[Federal Register: September 24, 2010 (Volume 75, Number 185)]
[Rules and Regulations]
[Page 58293-58303]
[DOCID:fr24se10-4]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-22-000; Order No. 739]

Promoting a Competitive Market for Capacity Reassignment

September 20, 2010.

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission lifts the price cap
for all electric transmission customers reassigning transmission
capacity based on the Commission's experience to date and a two-year
study, released April 15, 2010. The removal of the price cap is
intended to help facilitate the development of a market for electric
transmission capacity reassignments as a competitive alternative to
transmission capacity acquired directly from the transmission owner.

DATES: Effective Date: This rule will become effective September 24,
2010.

FOR FURTHER INFORMATION CONTACT:
Laurel Hyde (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
A. Cory Lankford (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:
Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer,
Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.

                                                              Paragraph
                                                                 Nos.

I. Background..............................................            2
II. Discussion.............................................           15
    A. Removal of the Price Cap............................           15
        1. Comments........................................           15
        2. Commission Determination........................           25
            a. Removal of the Price Cap....................           25
            b. Implementation of the Requirement...........           37
    B. Non-Rate Reforms to Promote Secondary Market........           39
        1. NOPR Proposal...................................           39
        2. Comments........................................           40
        3. Commission Determination........................           43
III. Information Collection Statement......................           44
IV. Environmental Analysis.................................           48
V. Regulatory Flexibility Act..............................           49
VI. Document Availability..................................           50
VII. Effective Date and Congressional Notification.........           53

    1. Based on the Commission's experience to date and a two-year
study, released April 15, 2010,\1\ the Federal Energy Regulatory
Commission in this Final Rule makes permanent the lifting of price caps
for transmission customers reassigning electric transmission capacity.
This action is intended to facilitate the development of a market for
electric transmission capacity reassignments as a competitive
alternative to primary transmission capacity.
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    \1\ FERC Staff, Staff Findings on Capacity Reassignment (2010),
available at http://www.ferc.gov (Staff Report).
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I. Background

    2. In Order No. 888, the Commission concluded that a transmission
provider's pro forma Open Access Transmission Tariff (OATT) must permit
explicitly the voluntary reassignment of all or part of a holder's firm
point-to-point capacity rights to any eligible customer.\2\ The
Commission also found that allowing holders of firm transmission
capacity rights to reassign that transmission capacity would help
parties manage the financial risks associated with their long-term
commitment, reduce the market power of transmission providers by
enabling customers to compete, and foster efficient transmission
capacity allocation.
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    \2\ 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, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ]
31,036, at 31,696 (1996), order on reh'g, Order No. 888-A, 62 FR
12274 (March 14, 1997), FERC Stats. & Regs. ] 31,048 (1997), 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
(DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
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    3. With respect to the appropriate rate for transmission capacity
reassignment, the Commission concluded it could not permit
reassignments at market-based rates because it was unable to determine
that the market for reassigned transmission capacity was sufficiently
competitive so that resellers would not be able to exert market power.
Instead, the Commission capped the rate at the highest of: (1) The
original transmission rate charged to the purchaser (assignor); (2) the
transmission provider's maximum stated firm transmission rate in effect
at the time of the reassignment; or (3) the assignor's own opportunity
costs capped at the cost of expansion (price cap). The Commission
further explained that opportunity cost pricing had been permitted at
``the higher of embedded costs or legitimate and verifiable opportunity
costs, but not the sum of the two (i.e., `or' pricing is

