[Federal Register Volume 80, Number 38 (Thursday, February 26, 2015)]
[Proposed Rules]
[Pages 10426-10432]
[FR Doc No: 2015-03741]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM15-2-000]

Third-Party Provision of Primary Frequency Response Service

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes
to revise its regulations to foster competition in the sale of primary
frequency response service. Specifically, the Commission proposes to
amend its regulations to revise the 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 energy and
capacity.

DATES: Comments are due April 27, 2015.

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

FOR FURTHER INFORMATION CONTACT:

Rahim Amerkhail (General Information), Federal Energy Regulatory
Commission, Office of Energy Policy and Innovation, 888 First Street
NE., Washington, DC 20426,<PHONE_NUMBER>.
Gregory Basheda (Market Power Screening Information), Federal Energy
Regulatory Commission, Office of Energy Market Regulation, 888 First
Street NE., Washington, DC 20426,<PHONE_NUMBER>.
Lina Naik (Legal Information), Federal Energy Regulatory Commission,
Office of the General Counsel, 888 First Street NE., Washington, DC
20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:
    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) proposes to revise its regulations
to foster competition in the sale of primary frequency response
service.\1\ Specifically, the Commission proposes to amend 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 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 energy and capacity.
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    \1\ As envisioned in this NOPR, primary frequency response
service would be a reserve product that involves dedicating capacity
on a generator or other resource for autonomous, automatic, and
rapid action to change its output (within seconds) to rapidly dampen
large changes in frequency.
    \2\ 16 U.S.C. 824d, 824e (2012).
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    2. This NOPR is an extension of the policy reforms the Commission
started with Order No. 784,\3\ in which, among other things, the
Commission revised Part 35 of its regulations to reflect reforms to its
policy governing the sale of ancillary services at market-based rates
to public utility transmission providers. As discussed in more detail
below, the reforms proposed herein are in anticipation of the potential
interest in purchase of primary frequency response service from third-
parties as a result of a new reliability standard that requires a
Balancing Authority to maintain a minimum frequency response
obligation.
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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, at
PP 6-7 (2013), order on clarification, Order No. 784-A, 146 FERC ]
61,114 (2014).
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I. Background

    3. The Commission in Order No. 888 \4\ delineated two categories of
ancillary services: those that the transmission provider is required to
provide to all of its basic transmission customers \5\ 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.\6\ 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 Open Access Transmission Tariff (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.\7\
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    \4\ 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).
    \5\ The first category consists of Scheduling, System Control
and Dispatch service and Reactive Supply and Voltage Control from
Generation Sources service.
    \6\ 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).
    \7\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-21.
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    4. Subsequently, in Avista,\8\ 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.\9\
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    \8\ Avista Corp., 87 FERC ] 61,223, at 61,882, 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.
One such restriction is that the authorization provided by Avista
does not apply to sales to a public utility that is purchasing
ancillary services to satisfy its own OATT requirements to offer
ancillary services to its own customers.
    \9\ 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.
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    5. 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.\10\
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    \10\ 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. Because 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 area to respond to
contingencies in a neighboring balancing area within these tight
time frames. Order No. 784-A, 146 FERC ] 61,114 at PP 13-15.
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    6. 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).\11\ 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 \12\ or the sale is made at or
below the buying public utility transmission provider's own Schedule 2
or 3 rate, as applicable.\13\ 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.\14\
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    \11\ Order No. 784, FERC Stats. & Regs. ] 31,349 at PP 59-61.
    \12\ Id. PP 99-101.
    \13\ Id. PP 82-85.
    \14\ Id. P 61.
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    7. 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.\15\ 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.\16\
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    \15\ 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).
    \16\ For example, most commenters echoed EEI's 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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    8. Separately, the Commission on January 16, 2014 issued a Final
Rule approving reliability standard BAL-003-1 \17\ under which a
Balancing Authority \18\ must maintain a minimum frequency response
obligation.\19\ While most Balancing Authorities should be able to meet
the new reliability standard using their own resources,\20\ some may
nevertheless be interested in purchasing primary frequency response
service from others if doing so would be economically beneficial.
Accordingly, the Commission concludes that there could be interest in
the near future in voluntary purchases of a primary frequency response
product.
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    \17\ 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.
    \18\ 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.
    \19\ See Frequency Response and Frequency Bias Setting
Reliability Standard, Order No. 794, 146 FERC ] 61,024 (2014).
    \20\ Id. PP 62-63.
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    9. For the reasons described more fully below, the Commission finds
that sales of primary frequency response service at market-based rates
should be authorized for entities granted market-based rate authority
for sales of energy and capacity.
    10. With respect to the remainder of the issues discussed at the
workshop and in written comments, the Commission does not see
sufficient evidence to support pursuing additional reforms on a generic
basis.

