence, the Commission finds 
that market-based rate authority for sales of primary frequency 
response should be granted on the same basis as sales of energy and 
capacity; i.e., while market power is tested at the resource's 
location, authority is granted for sales anywhere the seller is capable 
of transacting. The Commission, therefore, clarifies the description in 
paragraph 28 of the NOPR accordingly.
---------------------------------------------------------------------------

    \76\ Order No. 784, FERC Stats. & Regs. ] 31,349 at P 58.
---------------------------------------------------------------------------

    58. AWEA, ESA, Union of Concerned Scientists, and Grid Storage 
Consulting argue that there may be some resources that have been 
authorized to sell ancillary services at market-based rates but not 
energy and capacity, or that are otherwise eligible to participate in 
Commission-authorized and supervised markets. They recommend that any 
such resources be permitted to sell primary frequency response service 
at market-based rates as well.\77\ In a similar vein, Public Interest 
Organizations ask the Commission to consider whether there is any class 
or potential class of emerging resources that sell only ancillary 
services and not energy or capacity, and if so, whether such resources 
should be exempted from existing market power screens in exchange for 
some more appropriate market power analysis.\78\
---------------------------------------------------------------------------

    \77\ AWEA at 4; ESA at 4-5; Union of Concerned Scientists at 3; 
Grid Storage Consulting at 10.
    \78\ Public Interest Organizations at 5-6.
---------------------------------------------------------------------------

    59. In response to these comments, the Commission clarifies that 
for resources capable of injecting electric energy onto the interstate 
transmission grid,\79\ authority to sell at market-based rates, even 
exclusively in organized RTO or ISO markets, is only granted to 
entities that either pass the existing market power screens for sales 
of energy and capacity or where any market power concerns have been 
adequately mitigated. Thus, even if such sellers only sell ancillary 
services today, their authorization to do so was granted based in part 
upon either passage of the existing market power screens for sales of 
energy and capacity or where there was a demonstration that any market 
power concerns have been adequately mitigated.\80\ The only current 
exception to this rule involves demand response resources. If a third-
party seller exclusively uses demand response resources to participate 
in RTO/ISO markets, it does not need to seek market-based rate 
authority or place any tariff on file with the Commission, because 
demand response resources do not inject electric energy onto the 
interstate transmission grid. However, if it ever markets services from 
other types of resources that result in it injecting electric energy 
onto the grid, then it would need market-based rate authority and a 
tariff on file.\81\ Accordingly, all sellers with market-based rate 
authority using resources that can inject electric energy onto the 
interstate transmission grid, even if they only sell ancillary services 
today, are already eligible to make use of the rebuttable presumption 
related to primary frequency response in this Final Rule. Similarly, 
sellers exclusively using demand response resources are already 
exempted from the need to submit market power analyses to gain 
authorization for their sales, and Public Interest Organizations have 
provided no reason why any new class of resources should be exempted.
---------------------------------------------------------------------------

    \79\ Pursuant to section 201(a) of the FPA, the Commission is 
charged with regulating the transmission of electric energy in 
interstate commerce and the sale of electric energy at wholesale in 
interstate commerce. 16 U.S.C. 824(a) (2012). Section 201(b) 
provides that the Commission shall have jurisdiction over facilities 
for wholesale sales of electric energy in interstate commerce or for 
transmission of electric energy in interstate commerce. Id. 824(b). 
In section 201(e), a public utility is defined as a person who owns 
or operates facilities subject to the jurisdiction of the 
Commission. Id. 824(e).
    \80\ In the event that sellers fail the existing market power 
screens for the RTO/ISO markets, the Commission allows such sellers 
to seek to obtain or retain market-based rate authority by relying 
on Commission-approved RTO/ISO monitoring and mitigation. See 
Refinements to Policies and Procedures for Market-Based Rates for 
Wholesale Sales of Electric Energy, Capacity and Ancillary Services 
by Public Utilities, Order No. 816, 80 FR 67056, (Oct. 30, 2015), 
153 FERC ] 61,065, at P 28 (2015).
    \81\ EnergyConnect, Inc., 130 FERC ] 61,031, at PP 26-33 (2010).
---------------------------------------------------------------------------