permitted; `and' pricing is not).'' \3\ In Order No. 888-A, the
Commission explained that opportunity costs for transmission capacity
reassigned by a customer should be measured in a manner analogous to
that used to measure the transmission provider's opportunity cost.\4\
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    \3\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,740.
    \4\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,224.
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    4. To foster the development of a more robust secondary market for
transmission capacity, the Commission, in Order No. 890, concluded that
it was appropriate to lift the price cap for all transmission customers
reassigning transmission capacity.\5\ The Commission stated that this
would allow transmission capacity to be allocated to those entities
that value it most, thereby sending more accurate price signals to
identify the appropriate location for construction of new transmission
facilities to reduce congestion.\6\ The Commission also found that
market forces, combined with the requirements of the pro forma OATT as
modified in Order No. 890, would limit the ability of resellers,
including affiliates of the transmission provider, to exert market
power.
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    \5\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (March 15, 2007),
FERC Stats. & Regs. ] 31,241, at P 808 (2007), order on reh'g, Order
No. 890-A, 73 FR 2984 (January 16, 2008), 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).
    \6\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 808.
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    5. To enhance oversight and monitoring activities, the Commission
adopted reforms to the underlying rules governing transmission capacity
reassignments.\7\ First, the Commission required that all resales or
reassignments of transmission capacity be conducted through or
otherwise posted on the transmission provider's OASIS on or before the
date the reassigned service commences.\8\ Second, the Commission
required that assignees of transmission capacity execute a service
agreement prior to the date on which the reassigned service
commences.\9\ Third, in addition to existing OASIS posting
requirements, the Commission required transmission providers to
aggregate and summarize in an electric quarterly report the data
contained in these service agreements.\10\
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    \7\ Id. P 815.
    \8\ Id.
    \9\ Id. P 816.
    \10\ Id. P 817.
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    6. The Commission also directed staff to closely monitor the
reassignment-related data submitted by transmission providers in their
quarterly reports to identify any problems in the development of the
secondary market for transmission capacity and, in particular, the
potential exercise of market power.\11\ Thus, the Commission directed
staff to prepare, within six months of receipt of two years of
quarterly reports, a report summarizing its findings.\12\ In addition,
the Commission encouraged market participants to provide feedback
regarding the development of the secondary electric transmission
capacity market and, in particular, to contact the Commission's
Enforcement Hotline if concerns arise.
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    \11\ Id. P 820.
    \12\ Id.
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    7. In Order No. 890-A, the Commission affirmed its decision to
remove the price cap on reassignments of electric transmission capacity
but granted rehearing to limit the period during which reassignments
may occur above the cap.\13\ The period was limited so that the
Commission could review the Staff Report to see if changes were needed
based on the actual operation of the reassignment program. Accordingly,
the Commission amended section 23.1 of the pro forma OATT to reinstate
the price cap as of October 1, 2010.\14\
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    \13\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 388,
390.
    \14\ Id. P 390.
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    8. The Commission also clarified that, as of the effective date of
the reforms adopted in Order No. 890, all reassignments of electric
transmission capacity must take place under the terms and conditions of
the transmission provider's OATT. As a result, there was no longer a
need for the assigning party to have on file with the Commission a rate
schedule governing reassigned capacity. To the extent that a reseller
has a market-based rate tariff on file, the provisions of that tariff,
including a price cap or reporting obligations, will not apply to the
reassignment since such transactions no longer take place pursuant to
the authorization of that tariff.
    9. In Order No. 890-B, the Commission clarified that the pro forma
OATT does not, and will not, permit the withholding of transmission
capacity by the transmission provider and that it effectively
establishes a price cap for long-term reassignments at the transmission
provider's cost of expanding its system.\15\ The Commission further
found that the fact that a transmission provider's affiliate may profit
from congestion on the system does not relieve the transmission
provider of its obligation to offer all available transmission capacity
and expand its system as necessary to accommodate requests for
service.\16\ The Commission pointed out that customers that do not wish
to participate in the secondary market may continue to take service
from the transmission provider directly, just as if the price cap had
not been lifted.\17\
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    \15\ Order No. 890-B, 123 FERC ] 61,299 at P 78.
    \16\ Id.
    \17\ Id. P 79.
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    10. With regard to the Staff Report, the Commission clarified that
staff should focus on the competitive effects of removing the price cap
for reassigned electric transmission capacity.\18\ The Commission
stated that staff should consider the number of reassignments occurring
over the study period, the magnitude and variability of resale prices,
the term of the reassignments, and any relationship between resale
prices and price differentials in related energy markets. In addition,
the Commission directed staff to examine the nature and scope of
reassignments undertaken by the transmission provider's affiliates and
include in its report any evidence of abuse in the secondary market for
transmission capacity, whether by those affiliates or other customers.
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    \18\ Id. P 83.
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    11. The Commission also granted rehearing and directed each
transmission provider to include in its electric quarterly report the
identity of the reseller and indicate whether the reseller is
affiliated with the transmission provider.\19\ The Commission also
directed each transmission provider to include in its electric
quarterly reports the rate that would have been charged under its OATT
had the secondary customer purchased primary service from the
transmission provider for the term of the reassignment.\20\ The
Commission directed transmission providers to submit this additional
data for all resales during the study period and to update, as
necessary, any previously-filed electric quarterly reports on or before
the date they submitted their next electric quarterly reports.
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    \19\ Id. P 84.
    \20\ Id.
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    12. On April 15, 2010, Commission staff published its report on the
two-year study period.\21\ The Staff Report took a comprehensive look
at electric point-to-point transmission capacity

reassignment that occurred over the period from the second quarter of
2007 through the fourth quarter of 2009. Staff examined all reported
electric transmission reassignments during this period on both a
national and a regional basis. These almost 35,000 transactions
encompassed 65 TWh of total volume transferred. Staff looked at the
data in a number of ways, in order to better understand the market and
to look for evidence of abuse. In doing so, staff looked at the
magnitude and variability of resale prices, and focused on trends in
those numbers over time and by region. Staff compared resale prices to
the maximum tariff rates that would have otherwise been in effect for
those transactions. Further, staff looked at reassignments by term--
hourly, daily, monthly, and yearly and looked at differences in term by
transmission provider and by volume. Where the receipt and delivery
points of transactions had reported price indices with sufficient data,
staff compared the prices of reassignments to the energy market spread
(differential in prices between the two locations) over the same time
periods.
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    \21\ FERC Staff, Staff Finding on Capacity Reassignment (2010),
available at http://www.ferc.gov (Staff Report).
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    13. Staff also compared resale prices for transactions involving
affiliates versus non-affiliates. Staff compared the rate of
transactions above the cap for both affiliates and non-affiliates.
Staff looked for additional forms of affiliate abuse such as a
transmission provider providing preferential treatment in the
allocation of reassigned capacity to an affiliate. Staff also checked
for complaints of the abuse in affiliate transactions, as well as for
capacity reassignment in general.
    14. Two weeks after the release of the Staff Report, based on the
Commission's experience in the natural gas transportation market and
the Staff Report's conclusion that the secondary market had grown
substantially and that resale prices reflected market fundamentals
rather than the exercise of market power, the Commission issued a
Notice of Proposed Rulemaking (NOPR) proposing to lift the price cap
for all electric transmission customers reassigning transmission
capacity beyond October 1, 2010. In addition, the Commission proposed
to direct transmission providers to submit corresponding revisions to
their OATTs within 30 days of publication of the Final Rule in the
Federal Register. The Commission also sought comment as to whether
there are any other reforms that it should undertake to create a more
efficient and vibrant secondary market for electric transmission
capacity. In response to these NOPR proposals, the Commission received
comments from 13 parties, which are addressed below.\22\
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    \22\ A list of commenters is provided in Appendix A.
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II. Discussion