II. Discussion

A. Primary Frequency Response Service

    11. As explained in Order No. 794, reliable operation of a power
system depends on maintaining frequency within predetermined boundaries
above and below a scheduled value, which is 60 Hertz (Hz) in North
America.\21\ In order to do that, sufficient amounts of primary and
secondary frequency response reserves must be maintained to stabilize
frequency within an interconnection immediately following the sudden
loss of generation or load.
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    \21\ Id. P 6.
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    12. Primary frequency response involves 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.
Regulation, also known as secondary frequency response, is produced
from either manual or automated dispatch from a centralized control
system, generally using the communications and control system known as
automatic generation control (AGC). In both cases, capacity must be set
aside to provide the responses described above.
    13. Mechanically, the BAL-003-1 reliability standard provides
interconnection-wide primary frequency response obligations for each of
the Eastern, Western, Electric Reliability Council of Texas, and Hydro
Quebec

Interconnections. The interconnection-wide frequency response
obligation is then allocated among all of the Balancing Authorities (or
Frequency Response Sharing Groups made up of multiple Balancing
Authorities) within each interconnection based on the ratio of the
Balancing Authority's generation and load to the total interconnection-
wide generation and load times the interconnection-wide frequency
response obligation, and this value is called the Balancing Authority's
Frequency Response Obligation. However, Balancing Authorities are not
limited in how they meet the requirements of BAL-003-1; the standard
neither prohibits purchases nor requires self-supply.
    14. In Order No. 784, the Commission evaluated, among other things,
whether the existing market power screens for sales of energy and
capacity could be applied to the sale of Schedule 3 service without
significant modification.\22\ In Order No. 784, the Commission
discussed Schedule 3 without making a distinction between primary
frequency response and regulation.
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    \22\ Order No. 784, FERC Stats. & Regs. ] 31,349 at PP 59-61.
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    15. However, as noted above, primary frequency response is distinct
from regulation; and the April 22, 2014 workshop distinguished between
these two services for the purpose of discussing market power issues.
While the Commission, in Order No. 888, found that primary frequency
response did not merit a separate ancillary service given then-standard
industry practices,\23\ we preliminarily find that we can distinguish
between primary frequency response and regulation for the purposes of
considering how the transmission provider may procure the services it
must offer under OATT Schedule 3.
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    \23\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,707.
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    16. Specifically, following the approval of the new BAL-003-1
Frequency Response and Frequency Bias Setting Reliability Standard, it
is now appropriate to consider the possibility that entities may wish
to undertake voluntary sales of primary frequency response service as a
stand-alone product distinct from regulation service. The Commission
anticipates that sales of such a product would involve bilateral
transactions by sellers and, while such sales could be made at cost-
based rates, many sellers may prefer the administrative ease of market-
based rates. Accordingly, provision would need to be made for sales of
primary frequency response within the Commission's market-based rate
program.
    17. The Commission analyzes below the horizontal market power
issues relevant to a primary frequency response product.

B. The Existing Market Power Analyses

    18. The Commission analyzes horizontal market power \24\ for sales
of energy and capacity 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.\25\ 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.\26\ A seller
whose share of the relevant market is less than 20 percent during all
seasons passes the wholesale market share screen.\27\ 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.\28\ A seller satisfies the
pivotal supplier screen if its uncommitted capacity is less than the
net uncommitted supply in the relevant market.\29\
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    \24\ 18 CFR 35.37(b) (2014).
    \25\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 13,
62. See also 18 CFR 35.37(b), (c)(1) (2014).
    \26\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 43.
    \27\ Id. PP 43-44, 80, 89.
    \28\ 18 CFR 35.37(c)(1) (2014).
    \29\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 42.
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    19. 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.\30\ 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.\31\ In the alternative, a seller may accept the
presumption of horizontal market power and adopt some form of cost-
based mitigation.\32\
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    \30\ 18 CFR 35.37(c)(1) (2014).
    \31\ 18 CFR 35.37(c)(2) (2014). 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.
    \32\ 18 CFR 35.37(c)(3) (2014).
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    20. 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.\33\ Specifically, the Commission generally uses a seller's
Balancing Authority area plus directly interconnected Balancing
Authority areas, or the RTO/ISO market as applicable, as the default
relevant geographic market. However, where the Commission has made a
specific finding that there is a submarket within an RTO, 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.\34\
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    \33\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 15.
    \34\ 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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C. Applicability of Existing Indicative Screens to Primary Frequency
Response Service