    60. Union of Concerned Scientists, ESA, and Public Interest 
Organizations all ask that the Commission clarify that the current 
Final Rule applies for all resources that can provide primary frequency 
response.\82\ Steel Producers Alliance makes similar arguments, 
emphasizing that resources other than generators are able to provide 
primary frequency response service and should be permitted to compete 
to provide the service.\83\ The Commission clarifies that this Final 
Rule applies to jurisdictional market-based rate sellers of primary 
frequency response service, irrespective of what specific equipment 
they may choose to use to make such sales.
---------------------------------------------------------------------------

    \82\ Union of Concerned Scientists at 5; ESA at 2-4; Public 
Interest Organizations at 2-3.
    \83\ Steel Producers Alliance at 2-3.
---------------------------------------------------------------------------

    61. MISO asserts that certain technical statements within the NOPR 
require limited clarification. First, while MISO agrees with the NOPR 
that 60 Hertz (Hz) is the target frequency in North America, MISO notes 
that scheduled frequency may be offset at times to correct time 
error.\84\ Second, in response to the NOPR's description of how each 
balancing authority's automatic generation control system will issue 
dispatch instructions to regulation resources to try to return the 
systems frequency to 60 Hz, MISO argues that typically the contingent 
balancing authority uses a combination of automatic generation control 
and contingency reserves for this purpose.\85\ The Commission agrees 
with these clarifications, but finds that they do not alter any 
fundamental underpinning of the NOPR proposal.
---------------------------------------------------------------------------

    \84\ MISO at 5.
    \85\ Id. at 6.
---------------------------------------------------------------------------

    62. Union of Concerned Scientists seeks clarification that 
procurement of, and payment for, primary frequency

[[Page 73974]]

response service would be allowed if the sale of primary frequency 
response service under market-based rates were allowed. It suggests 
that the Commission state that markets for primary frequency response 
service are allowed, subject to petition by appropriate utilities and 
approval by the Commission.\86\ Union of Concerned Scientists also asks 
that market eligibility and participation as a seller should not be 
constrained by disproportionate administrative burdens.\87\ The 
Commission agrees that market-based rate sales by entities that have 
been granted authorization for such sales are allowed; that is, of 
course, the object of a market-based rate application. With respect to 
the authority for potential buyers to purchase primary frequency 
response service, this Final Rule only involves market power screening 
of potential sellers. As with most products in voluntary bilateral 
markets, potential buyers do not need the Commission's permission. 
Similarly, the Commission clarifies that RTOs and ISOs remain free to 
develop organized markets for primary frequency response if they so 
choose, though nothing in this Final Rule requires them to do so, and 
if they choose to do so, only then will the Commission review such 
issues as eligibility requirements for participation.
---------------------------------------------------------------------------

    \86\ Union of Concerned Scientists at 4.
    \87\ Id. at 3.
---------------------------------------------------------------------------

6. Requests Outside the Scope of This Proceeding
    63. AWEA and Public Interest Organizations both request that the 
Commission permit sales of regulation service at market-based rates by 
entities with authority for market-based rate sales of energy and 
capacity.\88\ AWEA further requests that the Commission: (a) Explore 
the role that dynamic transfer capability, or lack thereof, plays in 
protecting against exertion of market power; \89\ (b) consider relaxing 
interconnection standards for resources that only sell ancillary 
services; \90\ and (c) consider whether entities in bilateral market 
areas should be required to develop platforms for the sale of primary 
frequency response, even if on a limited basis such as through open 
seasons.\91\
---------------------------------------------------------------------------

    \88\ AWEA at 1, 7-9; Public Interest Organizations at 5.
    \89\ AWEA at 3.
    \90\ Id. at 4.
    \91\ Id. at 5.
---------------------------------------------------------------------------