A. Removal of the Price Cap

1. Comments
    15. Several commenters support the Commission's proposal to remove
the price cap on transmission reassignments permanently.\23\ They
contend that removal of the cap will encourage the development of a
more robust secondary market, resulting in appropriate price signals
and an efficient allocation of transmission capacity. Cargill comments
that the resale of transmission capacity at negotiated rates is
consistent with other Commission reforms in favor of market-based
pricing.
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    \23\ E.g. Bonneville, Cargill, EPSA, FIEG, PG&E, PGE, Powerex,
Seattle.
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    16. Despite their general support for the Commission's proposal,
EPSA and PG&E raise concerns about the staff study and the need for
transparency. EPSA states that the Staff Report shows some gaps that
will require further analysis; such as limited numbers of transmission
providers reported and the majority of transactions being from
Bonneville. PG&E expresses a lingering concern about the potential for
transmission service providers to raise power prices in locations where
there is insufficient competition. EPSA and PG&E urge the Commission to
continue to monitor the capacity reassignment market as it matures so
that the Commission will be informed and therefore able to direct
necessary reforms to the market, as the needed reforms reveal
themselves. EPSA further urges the Commission to look at ways of
increasing transparency for transmission capacity available for
reassignments as a way of promoting the secondary market for
reassignment. Powerex comments that there are already a number of
safeguards including requirements that transmission providers report
reassignments on their systems on OASIS and in the electronic quarterly
reports (EQR) that should help limit abuses. Similarly, Seattle
comments that reconciliation of EQRs, audits, and OASIS transactions
would go a long way to ensure that resale markets are functioning
without affiliate abuse.
    17. Bonneville agrees that lifting the price cap on transmission
capacity reassignments appears to support the goal of a more robust
secondary market for that capacity but asks the Commission to recognize
the position of non-jurisdictional entities, such as itself. Bonneville
contends that non-jurisdictional entities may have to place conditions
upon the removal of the cap in order to obtain reciprocity and comply
with their applicable statutory requirements. Bonneville contends that
if its administrator determines that behavior associated with
transmission capacity reassignments is occurring on its system in a
manner that frustrates or is otherwise inconsistent with the
administrator's statutory requirements to make all excess capacity
available to utilities on a fair and nondiscriminatory basis, the
administrator must be able to act promptly to stop that behavior. Thus,
Bonneville suggests that any revision to section 23 of Bonneville's
OATT permanently lifting the price cap must be conditioned upon the
administrator's express authority to carry out this mandate including
the right to reinstate the cap expeditiously if necessary.
    18. Other commenters argue against removal of the price cap,
contending that staff's two-year study provides insufficient evidence
to support a finding that the secondary market is sufficiently
competitive to lift the price caps or that market forces or other
factors will be effective to adequately protect consumers.\24\ These
commenters point out that, although the Final Rule would apply to an
estimated 132 public utilities, the Staff Report included data from
only 26 with 79 percent of the reported transactions coming from
Bonneville. These commenters also point out that the study was
performed during a recession with concomitant reductions in the demand
for electricity, and that Bonneville is atypical, given that it is
dependent on large hydroelectric projects. APPA further comments that
because there were so few sales made during the study period by
affiliates above the rate cap, it would appear that reinstitution of
the cap would not significantly dampen resales of capacity by
affiliates of transmission providers.
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    \24\ E.g. APPA, NRECA, SCE, TAPS, Outland, and TDU Systems.
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    19. TAPS states that the staff study did not examine both prices
offered and accepted such that the Commission could determine the level
of market interest in reassigned capacity, whether prices increased,
the cause of price changes, and whether those prices remained in the
zone of reasonableness. It notes that the staff study compared resale
prices during the study period to the tariff rate, but not to the
opportunity cost cap, which is likely higher. It argues that
accordingly, the study does not show that the price cap constrained