    21. The Commission has considered whether passing the market-based
rate screens for energy and capacity described above should create a
rebuttable presumption that the seller lacks horizontal market power
for sales of primary frequency response service. As discussed below,
the Commission believes it should.
    22. As described above, primary frequency response service involves
the autonomous, automatic, and rapid reaction of an individual turbine-
generator or other resource to change its

output to rapidly dampen changes in interconnection-wide frequency.
With respect to the technical capability of resources to provide such
response, essentially all synchronous resources and some non-
synchronous resources have governors or equivalent control equipment
capable of autonomous and automatic responses such as those necessary
for primary frequency response.\35\ The only real difference among
resources in this regard involves the choice of settings applied to
that equipment, where settings can range from those that result in
appropriate levels of primary frequency response to those that result
in no response at all, or even responses that worsen the situation.
However, such settings can be changed on short notice, thus enabling
resources that have never provided primary frequency response in the
past to quickly begin providing it if there is some reason and
incentive to do so. Accordingly, the set of resources technically
capable of providing primary frequency response service does not differ
significantly from the set of resources represented in the existing
market power screens.
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    \35\ See, e.g., Kosterev Statement, Docket No. AD14-7-000
Workshop Transcript, at 180 (Apr. 22, 2014) (``. . . every
synchronous machine has a governor'').
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    23. With respect to the geographic market, the frequency of an
interconnection is uniform throughout that interconnection and is
determined largely by the dynamic interconnection-wide balance of
supply with demand. Large contingency events, such as the unexpected
loss of large amounts of generation or load, which happen anywhere
within a given interconnection, cause deviations from the target 60Hz
frequency that propagate throughout that interconnection. Accordingly,
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.\36\
Therefore, the geographic market for 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.
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    \36\ See, e.g., Edison Electric Institute Post-Workshop
Comments, Docket No. AD14-7-000, at 8 (filed June 3, 2014).
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    24. With respect to potential barriers related to transmission
scheduling or reservation, while information sharing arrangements will
certainly be necessary between buyers and sellers to enable the buyers
to rely on purchased resources to meet their frequency response
obligations under BAL-003-1, primary frequency response service should
not require any transmission reservation or scheduling, even for sales
from resources in a different Balancing Authority area. This is because
individual frequency responses, by definition,\37\ would not be
sustained for long enough periods to trigger a need for transmission
service or schedule changes. Rather, regulation resources dispatched by
balancing authorities would be expected to assume responsibility for
returning the system to the target 60Hz frequency as soon as the
central dispatch system is able to send appropriate dispatch signals
and the dispatched resources are able to respond.
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    \37\ Primary frequency response service would entail the setting
aside of some amount of capacity dedicated to providing autonomous
frequency response, and the actual autonomous responses to
predefined levels of frequency deviation. While the capacity would
be set aside for extended periods, the actual autonomous responses
would be of very short duration, as explained in the next section of
the text.
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    25. The AGC signals used for that dispatch are generally issued
every 2-6 seconds, and actual response from dispatched resources is a
gradual process on a scale of minutes due to the inherent ramping
constraints of each resource; for example, PJM Interconnection, L.L.C.
requires a maximum response time of 5 minutes, and certain regions may
allow up to 10 minutes. Accordingly, the expectation would be for
primary frequency response to gradually decline over a span of 1 to 10
minutes as regulation resources ramp up to their designated output.\38\
As such, this short period of time means that transmission scheduling
and reservation should not be needed in connection with the provision
of the temporary, autonomous changes in output associated with primary
frequency response service that would in all normal cases be quickly
replaced by regulation service.\39\
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    \38\ When some event causes a sudden and large drop (or
increase) in system frequency across the interconnection in
question, all of the frequency-responsive resources maintained by
Balancing Authorities in that interconnection will automatically and
autonomously begin to respond within fractions of a second to try to
arrest the deviation in frequency. Within 2-6 seconds after that,
each Balancing Authority's AGC system will begin issuing dispatch
instructions to regulation resources to try to reverse the deviation
in frequency and return the interconnection-wide system frequency to
60Hz, and those regulation resources, depending upon their ramping
capabilities, may take up to 10 minutes or so to reach their full
dispatched levels. At this point, they should have fully displaced
the autonomous primary frequency response resources that initially
reacted to slow and arrest the frequency deviation.
    \39\ As relevant to the topic of this order, such frequency
responsive reserves (resources set aside to provide primary
frequency response) may include both resources owned by the
Balancing Authorities and resources purchased from other entities
anywhere within the same interconnection. For remote resources
within the same interconnection, arrangements will have to be made
for sharing telemetry data from the resources in order to allow the
host Balancing Authority to demonstrate that it met its frequency
response obligation, and for ACE accounting purposes, but such
telemetry sharing should not pose any significant barrier to the use
of remote resources for the purposes of market-based rates here.
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    26. Accordingly, there should be no barriers related to
transmission scheduling or reservation preventing sellers anywhere
within the same interconnection as the buyer from providing effective
primary frequency response service to that buyer.