    64. Monitoring Analytics, LLC (Monitoring Analytics) notes that, 
while the NOPR is mainly concerned with the market power screens 
typically used in connection with authorizations to charge market-based 
rates, in organized markets like PJM's, such rates are granted in 
significant part based on the market power mitigation rules of the RTO 
or ISO. Accordingly, Monitoring Analytics recommends that if PJM 
develops a market for primary frequency response service, the rules for 
such market should incorporate the three pivotal supplier test that is 
already used for market power mitigation in PJM's other markets.\92\
---------------------------------------------------------------------------

    \92\ Monitoring Analytics at 7.
---------------------------------------------------------------------------

    65. ESA argues that fast responding energy storage resources should 
be allowed to supply both primary frequency response and regulation 
services simultaneously. In this regard, ESA asserts that the 
Commission should not inadvertently create a system where all providers 
of primary frequency response must provide such service for at least 5-
10 minutes until the slowest regulation resources can be brought 
online.\93\ ESA requests that the Commission ensure that ancillary 
service market designs and procurement mechanisms are reasonably 
consistent across regions and reflect non-market compensated benefits 
in the determination of operational needs for particular capabilities, 
such as fast response.\94\
---------------------------------------------------------------------------

    \93\ ESA at 5.
    \94\ Id. at 6.
---------------------------------------------------------------------------

    66. Grid Storage Consulting argues that balancing authorities 
should not be able to mandate that primary frequency response be 
provided as part of other market products,\95\ and that in some 
circumstances it may be appropriate to permit the costs of dedicated 
primary frequency response resources to be recovered in transmission 
rate base.\96\
---------------------------------------------------------------------------

    \95\ Grid Storage Consulting at 8-9.
    \96\ Id. at 10-11.
---------------------------------------------------------------------------

    67. If an RTO seeks to create an organized market for primary 
frequency response, then Dominion recommends that the Commission 
require a market design similar to those used currently to procure 
other ancillary services such as regulation and operating reserves. 
Alternatively, Dominion also supports allowing RTOs to procure primary 
frequency response at cost-based rates, in a manner similar to how 
reactive power is procured. Dominion also argues that generators should 
either be exempt from charges such as operating reserve and balancing 
energy when deviating from their schedules in order to provide primary 
frequency response service or their compensation should include credits 
to offset such charges.\97\
---------------------------------------------------------------------------

    \97\ Dominion at 3.
---------------------------------------------------------------------------

    68. SmartSenseCom asserts that there is a difference in value 
between resources capable of delivering a rapid response to changing 
frequency and slower-responding units. Accordingly, SmartSenseCom asks 
the Commission to require public utility transmission providers to take 
into account the speed and accuracy of primary frequency response 
resources when determining reserve requirements for primary frequency 
response, as the Commission did for regulation service in Order No. 
784. SmartSenseCom claims this ``is particularly necessary in this 
instance in light of the language set forth in Order No. 784 and in the 
instant NOPR that distinguishes [primary frequency response] from 
regulation and the different requirements that will now exist for each 
service.'' \98\
---------------------------------------------------------------------------

    \98\ SmartSenseCom at 8.
---------------------------------------------------------------------------

    69. The Commission finds all of these issues to be beyond the scope 
of this Final Rule. This Final Rule deals only with market-based 
pricing for voluntary bilateral primary frequency response sellers. 
While some of the issues raised above might be relevant in other 
proceedings,\99\ none of the issues raised above is relevant to the 
topic of market-based rates in voluntary bilateral markets. 
Accordingly, there is no need to address these issues here.
---------------------------------------------------------------------------

    \99\ For example, if an RTO or ISO eventually proposes to 
develop an organized market for primary frequency response service, 
or if the Commission at some point in the future decides to require 
such development, then several of the issues raised above might 
become relevant at that stage.
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III. Compliance and Implementation

    70. In Order No. 697, the Commission provided standard tariff 
provisions that sellers must include in their market-based rate tariffs 
to the extent they are applicable based on the services provided by the 
seller,\100\ including a provision for sales of ancillary services as a 
third-party provider.\101\ The Commission hereby revises the ``Third 
Party Provider'' ancillary services provision to change the reference 
to ``Regulation and Frequency Response Service'' to ``Regulation 
Service'' and to add a reference to ``Primary Frequency Response 
Service.'' The new language is as follows:
---------------------------------------------------------------------------

    \100\ Order No. 697, FERC Stats. & Regs. ] 31,252 at Appendix C.
    \101\ In Order No. 784, the Commission revised the standard 
third party provider provision to reflect the changes adopted in 
Order No. 784. Order No. 784, FERC Stats. & Regs. ] 31,349 at P 200.