any prices, and thus it prevents a finding that the price cap is unjust
and unreasonable. SCE requests that the Commission reconcile its
proposal with findings in the Staff Report that removal of the price
cap does not appear to be primarily responsible for the observed growth
in the secondary market. It also states that the Staff Report did not
definitively conclude that there was not abuse by resellers, even in a
period with very low demand and no supply scarcity. SCE states that
this is not sufficient evidence to lift the price cap. APPA, SCE and
TAPS suggest that, if the Commission wishes to lift the price cap, it
should only do so as a continuation of the experiment.
    20. NRECA, TAPS, and TDU Systems argue that the Staff Report does
not provide a sufficient factual basis for the Commission to conclude
that the OATT section 23.1, which reinstates the price cap on October
1, 2010, is unjust and unreasonable or to conclude that proposed
revision is just and reasonable. Moreover, TAPS and TDU Systems comment
that market-based reassignment of transmission capacity should not be
available to entities to the extent they lack market-based rate
authority in the area in which the transmission reservation is located.
TDU Systems states that each secondary transmission capacity market
should be looked at individually, and that there is no single, national
market for secondary transmission capacity rights. It questions why the
Staff Report considers Public Service of New Hampshire (PSNH) to be an
aberration, while the nearby Central Vermont Public Service Corporation
(Central Vermont) system is presented as representing national trends.
    21. TAPS and TDU Systems further contend that, to permit market-
based rates, the Commission remains bound by the requirement that
market-based rates be supported by empirical proof that existing
competition would ensure that the actual price is just and
reasonable.\25\ TDU Systems comments that courts have held that
undocumented reliance on market forces is insufficient grounds for
authorizing market-based rates.\26\ Moreover, TAPS and TDU Systems
argue that the Commission has a requirement to make an ex ante finding
of the absence of market power and sufficient post-approval
requirements.\27\ SCE agrees that the Commission should engage in an ex
ante competitive analysis to find that the transmission reseller lacks
market power, or take sufficient steps to mitigate market power, as
well as adopt sufficient post-approval reporting requirements.
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    \25\ Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d
1486, 1510 (DC Cir. 1984)(Farmers Union).
    \26\ Citing Transwestern Pipeline, 43 FERC ] 61,240, at 61,250
(1988).
    \27\ Citing California ex. Rel. Lockyer v. FERC, 383 F.3d 1006,
1013 (9th Cir. 2004).
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    22. Outland states that the pilot project has allowed resellers to
acquire capacity ``for pennies and then hold up the first renewable
energy generator that comes along looking to use it.'' \28\ It states
that parties acquire transmission when they do not need it for a real
generation project, to the detriment of real projects.
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    \28\ Outland at 1.
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    23. NRECA, TAPS, and TDU Systems urge the Commission, at a minimum,
to retain the price cap on transmission capacity reassignments for
transmission provider affiliates and retail/merchant functions. TAPS
states that the pattern of affiliate pricing reveals more about
corporate strategy selected by a few corporate entities and general
conditions during an atypical period, than confirming the Commission's
assumption that the rates for primary capacity or competition in the
reassignment market will restrain prices. It states that assuming that
the customer may always take service from the transmission provider
directly is cold comfort if the available capacity has been assigned to
the transmission provider's affiliate. NRECA states that a larger
portion of affiliate than non-affiliate transactions occurred over the
cap, and points to the PSNH system where all reported transactions
originated with an affiliate and occurred over the price cap.
    24. In its supplemental comments, Powerex expresses concern that
Bonneville might reinstate the price cap as of October 1, 2010,
regardless of Commission action in this proceeding. Powerex asks the
Commission to address the possible adverse consequences of non-
jurisdictional transmission providers reinstating price caps on
transmission reassignments and to provide guidance to customers seeking
to reassign transmission on the systems of non-jurisdictional
transmission providers that elect not to adopt any reforms the
Commission directs. To address this issue, Powerex requests the
Commission to clarify that its seller-specific market-based rate
schedule for transmission reassignment remains operative.
Alternatively, Powerex seeks guidance on how to price capacity
reassignments based on the customer's opportunity cost capped at the
transmission provider's cost of expansion.
2. Commission Determination
a. Removal of the Price Cap
    25. The Commission hereby adopts its NOPR proposal to lift the
price cap for all reassignments of electric transmission capacity to
become effective October 1, 2010. Removal of the price cap will help
foster the development of a more robust secondary market for
transmission capacity because point-to-point transmission service
customers will have increased incentives to resell their service
whenever others place a higher value on it. Existing transmission,
therefore, may be put to better, more efficient use.
    26. Moreover, removal of the price cap will promote the efficient
construction of new capacity. Prices serve as signals indicating where
capacity shortages exist and where potentially profitable construction
can take place. The Commission has previously addressed the need for
new transmission and established incentives for its construction.\29\
Removing the price cap on sales of secondary electric transmission
capacity is one way to create the proper incentives for new
transmission investment in this industry. Areas with congestion tend to
have higher prices and thus signal the need for investment.\30\
However, if prices for reassigned capacity exceed the cost of
construction of new transmission, the customer could request service
from the transmission provider which would support investment in new
transmission and lower costs prospectively by relieving constrained
transmission capacity. Thus, the price of reassigned capacity will
remain effectively capped at the cost of new transmission. We therefore
reaffirm the Commission's finding in Order No. 890-A that removal of
the price cap for reassigned capacity will help establish a competitive
market for secondary transmission capacity that will send more accurate
signals and that such price signals will promote more efficient use of
the electric transmission system.\31\
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    \29\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 71 FR 43294 (July 31, 2006), FERC Stats. & Regs. ]
31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152 (January
10, 2007), FERC Stats. & Regs. ] 31,236 (2006), order on reh'g, 119
FERC ] 61,062 (2007).
    \30\ See Interstate Nat'l Gas Ass'n of America v. FERC, 285 F.3d
18, 32-34 (DC Cir. 2002) (INGAA) (``[B]rief spikes in moments of
extreme exigency are completely consistent with competition,
reflecting scarcity rather than monopoly.'').
    \31\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 388.
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    27. Our continued regulatory oversight will also limit the
potential for the exercise of market power. We are