III. Proposal

    27. For the reasons discussed above, the Commission concludes that
passage of the existing market-based rate screens for sales of energy
and capacity can adequately demonstrate lack of market power for sales
of primary frequency response service.
    28. The Commission, therefore, proposes that sellers passing the
existing market power screens should be permitted to sell primary
frequency response service at market-based rates. As a result, we
propose to revise our regulations governing market-based rate
authorizations to provide that sellers passing the existing market-
based rate screens in a given geographic market should be granted a
rebuttable presumption that they lack horizontal market power for sales
of primary frequency response service in that market. Specifically,
section 35.37 of the Commission's regulations would be revised to state
that a seller would have a rebuttable presumption it lacks market power
with respect to sales of energy, capacity, energy imbalance service,
generator imbalance service, and primary frequency response service if
the seller passes the indicative screens for that geographic market.
The Commission preliminarily concludes that expanding the rebuttable
presumption adopted in Order No. 697 for energy and capacity to include
primary frequency response service provides adequate protection that
market-based rates charged by public utilities will be just and
reasonable and not unduly discriminatory or preferential.
    29. Any entity selling primary frequency response service, either
at market-based or cost-based rates, will be required to report such
sales in the Electric Quarterly Report. Accordingly, the Commission
proposes to update its Electric Quarterly Report system to

include a specific product name option for primary frequency response
service.
    30. The Commission seeks comment on this proposal, including the
proposed revisions to section 35.37(c)(1) of our regulations. Comments
may address, among other things, any unique technical requirements or
limitations that might apply to the provision of primary frequency
response service, and the Commission's proposal to extend the
rebuttable presumption to primary frequency response service.

IV. Summary of Compliance and Implementation

    31. 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,\40\ including a provision for sales of ancillary services as a
third-party provider.\41\ The Commission proposes to revise the ``Third
Party Provider'' ancillary services provision filed by utilities in
their market-based rate tariffs to change the reference to ``Regulation
and Frequency Response Service'' to ``Regulation Service'' and to add a
reference to ``Primary Frequency Response Service.'' The proposed new
language is as follows:
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    \40\ Order No. 697, FERC Stats. & Regs. ] 31,252 at Appendix C.
    \41\ 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 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.

    32. The Commission proposes that a seller that already has market-
based rate authority as of the effective date of the Final Rule issued
in this proceeding would be authorized as of the effective date of the
Final Rule to make sales of primary frequency response service at
market-based rates. Such a seller would 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 would be effective for sellers with existing market-based
rate authority as of the date specified in a Final Rule in this
proceeding, the Commission proposes that such sellers may 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.

V. Information Collection Statement

    33. The Paperwork Reduction Act (PRA) \42\ 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.\43\ 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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    \42\ 44 U.S.C. 3501-3520.
    \43\ See 5 CFR 1320.10 (2014).
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    34. The Commission will submit the proposed 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.
    35. Burden Estimate and Information Collection Costs: While, to the
Commission's knowledge, no entity currently sells primary frequency
response service on an unbundled basis,\44\ 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.\45\ 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
NOPR 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.
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    \44\ 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 NOPR is focused on
unbundled sales of primary frequency response service.
    \45\ 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.
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    36. Below, we discuss the expected increases in burdens as a result
of the proposals in this NOPR, which we expect 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 proposed rule are as follows.