Third-party ancillary services: Seller offers [include all of the 
following that the seller is offering: Regulation Service, Reactive 
Supply and Voltage Control Service, Energy and Generator Imbalance 
Service, Operating

[[Page 73975]]

Reserve-Spinning, Operating Reserve-Supplemental, and Primary 
Frequency Response Service]. Sales will not include the following: 
(1) sales to an RTO or an ISO, i.e., where that entity has no 
ability to self-supply ancillary services but instead depends on 
third parties; and (2) sales to a traditional, franchised public 
utility affiliated with the third-party supplier, or sales where the 
underlying transmission service is on the system of the public 
utility affiliated with the third-party supplier. Sales of Operating 
Reserve-Spinning and Operating Reserve-Supplemental will not include 
sales to a public utility that is purchasing ancillary services to 
satisfy its own open access transmission tariff requirements to 
offer ancillary services to its own customers, except where the 
Commission has granted authorization. Sales of Regulation Service 
and Reactive Supply and Voltage Control Service will not include 
sales to a public utility that is purchasing ancillary services to 
satisfy its own open access transmission tariff requirements to 
offer ancillary services to its own customers, except at rates not 
to exceed the buying public utility transmission provider's OATT 
rate for the same service or where the Commission has granted 
---------------------------------------------------------------------------
authorization.

    71. The Commission finds that a seller that already has market-
based rate authority as of the effective date of this Final Rule is 
authorized as of that date to make sales of primary frequency response 
service at market-based rates. Such a seller will be required to revise 
the third-party provider ancillary services provision of its market-
based rate tariff to reflect that it wishes to make sales of primary 
frequency response service at market-based rates. However, while this 
authorization is effective for sellers with existing market-based rate 
authority as of the effective date of this Final Rule, in order to 
reduce their administrative burden, the Commission permits such sellers 
to wait to file this tariff revision until the next time they make a 
market-based rate filing with the Commission, such as a notice of 
change in status filing or a triennial update.
    72. As noted in the NOPR, consistent with the existing requirements 
of Order No. 2001, any entity selling primary frequency response 
service will need to report such sales in the Electric Quarterly 
Report,\102\ and the Commission will update its Electric Quarterly 
Report system to include a specific product name option for primary 
frequency response service.\103\
---------------------------------------------------------------------------

    \102\ See Revised Public Utility Filing Requirements, Order No. 
2001, FERC Stats. & Regs. ] 31,127, reh'g denied, Order No. 2001-A, 
100 FERC ] 61,074, reh'g denied, Order No. 2001-B, 100 FERC ] 
61,342, order directing filing, Order No. 2001-C, 101 FERC ] 61,314 
(2002), order directing filing, Order No. 2001-D, 102 FERC ] 61,334, 
order refining filing requirements, Order No. 2001-E, 105 FERC ] 
61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC ] 
61,060 (2004), order revising filing requirements, Order No. 2001-G, 
120 FERC ] 61,270, order on reh'g and clarification, Order No. 2001-
H, 121 FERC ] 61,289 (2007), order revising filing requirements, 
Order No. 2001-I, FERC Stats. & Regs. ] 31,282 (2008).
    \103\ NOPR, FERC Stats. & Regs. ] 32,705 at P 29.
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IV. Information Collection Statement