not deregulating or otherwise adopting market-based rates for the
provision of transmission service under the pro forma OATT.
Transmission providers will continue to be obligated to offer available
transfer capability to customers, including available transfer
capability associated with purchased but unused capacity. Transmission
providers also will continue to be obligated to construct new
facilities to satisfy requests for service if those requests cannot be
satisfied using existing capacity. Furthermore, the rates for
transmission service provided under the pro forma OATT will continue to
be determined on a cost-of-service basis unless the transmission
provider can demonstrate, on a case-specific basis, that it lacks
market power. Nothing in this Final Rule affects the obligations of
transmission providers to offer service under the pro forma OATT at
cost-based rates. The availability of firm and non-firm service from
transmission providers, therefore, will limit the ability of
reassignors to exercise market power. In INGAA, the Court of Appeals
for the District of Columbia Circuit recognized that the maintenance of
regulated rates for primary service would protect against the potential
for the exercise of market power in the capacity release market.\32\
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    \32\ 285 F.3d at 32 (``[i]f holders of firm capacity do not use
or sell all of their entitlement, the pipelines are required to sell
the idle capacity as interruptible service to any taker at no more
than the maximum rate--which is still applicable to the
pipelines''); see also, Promotion of a More Efficient Capacity
Release Market, Order No. 712, 73 FR 37058 (June 30, 2008), FERC
Stats. & Regs. ] 31,271, at P48-49 (2008), order on reh'g, Order No.
712-A, FERC Stats. & Regs. ] 31,284 (2008).
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    28. The Commission disagrees with suggestions that affiliates of
the transmission provider be treated differently than non-affiliated
customers with respect to reassignments of transmission capacity. The
Commission's Standards of Conduct are designed to prevent the
transmission provider and its affiliate from acting in concert to
exercise market power.\33\ Commenters did not identify any affiliate
concerns that these obligations, along with the monitoring discussed
below, would not address.
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    \33\ See Standards of Conduct for Transmission Providers, Order
No. 717, 73 FR 63796 (October 27, 2008), FERC Stats. & Regs. ]
31,280 (2008), order on reh'g, Order No. 717-A, 74 FR 54463 (October
22, 2009), FERC Stats. & Regs. ] 31,297 (2009), order on reh'g,
Order No. 717-B, 129 FERC ] 61,123 (2009), order on reh'g, Order No.
717-C, 131 FERC ] 61,045 (2010). The Commission's Standards of
Conduct establish that a transmission provider must (1) treat all
customers, affiliated and non-affiliated, on a not unduly
discriminatory basis, (2) not make or grant any undue preference or
advantage to any person, and (3) not subject any person to any undue
prejudice or disadvantage with respect to transmission of electric
energy. This would include avoiding undue prejudice or disadvantage
in the initial allocation of capacity to affiliates, thereby
allowing those affiliates to gain market power and then to exercise
it when reassigning capacity.
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    29. The Commission takes seriously the possibility that resellers
may attempt to exercise market power in the secondary market for
transmission. We continue to find, however, that the regulatory
protections in place and our increased oversight of this market will
limit the potential for market power abuse. Prices for secondary
transmission capacity may rise above prices for primary transmission
capacity but this alone does not indicate an abuse of market power. On
the contrary, courts have recognized that prices in a competitive
market should rise during periods when capacity is truly scarce in
order to ensure that transmission capacity is being allocated
appropriately.\34\ Nevertheless, the Commission will continue to
monitor the secondary transmission capacity market to ensure that
participants are not exercising market power.\35\ The Commission also
will monitor for abuse by transmission providers in concert with their
affiliates. If a customer has evidence of an exercise of market power
or other abuse, it should bring the matter to the Commission's
attention through a complaint or other appropriate procedural
mechanism. Absent such evidence, the Commission concludes that the
continued rate regulation of the primary market for electric
transmission capacity and the transmission provider's obligation to
expand its system to accommodate service requests adequately mitigates
any market power that resellers may have in the long-term secondary
market.
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    \34\ INGAA, 285 F.3d at 32-34 (``[B]rief spikes in moments of
extreme exigency are completely consistent with competition,
reflecting scarcity rather than monopoly.'').
    \35\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 815.
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    30. The Staff Report did not raise any concerns with removal of the
price cap that would warrant its reimposition given the regulatory
protections and increased market oversight discussed above. The report
included a comprehensive examination of the assignments that took place
during the study period which included both the period prior to the
economic downturn starting in September 2008 and the period after the
downturn. Although the Staff Report did not conclusively demonstrate
that the price cap inhibited the growth of the secondary market, the
data showed a marked growth in reassignments, with both the number of
transactions and the volume increasing during the two and one half year
time span. The number of reassignments grew from just over 200 in 2007
to almost 32,000 in 2009. During this same period, the volume
reassigned grew from 3 TWh to 36 TWh.
    31. The data do not suggest the exercise of market power. The
prices during the test period appear consistent with pricing
differentials between locational markets, indicating that the
transactions reflect market fundamentals, not the exercise of market
power.\36\ Moreover, the Staff Report found that 99 percent of
reassignments were priced at or below the transmission provider's
maximum firm transmission rate, an indication that prices reflect
market conditions and competition rather than the exercise of market
power.\37\ The brief spikes above the price cap are consistent with a
competitive market, indicating scarcity rather than market power.\38\
---------------------------------------------------------------------------

    \36\ See INGAA, 285 F.3d at 31 (indicating that differentials in
prices between receipt and delivery points are indicative of the
value of the transportation between those points).
    \37\ Because 99 percent of the prices were below the tariff
rate, these prices are almost certainly lower than opportunity costs
which TAPS suggests are likely higher than the tariff rate.
    \38\ INGAA, 285 F.3d 18, 32 (``A surge in the price of candles
during a power outage is no evidence of monopoly in the candle
market'').
---------------------------------------------------------------------------

    32. We disagree with comments suggesting that the Staff Report does
not provide enough evidence to support a finding that the market is
sufficiently competitive to lift the price cap because it relied on
data from a limited number of transmission providers. While capacity
reassignments occurred on a limited number of transmission systems, the
lack of data for other transmission providers indicates a lack of
reassignments on those systems, not an exercise of market power or lack
of potential competition for capacity reassignment. Where reassignment
is currently non-existent or occurring at a lower level, potential
reassignment of transmission in these areas, should it develop, would
face competition associated with transmission that can be acquired from
other customers. Such reassignment also would compete with capacity
available from the transmission provider. Although the data in the
Staff Report included extensive data from Bonneville and Central
Vermont, the greater number of such assignments may be due to
differences in market dynamics (such as the extensive use of
hydroelectric power in the Bonneville region) or reporting conventions
(in the case of Central Vermont).\39\ It also may

indicate that capacity reassignment is more developed in those areas.
The volume of capacity reassignments on these two systems provides an
example of what may be possible in other areas of the country. As for
arguments that the time period under review was atypical due to the
economic downturn and, thus, not representative, we note that study
began the second quarter of 2007, well before the downturn began.
---------------------------------------------------------------------------