                                                         Changes Proposed in NOPR in RM15-2 \46\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Total annual
                                                                Annual number of   Total number of  Average burden &   burden hours &       Cost per
                     Number of respondents                        responses per       responses         cost per        total annual        response
                                                                   respondent                           response            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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,551 \47\....................................................        \48\ 0.166               258           6, $432   1,548, $111,456              $432
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               FERC-920 (Electric Quarterly Report) (one-time, phased in)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,551.........................................................        \49\ 0.166               258           2, $144      516, $37,152               144
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Action: Proposed changes.
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    \46\ We think that industry staff members are similarly situated
to FERC, in terms of hourly cost per full time employee. Therefore,
the estimated average hourly cost (salary plus benefits) is $72.00.
    \47\ The 1,551 respondent universe includes existing sellers
(1,965 total market-based rate sellers--697 Category 1 sellers + 70
Category 1 sellers = 1,338 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.)
    \48\ 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 1,338 respondents (or 134 respondents),
to decide to sell primary frequency response services and to make
the corresponding FERC-516 rate filing. The corresponding annual
estimate is 45 of the existing respondents (an average of 3.3%
annually). Therefore, the annual estimate, including both new
respondents and existing respondents, is an average of 258 (213 +
45) respondents and responses per year.
    \49\ 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, 258 respondents or 16.6 percent of EQR filers.
     Year 2, 258 respondents or 16.6 percent of EQR filers.
     Year 3, 258 respondents or 16.6 percent of EQR filers.
---------------------------------------------------------------------------

    OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0255 (FERC-920).
    Respondents: Public utilities, FERC licensees.
    Frequency of responses: One-time (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 NOPR. 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.
    37. 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.
    38. 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:
<EMAIL_ADDRESS>Phone<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
Comments on the collections of information and associated burden
estimates in the proposed 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:
<EMAIL_ADDRESS>Please refer to OMB Control No. 1902-0096
(FERC-516) and OMB Control No. 1902-0255 (FERC-920).

VI. Environmental Analysis

    39. 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.\50\ 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.\51\
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    \50\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \51\ 18 CFR 380.4(a)(15) (2014).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    40. The Regulatory Flexibility Act of 1980 (RFA) \52\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \52\ 5 U.S.C. 601-612 (2012).
---------------------------------------------------------------------------

    41. The Small Business Administration's (SBA) Office of Size
Standards develops the numerical definition of a small business.\53\
The SBA recently 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.\54\ Under SBA's current size standards, the entities with
market-based rates which are affected by this NOPR likely come under
the following categories \55\ with the indicated thresholds (in terms
of number of employees \56\):
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    \53\ 13 CFR 121.101 (2014).
    \54\ SBA Final Rule on ``Small Business Size Standards:
Utilities,'' 78 FR 77,343 (Dec. 23, 2013).
    \55\ 13 CFR 121.201, Sector 22, Utilities.
    \56\ 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

    42. The categories for the applicable entities have a size
threshold ranging from 250 employees to 750 employees. For the analysis
in this proposed 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 NOPR 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.
    43. 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.
    44. 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 NOPR
will not have a significant economic impact on a substantial number of
small entities.

VIII. Comment Procedures

    45. The Commission invites interested persons to submit comments on
the matters and issues proposed in this notice to be adopted, including
any related matters or alternative proposals that commenters may wish
to discuss. Comments are due April 27, 2015. Comments must refer to
Docket No. RM15-2-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments.
    46. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    47. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
    48. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

IX. Document Availability

    49. 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.
    50. 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.
    51. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
List of Subjects in 18 CFR Part 35

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

    Issued: February 19, 2015.

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

    In consideration of the foregoing, the Commission proposes to amend
Part 35, Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

0
2. Revise Sec.  35.37(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. 2015-03741 Filed 2-25-15; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 80, Number 1 (Friday, January 2, 2015)]
[Notices]
[Page 40]
[FR Doc No: 2014-30747]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EL00-95-248]

San Diego Gas & Electric Company v. Sellers of Energy and
Ancillary Services Into Markets Operated by the California Independent
System Operator Corporation and the California Power Exchange; Notice
of Filing

    Take notice that on December 10, 2014, the California Parties \1\
filed proposed data templates for compliance filings and proposed
procedures for implementing the Commission's Opinion No. 536,\2\ as
more fully explained in the California Parties' filing.
---------------------------------------------------------------------------