    73. The Paperwork Reduction Act (PRA) \104\ 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 
regulations require approval of certain information collection 
requirements imposed by agency rules.\105\ 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 
an agency rule will not be penalized for failing to respond to the 
collection of information unless the collection of information displays 
a valid OMB control number.
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    \104\ 44 U.S.C. 3501-3520 (2012).
    \105\ See 5 CFR 1320 (2015).
---------------------------------------------------------------------------

    74. The Commission will submit the revised information collection 
requirements to OMB for its review and approval. The Commission 
solicits public comments on its need for this information, whether the 
information will have practical utility, the accuracy of burden and 
cost estimates, ways to enhance the quality, utility, and clarity of 
the information to be collected or retained, and any suggested methods 
for minimizing respondents' burden, including the use of automated 
information techniques.
    75. Burden Estimate and Information Collection Costs: While, to the 
Commission's knowledge, no entity currently sells primary frequency 
response service on an unbundled basis,\106\ there is no reason why 
primary frequency response service could not be sold today under cost-
based rates. Such cost-based sales, if they occurred, would face all of 
the burdens associated with cost-of-service regulation, including a 
variety of requirements from which market-based rate sellers frequently 
seek and are granted waiver.\107\ Furthermore, just like market-based 
rate sellers, cost-based rate sellers must report all transactions in 
the Electric Quarterly Report. Accordingly, the Commission views this 
Final Rule as providing potential market-based rate sellers of primary 
frequency response service with the opportunity to avoid cost-of-
service regulation for such sales and the associated substantial 
reporting burdens.
---------------------------------------------------------------------------

    \106\ It is likely that some customers purchase primary 
frequency response service along with other services on a bundled 
basis, such as through full requirements contracts, but this Final 
Rule is focused on unbundled sales of primary frequency response 
service.
    \107\ Such burdens would include, for example, the need to 
maintain Open Access Transmission Tariffs and Open Access Same-Time 
Information Systems related to any jurisdictional transmission 
facilities owned by the entity, the need to adhere to the 
Commission's standards of conduct, the need to adhere to the 
detailed cost-of-service related requirements of subparts B and C of 
Part 35 of the Commission's regulations, the need to adhere to the 
accounting and reporting requirements of Parts 41, 101, and 141 of 
the Commission's regulations, and the need to seek separate 
authorizations for issuances of securities and assumptions of 
liabilities under FPA section 204 and Part 34 of the Commission's 
regulations.
---------------------------------------------------------------------------

    76. Below, we discuss the expected increases in burden as a result 
of this Final Rule. The Commission expects the additional burden to be 
greatly outweighed by the reduction in burden from avoiding cost-of-
service regulation. The additional estimated annual public reporting 
burdens and costs for the requirements in this Final Rule are as 
follows.

                                                          Changes in Final Rule in RM15-2 \108\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                       Annual number of
        Number of respondents           responses per     Total number of     Average burden & cost per   Total annual burden hours &  Cost per response
                                          respondent         responses                response                 total annual cost
(a)                                                 (b)        (a)x(b)=(c)  (d).........................  (c)x(d)=(e)................            (e)/(c)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                       FERC-516 (Electric Rate Schedules and Tariff Filings) (one time, phased in)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,585 \109\.........................        \110\ 0.163                259  6 hrs.; $432................  1,554 hrs.; $111,888.......               $432
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 73976]]

 
                                               FERC-920 (Electric Quarterly Report) (one-time, phased in)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,585...............................        \111\ 0.163                259  2 hrs.; $144................  518 hrs.; $37,296..........                144
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Titles: FERC-516 (Electric Rate Schedules and Tariff Filings) and 
FERC-920 (Electric Quarterly Report (EQR)).
---------------------------------------------------------------------------