    \39\ The Staff Report states that ``the large number of [Central
Vermont] transactions may be due, in part, to reporting conventions.
For EQR reporting purposes, each line of data is counted as one
transaction.'' See Staff Report at 4.
---------------------------------------------------------------------------

    33. The Staff Report also did not show evidence of affiliate abuse.
Ninety-nine percent of reassignments by affiliates of the transmission
provider were at or below the transmission provider's maximum rate. The
percentage of such reassignments over the maximum firm transmission
rate by affiliates was comparable to that by non-affiliates (0.5
percent versus 0.4 percent).
    34. While it is true, as some of the commenters point out, that the
reassignment transactions were limited to certain areas and utilities,
we see no reason to expect different results as capacity reassignment
expands. There have not been allegations of the exercise of market
power in reassignment markets, and commenters do not provide any data
to suggest that market power may be more prevalent as capacity
reassignment increases on other transmission systems. Development of a
more robust reassignment market in areas where reassignments are not
prevalent should raise, rather than lower, the level of competition in
markets. Moreover, we will continue to monitor the market and if
anomalies develop in certain areas, they can be addressed.
    35. We disagree with the comments that a market power study or
other empirical competition analyses are required to lift the price cap
on transmission capacity reassignments. Contrary to commenters'
assertions, market power analyses are not the only method to ensure
that market-based rates remain just and reasonable.\40\ In INGAA,\41\
the DC Circuit affirmed the Commission's removal of price ceilings for
short-term capacity releases by shippers in the natural gas market
without requiring sellers to submit market power analyses. The court
recognized that non-cost factors such as the need to facilitate
movement of capacity into the hands of those who value it most may also
justify the removal of price ceilings. The court concluded that these
non-cost factors, combined with the limitation of negotiated rates to
the secondary market, distinguished the case from Farmers Union in
which the court had reversed a Commission determination to implement
lighthanded regulation of the oil industry.\42\
---------------------------------------------------------------------------

    \40\ See Alternatives to Traditional Cost-of-Service Ratemaking
for Natural Gas Pipelines and Regulation of Negotiated
Transportation Services of Natural Gas Pipelines, 74 FERC ] 61,076,
at 61,227-36 (1996). The Commission ultimately determined in that
case that a market power analysis was required in order to allow a
pipeline to use market-based pricing instead of cost-of-service
rates. The Commission has not proposed to allow transmission
providers to engage in sales of primary capacity at market-based
rates and, as explained below, sufficient protections exist to
ensure the secondary market for transmission capacity remains
sufficiently competitive without requiring market power analyses
from each reseller.
    \41\ Interstate Nat'l Gas Ass'n of American v. FERC, 285 F.3d at
33 (DC Cir. 2002).
    \42\ Interstate Nat'l Gas Ass'n of America v. FERC, 285 F.3d 18
at 31-34 (DC Cir. 2002), order on remand, 101 FERC ] 61,127 (2002),
order on reh'g, 106 FERC ] 61,088 (2004), aff'd sub nom. American
Gas Ass'n v. FERC, 428 F.3d 255 (DC Cir. 2005).
---------------------------------------------------------------------------

    36. Farmers Union itself did not require a market power study to
support a move to a more market-based regulatory regime. The court
found that rates should be within a ``zone of reasonableness, where
[they] are neither less than compensatory nor excessive.'' \43\
Moreover, the court found that the Commission could justify a move to a
more market-based focus ``by a showing that under circumstances the
goals and purposes of [the Commission's statutory mandate] will be
accomplished through substantially less regulatory oversight.'' \44\
Here, the Commission is relying on competition in the market for
transmission capacity, together with the regulatory protections
discussed above, to ensure just and reasonable rates. Protections, such
as continuing rate regulation of the transmission provider's primary
capacity, retention of the requirement for transmission owners to build
additional capacity at cost-based rates, competition among resellers,
reforms to the secondary market for transmission capacity, and
reporting requirements combined with enforcement proceedings, audits,
and other regulatory controls, will assure that prices in the secondary
market for electric transmission capacity remain within a zone of
reasonableness.\45\
---------------------------------------------------------------------------

    \43\ Farmers Union, 734 F.2d at 1502; see also, INGAA, 285 F.3d
at 31.
    \44\ Farmers Union, 734 F.2d at 1510.
    \45\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 811;
see also Order No. 712, 73 FR 37058 (June 30, 2008), FERC Stats. &
Regs. ] 31,271 at P 39 (2008), order on reh'g, Order No. 712-A, FERC
Stats. & Regs. ] 31,284 (2008), aff'd sub nom. Interstate Natural
Gas Ass'n of America, No. 09-1016 (DC Cir. Aug. 13, 2010).
---------------------------------------------------------------------------

b. Implementation of the Requirement
    37. Because the current OATTs reinstate the price cap as of October
1, 2010, transmission providers will need to revise section 23 of the
pro forma OATT, as indicated in Appendix B. We direct transmission
providers to file these changes within 30 days from publication of this
Final Rule in the Federal Register. Bonneville requests a blanket
waiver of the requirement for non-jurisdictional entities that are
unable to satisfy reciprocity conditions with regard to the
reassignment of transmission capacity. Whether the particular terms and
conditions of a non-jurisdictional transmission provider's reciprocity
tariff satisfy the Commission's open access principles must be
determined on a case-by-case basis. Therefore, the Commission denies,
without prejudice, Bonneville's request for a blanket waiver.
    38. We find Powerex's concern that Bonneville will reinstate the
price cap as of October 1, 2010 to be premature, since Bonneville has
not made a final decision at this point. Moreover, when Bonneville
submitted its tariff revisions pursuant to Order No. 890, it declined
to adopt certain pro forma provisions related to the reassignment of
transmission capacity and several transmission customers within
Bonneville, including Powerex, filed stand-alone rate schedules
allowing them to sell transmission capacity above the price cap.\46\
These customers may submit any necessary revisions to their rate
schedules before October 1, 2010 and request waiver of the prior notice
requirement, if they find such action to be necessary and appropriate.
---------------------------------------------------------------------------