    \1\ California Parties means collectively, the People of the
State of California ex rel. Kamala D. Harris, Attorney General, the
Public Utilities Commission of the State of California, Pacific Gas
and Electric Company, and Southern California Edison Company.
    \2\ San Diego Gas & Elec. Co. v. Sellers of Energy and Ancillary
Services Into Markets Operated by the California Independent System
Operator and the California Power Exchange, 149 FERC ] 61,116 (2014)
(Opinion No. 536).
---------------------------------------------------------------------------

    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211, 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date.
Anyone filing a motion to intervene or protest must serve a copy of
that document on the Applicant and all the parties in this proceeding.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 5 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street NE., Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the
``eLibrary'' link and is available for electronic review in the
Commission's Public Reference Room in Washington, DC. There is an
``eSubscription'' link on the Web site that enables subscribers to
receive email notification when a document is added to a subscribed
docket(s). For assistance with any FERC Online service, please email
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5:00 p.m. Eastern Time on December 31, 2014.

    Dated: December 23, 2014.
 Kimberly D. Bose,
 Secretary.
[FR Doc. 2014-30747 Filed 12-31-14; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register: August 20, 2007 (Volume 72, Number 160)]
[Notices]
[Page 46458-46459]
[DOCID:fr20au07-54]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[P-2242-078]

Eugene West and Electric Board; Carmen-Smith Hydroelectric
Project; Notice of Scoping Meetings and Site Visit and Soliciting
Scoping Comments

August 10, 2007.
    Take notice that the following hydroelectric application has been
filed with Commission and is available for public inspection:
    a. Type of Application: New Major License.
    b. Project No.: 2242-078.
    c. Date filed: November 24, 2006.
    d. Applicant: Eugene Water and Electric Board.
    e. Name of Project: Carmen-Smith Hydroelectric Project.
    f. Location: On the McKenzie River in Lane and Linn Counties, near
McKenzie Bridge, Oregon. The project occupies approximately 560 acres
of the Willamette National Forest.
    g. Filed Pursuant to: Federal Power Act, 16 U.S.C. 791(a)--825(r).
    h. Applicant Contact: Randy L. Berggren, General Manager, Eugene
Water and Electric Board, 500 East 4th Avenue, P.O. Box 10148, Eugene,
OR 97440,<PHONE_NUMBER>.
    i. FERC Contact: Bob Easton,<PHONE_NUMBER> or
<EMAIL_ADDRESS>
    j. Deadline for filing scoping comments: October 12, 2007.
    All documents (original and eight copies) should be filed with:
Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426.
    The Commission's Rules of Practice and Procedure require all
intervenors filing documents with the Commission to serve a copy of
that document on each person on the official service list for the
project. Further, if an intervenor files comments or documents with the
Commission relating to the merits of an issue that may affect the
responsibilities of a particular resource agency, they must also serve
a copy of the document on that resource agency.
    Scoping comments may be filed electronically via the Internet in
lieu of paper. The Commission strongly encourages electronic filings.
See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's
Web site (http://www.ferc.gov) under the ``e-Filing'' link.

    k. This application is not ready for environmental analysis at this
time.
    l. The Carmen-Smith Hydroelectric Project consists of two
developments,

the Carmen development and the Trail Bridge development. The Carmen
development includes:
    (1) A 25-foot-high, 2,100-foot-long, and 10-foot-wide earthen
Carmen diversion dam with a concrete weir spillway, (2) a 11,380-foot-
long by 9.5-foot-diameter concrete Carmen diversion tunnel located on
the right abutment of the spillway, (3) a 235-foot-high, 1,100-foot-
long, and 15-foot-wide earthen Smith diversion dam with a gated Ogee
spillway, (4) a 7,275-foot-long by 13.5 foot-diameter concrete-lined
Smith power tunnel, (5) a 1,160-foot-long by 13-foot-diameter steel
underground Carmen penstock, (6) a 86-foot-long by 79-foot-wide Carmen
powerhouse, (7) two Francis turbines each with a generating capacity of
52.25 megawatts (MW) for a total capacity of 104.50 MW, (8) a 19-mile,
115-kilovolt (kV) transmission line that connects the Carmen powerhouse
to the Bonneville Power Administration's Cougar-Eugene transmission
line; and (9) appurtenant facilities.
    The Trail Bridge development includes: (1) A 100-foot-high, 700-
foot-long, and 24-foot-wide earthen Trail Bridge dam section with a
gated Ogee spillway, (2) a 1,000-foot-long and 20-foot-wide emergency
spillway section, (3) a 300-foot-long by 12-foot-diameter concrete
penstock at the intake that narrows to a diameter of 7 feet, (4) a 66-
foot-long by 61-foot-wide Trail Bridge powerhouse, (5) one Kaplan
turbine with a generating capacity of 9.975 MW; and (6) a one-mile,
11.5-kV distribution line that connects the Trail Bridge powerhouse to
the Carmen powerhouse.
    m. A copy of the application is available for review at the
Commission in the Public Reference Room or may be viewed on the
Commission's Web site at http://www.ferc.gov using the ``eLibrary''