    \108\ For purposes of burden estimation, the NOPR assumed that 
industry staff members are similarly situated to FERC, in terms of 
hourly cost per full time employee, and no commenter disputes this 
assumption. Therefore, the estimated average hourly cost (salary 
plus benefits) is $72.00.
    \109\ The 1,585 respondent universe includes existing sellers 
(1,999 total market-based rate sellers--697 Category 1 sellers + 70 
Category 1 sellers = 1,372 sellers estimated to sell primary 
frequency response services) plus 213 new market-based rate 
applicants (as estimated in Docket No. RM14-14). (We estimate that 
ten percent (or 70, as indicated above) of the Category 1 sellers 
may choose to sell primary frequency response services.)
    \110\ We expect respondents to enter the primary frequency 
response market gradually. For each of the next three years, we 
expect all 213 new market-based rate applicants per year (or 639 
total during Years 1-3), to include the primary frequency response 
language in their tariffs.
    Additionally, during the three-year period, we expect a total of 
ten percent of the existing 1,372 respondents (or 137 respondents), 
to decide to sell primary frequency response services and to make 
the corresponding FERC-516 rate filing. The corresponding annual 
estimate is 46 of the existing respondents (an average of 3.4% 
annually). Therefore, the annual estimate, including both new 
respondents and existing respondents, is an average of 259 (213 + 
46) respondents and responses per year.
    \111\ As respondents decide to sell primary frequency response 
services, they would report the new offering in their Electric 
Quarterly Report (FERC-920), and would continue to report in 
subsequent EQRs. When a filer adds the new service, we estimate the 
one-time burden to be two hours. We expect any additional burden 
associated with reporting the new service in the EQR to be 
negligible after the first implementation as it would become part of 
the respondent's normal reporting practice in the EQR and would only 
involve selecting the `primary frequency response' option from a 
list of product names. On average, we expect filers of the new 
primary frequency response service to phase in:
     Year 1, 259 respondents or 16.3 percent of EQR filers.
     Year 2, 259 respondents or 16.3 percent of EQR filers.
     Year 3, 259 respondents or 16.3 percent of EQR filers.
---------------------------------------------------------------------------

    Action: Revision of Currently Approved Collection of Information.
    OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0255 (FERC-920).
    Respondents: Public utilities.
    Frequency of responses: One-time, phased in (for both FERC-516 and 
FERC-920).
    Necessity of the Information: Regarding FERC-516, section 205(c) of 
the Federal Power Act requires public utilities to file with the 
Commission schedules showing all rates and charges for any transmission 
or sale subject to the Commission's jurisdiction. Accordingly, entities 
wishing to sell primary frequency response service at market-based 
rates must amend their market-based rate tariffs to include the 
language included in this Final Rule. Regarding FERC-920, the 
Commission is revising the EQR to ensure that public utilities that may 
sell primary frequency response service at market-based rates report 
those sales in the EQR, consistent with their filing obligations under 
section 205(c).
    Internal Review: The Commission has reviewed the requirements 
associated with the proposed revisions to the information collections 
and determined they are necessary to ensure that rates remain just, 
reasonable, and not unduly discriminatory.
    77. These requirements conform to the Commission's need for 
efficient information collection, communication, and management within 
the energy industry. The Commission has assured itself, through 
internal review, that there is specific, objective support for the 
burden estimates associated with the information collection 
requirements.
    78. 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 on the collections of information and associated burden 
estimates in the Final Rule should be sent to the Commission in this 
docket and may also be sent to the Office of Information and Regulatory 
Affairs, Office of Management and Budget, Washington, DC 20503 
[Attention: Desk Officer for the Federal Energy Regulatory Commission]. 
For security reasons, comments to OMB should be submitted by email to: 
oira_submission@omb.eop.gov. Please refer to OMB Control No. 1902-0096 
(FERC-516) and OMB Control No. 1902-0255 (FERC-920).