    \46\ See Portland General Electric Co., Docket No. ER09-93-000
(Dec. 3, 2008) (unpublished letter order); Idaho Power Co., Docket
No. ER09-524-000 (Mar. 5, 2009) (unpublished letter order); Puget
Sound Energy, Inc., Docket No. ER09-528-000 (Mar. 5, 2009)
(unpublished letter order); Avista Corp., ER09-729-000 (May 12,
2009) (unpublished letter order); PacifiCorp, Docket No. ER09-921-
001 (Sept. 29, 2009) (unpublished letter order); Powerex Corp.,
Docket No. ER09-926-000 (May 21, 2009) (unpublished letter order).
---------------------------------------------------------------------------

B. Non-Rate Reforms To Promote Secondary Market

1. NOPR Proposal
    39. In the NOPR, the Commission sought comment as to whether there
are any reforms, other than removal of the price cap, that it should
undertake to create a more efficient and vibrant secondary market for
transmission capacity. The Commission asked if there are non-price
limitations or regional factors that may be continuing to limit the
utility of reassignment. By way of an example, the Commission asked if
there

are reforms to the redirect process that would enable all firm
customers to use their firm capacity more flexibly and thereby
facilitate capacity reassignment by making point changes by the buyer
of reassigned capacity more efficient.
2. Comments
    40. Although FIEG supports the Commission's proposal to allow
redirects of reassigned capacity, several other commenters raise
concerns. Powerex admits that the ability to modify receipt and
delivery points of reassigned capacity may make the capacity more
attractive to a potential third-party assignee but warns that this
practice would erode the priority that firm capacity should be
accorded. NRECA expresses similar concern that this proposal may give
higher priority to point-to-point customers who wish to redirect by
awarding them service over those non-firm customers who do not redirect
and over secondary network customers. APPA contends that any reforms to
firm point-to-point service proposed to increase the attractiveness of
re-sales of firm point-to-point capacity would have to be carefully
assessed to ensure that they do not result in a degradation of the
quality of network integration transmission service. TAPS and TDU
Systems urge the Commission to not use a narrowly focused rulemaking to
implement a sweeping change to point-to-point transmission service.
    41. Commenters offered suggestions about various other reforms as
well. Bonneville and Seattle argue that requiring transmission
providers to act as financial intermediaries in capacity reassignments
imposes an undue burden and complicates settlements. Powerex and
Bonneville raise concerns about transmission providers failing to
recalculate available transfer capability or available flowgate
capability in a timely manner, thereby inhibiting reassignments.
Bonneville recommends that a firm redirect request receive a credit for
any available flowgate capability the parent reservation has on the
flowgates impacted by the firm redirect request. TAPS suggests that the
Commission require the posting of transmission capacity available for
reassignment on the transmission provider's OASIS. Cargill recommends
that the reseller not remain responsible or liable to the transmission
provider for the reassigned capacity if it is a complete reassignment
(the full quantity of capacity for the remainder of the reservation) or
if the reseller performs a long-term assignment of the reservation for
any quantity up to the full amount of the capacity of the reservation.
    42. Seattle advocates a transition from comma separated data to
structured XML data in order to enhance data exchange and validation
between ``front-end'' and ``back-end systems'' used by transmission
customers and providers. It also advocates more meaningful forms of
transaction umbrella agreements, such as the WSPP agreement. EPSA
advocates consistent rules about posting the entities and market
participants that have active umbrella agreements with the transmission
provider. It says that such postings would give competitive suppliers
transparency about which market participants can purchase reassigned
capacity.
3. Commission Determination
    43. The Commission declines to implement the non-rate reforms
proposed in this proceeding at this time. Although some of these
proposals may have merit, we are unable to make a determination that
they are appropriate at this time based on the record in this
proceeding. With respect to the issues raised by Seattle and EPSA
regarding data structures, such issues are best addressed through the
standards development process of the North American Energy Standards
Board, which sets voluntary wholesale electric market standards
including those related to data exchanges and posting requirements.

III. Information Collection Statement

    44. The following collection of information contained in this
proposed rule is subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\47\ OMB's regulations require OMB to approve certain information
collection requirements imposed by agency rule.\48\
---------------------------------------------------------------------------

    \47\ 44 U.S.C. 3507(d) (2006).
    \48\ 5 CFR 1320.11 (2010).
---------------------------------------------------------------------------

    Burden Estimate: The public reporting and records retention burdens
for the reporting requirements and the records retention requirement
are as follows.\49\ The Commission solicited comments on the need for
this information and did not receive any specific comments regarding
its burden estimates. Where commenters raised concerns that specific
information collection requirements would be burdensome to implement,
the Commission has addressed those concerns elsewhere in the rule.
---------------------------------------------------------------------------

    \49\ These burden estimates apply only to this Final Rule and do
not reflect upon all of FERC-516 or FERC-717.