link. Enter the docket number excluding the last three digits in the
docket number field to access the document. For assistance, contact
FERC Online Support at<EMAIL_ADDRESS>or toll-free at 1-
866-208-3676, or for TTY,<PHONE_NUMBER>. A copy is also available for
inspection and reproduction at the address in item h above.
    You may also register online at http://www.ferc.gov/docs-filing/esubscription.asp
 to be notified via e-mail of new filings and

issuances related to this or other pending projects. For assistance,
contact FERC Online Support.
    n. Scoping Process.
    The Commission intends to prepare an Environmental Assessment (EA)
on the project in accordance with the National Environmental Policy
Act. The EA will consider both site-specific and cumulative
environmental impacts and reasonable alternatives to the proposed
action.

Scoping Meetings

    Commission staff will conduct one agency scoping meeting and one
public scoping meeting. The agency scoping meeting will focus on
resource agency and non-governmental organization (NGO) concerns, while
the public scoping meeting is primarily for public input. All
interested individuals, organizations, and agencies are invited to
attend one or both of the meetings, and to assist the staff in
identifying the scope of the environmental issues that should be
analyzed in the EA. The times and locations of these meetings are as
follows:

Agency Scoping Meeting
    Date: September 13, 2007, Time : 9 a.m. to noon (PST),
    Place: Midgleys Building Meeting Room,
    Address: 500 East 4th Avenue, Eugene, Oregon (The Midgleys Building
Meeting Room is located at the corner of East 4th Avenue and High
Street, adjacent to the EWEB office located at 409 High Street).
Public Scoping Meeting
    Date: September 13, 2007,
    Time: 7 p.m. to 10 p.m. (PST),
    Place: Midgleys Building Meeting Room,
    Address: 500 East 4th Avenue, Eugene, Oregon (see above).

    Copies of the Scoping Document (SD1) outlining the subject areas to
be addressed in the EA were distributed to the parties on the
Commission's mailing list. Copies of the SD1 will be available at the
scoping meetings or may be viewed on the internet at http://www.ferc.gov
 using the ``eLibrary'' link (see item m above).

Site Visit

    EWEB and Commission staff will visit the Carmen-Smith Project on
September 12, 2007. All participants interested in seeing the project
should meet at EWEB's Offices at 500 East 4th Street, Eugene, Oregon at
8 a.m. or meet at the informal parking area across Highway 126 from the
Trail Bridge Dam at 9:30 a.m. Anyone with questions about the site
visit (or needing directions) should contact Karen Lee at (541) 341-
8514 or<EMAIL_ADDRESS>Those individuals planning to
participate in the site visit should notify Ms. Lee of their intent, no
later than September 6, 2007.

Objectives

    At the scoping meetings, the staff will: (1) Summarize the
environmental issues tentatively identified for analysis in the EA; (2)
solicit from the meeting participants all available information,
especially quantifiable data, on the resources at issue; (3) encourage
statements from experts and the public on issues that should be
analyzed in the EA, including viewpoints in opposition to, or in
support of, the staff's preliminary views; (4) determine the resource
issues to be addressed in the EA; and (5) identify those issues that
require a detailed analysis, as well as those issues that do not
require a detailed analysis.

Procedures

    The meetings are recorded by a stenographer and become part of the
formal record of the Commission proceeding on the project.
    Individuals, organizations, and agencies with environmental
expertise and concerns are encouraged to attend the meetings and to
assist the staff in defining and clarifying the issues to be addressed
in the EA.

Kimberly D. Bose,
Secretary.
[FR Doc. E7-16249 Filed 8-17-07; 8:45 am]

BILLING CODE 6717-01-P