V. Environmental Analysis

    79. 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.\112\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's 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 subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classifications, and 
services.\113\
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    \112\ 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).
    \113\ 18 CFR 380.4(a)(15) (2015).
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VI. Regulatory Flexibility Act

    80. The Regulatory Flexibility Act of 1980 (RFA) \114\ generally 
requires a description and analysis of proposed and final rules that 
will have significant economic impact on a substantial number of small 
entities.
---------------------------------------------------------------------------

    \114\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    81. The Small Business Administration's (SBA) Office of Size 
Standards develops the numerical definition of a small business.\115\ 
The SBA revised its size standard for electric utilities (effective 
January 22, 2014) from a standard based on megawatt hours to a standard 
based on the number of employees, including affiliates.\116\ Under 
SBA's current size

[[Page 73977]]

standards, the entities with market-based rates which are affected by 
this Final Rule likely come under the following categories \117\ with 
the indicated thresholds (in terms of number of employees \118\):
---------------------------------------------------------------------------

    \115\ 13 CFR 121.101 (2015).
    \116\ SBA Final Rule on ``Small Business Size Standards: 
Utilities,'' 78 FR 77,343 (Dec. 23, 2013).
    \117\ 13 CFR 121.201, Sector 22, Utilities.
    \118\ SBA's regulations at 13 CFR 121.201 state that ``[t]he 
number of employees . . . indicates the maximum allowed for a 
concern and its affiliates to be considered small.''
---------------------------------------------------------------------------

     Hydroelectric Power Generation, 500 employees.
     Fossil Fuel Electric Power Generation, 750 employees.
     Nuclear Electric Power Generation, 750 employees.
     Solar Electric Power Generation, 250 employees.
     Wind Electric Power Generation, 250 employees.
     Geothermal Electric Power Generation, 250 employees.
     Biomass Electric Power Generation, 250 employees.
     Other Electric Power Generation, 250 employees.
    82. The categories for the applicable entities have a size 
threshold ranging from 250 employees to 750 employees. For the analysis 
in this Final Rule, we are using the threshold of 750 employees for all 
categories. We anticipate that a maximum of 82 percent of the entities 
potentially affected by this Final Rule are small. In addition, we 
expect that not all of those entities will be able to or will choose to 
offer primary frequency response service.
    83. Based on the estimates above in the Information Collection 
section, we expect a one-time cost of $576 (including the burden cost 
related to filing both the tariff and the EQR) for each entity that 
decides to offer primary frequency response service.
    84. The Commission does not consider the estimated cost per small 
entity to impose a significant economic impact on a substantial number 
of small entities. Accordingly, the Commission certifies that this 
Final Rule will not have a significant economic impact on a substantial 
number of small entities.

VII. Document Availability

    85. In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington, DC 20426.
    86. From the Commission's Home Page on the Internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    87. 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.

VIII. Effective Date and Congressional Notification

    88. The Final Rule is effective February 25, 2016. The Commission 
has determined, with the concurrence of the Administrator of the Office 
of Information and Regulatory Affairs of OMB, that this Final Rule is 
not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. This Final Rule is being 
submitted to the Senate, House, Government Accountability Office, and 
Small Business Administration.

List of Subjects in 18 CFR Part 35

    Electric power rates; Electric utilities; Reporting and 
recordkeeping requirements.

    By the Commission.

    Issued: November 20, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends 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. In Sec.  35.37, revise paragraph (c)(1) to read as follows:

Sec.  35.37  Market power analysis required.

* * * * *
    (c)(1) There will be a rebuttable presumption that a Seller lacks 
horizontal market power with respect to sales of energy, capacity, 
energy imbalance service, generation imbalance service, and primary 
frequency response service if it passes two indicative market power 
screens: a pivotal supplier analysis based on annual peak demand of the 
relevant market, and a market share analysis applied on a seasonal 
basis. There will be a rebuttable presumption that a Seller lacks 
horizontal market power with respect to sales of operating reserve-
spinning and operating reserve-supplemental services if the Seller 
passes these two indicative market power screens and demonstrates in 
its market-based rate application how the scheduling practices in its 
region support the delivery of operating reserve resources from one 
balancing authority area to another. There will be a rebuttable 
presumption that a Seller possesses horizontal market power with 
respect to sales of energy, capacity, energy imbalance service, 
generation imbalance service, operating reserve-spinning service, 
operating reserve-supplemental service, and primary frequency response 
service if it fails either screen.
* * * * *
[FR Doc. 2015-30140 Filed 11-25-15; 8:45 am]
 BILLING CODE 6717-01-P