----------------------------------------------------------------------------------------------------------------
                                                 Number of        Number of        Hours per       Total annual
               Data collection                  respondents       responses         response          hours
----------------------------------------------------------------------------------------------------------------
Conforming tariff changes...................             132                1               10            1,320
----------------------------------------------------------------------------------------------------------------

    Cost To Comply: $150,480

1,320 hours @ $114 an hour (average cost of attorney ($200 per hour),
consultant ($150), technical ($80), and administrative support ($25))

    OMB's regulations require it to approve certain information
collection requirements imposed by an agency rule. The Commission is
submitting a copy of this Final Rule to OMB for their review approval
of the information collection requirements.
    Title: FERC-516, Electric Rate Schedules and Tariff Filings; FERC-
717 Standards for Business Practices and Communication Protocols for
Public Utilities.
    Action: Collection
    OMB Control Nos. 1902-0096 and 1902-0173
    Respondents: Transmission Providers
    Frequency of responses: One time.
    Necessity of the Information:
    45. The Federal Energy Regulatory Commission is adopting amendments
to the pro forma OATT to ensure that transmission services are provided
on a basis that is just, reasonable and not unduly discriminatory or
preferential. The purpose of this rulemaking is to strengthen the pro
forma OATT by encouraging more robust competition. The Final Rule
achieves this goal by removing the price cap previously imposed on
reassignments of transmission capacity.
    46. 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:
Michael Miller, Office of the Executive

Director, Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>, e-mail:
<EMAIL_ADDRESS>    47. For submitting comments concerning the collections of
information and the associated burden estimate(s), please send your
comments to the contact listed above and to the Office of Information
and Regulatory Affairs, Office of Management and Budget, 725 17th
Street, NW., Washington, DC 20503 [Attention: Desk Officer for the
Federal Energy Regulatory Commission, phone:<PHONE_NUMBER>, fax: (202)
395-7285. Due to security concerns, comments should be sent
electronically to the following e-mail address: oira_
<EMAIL_ADDRESS>Please reference the docket number of this
rulemaking in your submission.

IV. Environmental Analysis

    48. 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 Federal Power Act (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\
---------------------------------------------------------------------------

    \50\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (December 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \51\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act

    49. The Regulatory Flexibility Act of 1980 (RFA) \52\ generally
requires a description and analysis of Final Rules that will have
significant economic impact on a substantial number of small entities.
This Final Rule applies to public utilities that own, control, or
operate interstate transmission facilities, not to electric utilities
per se. The total number of public utilities that, absent waiver, would
have to modify their current OATTs by filing the revised pro forma OATT
is 176.\53\ Of these only six public utilities, or less than two
percent, dispose of four million MWh or less per year.\54\ The
Commission does not consider this a substantial number, and in any
event, these small entities may seek waiver of these requirements.\55\
Moreover, the criteria for waiver that would be applied under this
rulemaking for small entities is unchanged from that used to evaluate
requests for waiver under Order Nos. 888 and 889. Thus, small entities
who have received waiver of the requirements to have on file an open
access tariff or to operate an OASIS would be unaffected by the
requirements of this proposed rulemaking.
---------------------------------------------------------------------------

    \52\ 5 U.S.C. 601-612 (2006).
    \53\ The sources for this figure are FERC Form No. 1 and FERC
Form No. 1-F data.
    \54\ Id.
    \55\ The Regulatory Flexibility Act defines a ``small entity''
as ``one which is independently owned and operated and which is not
dominant in its field of operation.'' See 5 U.S.C. 601(3) and
601(6)(2000); 15 U.S.C. 632(a)(1) (2000). In Mid-Tex Elec. Coop. v.
FERC, 773 F.2d 327, 340-343 (DC Cir. 1985), the court accepted the
Commission's conclusion that, since virtually all of the public
utilities that it regulates do not fall within the meaning of the
term ``small entities'' as defined in the Regulatory Flexibility
Act, the Commission did not need to prepare a regulatory flexibility
analysis in connection with its proposed rule governing the
allocation of costs for construction work in progress (CWIP). The
CWIP rules applied to all public utilities. The revised pro forma
OATT will apply only to those public utilities that own, control or
operate interstate transmission facilities. These entities are a
subset of the group of public utilities found not to require
preparation of a regulatory flexibility analysis for the CWIP rule.
---------------------------------------------------------------------------

VI. Document Availability

    50. 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 FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.
    51. From FERC'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.
    52. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
VII. Effective Date and Congressional Notification

    53. These regulations shall become effective September 24, 2010.
Section 553(d) of the Administrative Procedure Act (APA) generally
requires a rule to be effective not less than 30 days after publication
in the Federal Register unless, inter alia, the rule relieves a
restriction or good cause is otherwise found to shorten the time
period.\56\ Section 553(b)(B) of the APA authorizes agencies to
dispense with certain procedures when the agency, for good cause, finds
that those procedures are ``impracticable, unnecessary, or contrary to
public interest.'' \57\ For the following reasons the Commission is
using the ``Good Cause'' exemption. This Final Rule must become
effective by 12 a.m. on October 1, 2010 or the price cap on
reassignments of electric transmission capacity will be reinstated.
Reinstating the price cap would impose a restriction on the rights of
transmission customers. Thus, this Final Rule relieves a restriction.
Furthermore, the Commission finds that good cause exists to make this
Final Rule effective immediately because allowing the price cap to be
reinstated temporarily could disrupt the efficient management of the
secondary market for electric transmission capacity and reduce
opportunities for further reduction of transmission congestion.
---------------------------------------------------------------------------

    \56\ 5 U.S.C. 553(d) (2006).
    \57\ 5 U.S.C. 553(b)(B) (2006).
---------------------------------------------------------------------------

    54. The Commission has determined, with the concurrence of the
Administrator of the Office of Information and Regulatory Affairs of
OMB, that this rule is not a ``major rule'' as defined in section 351
of the Small Business Regulatory Enforcement Fairness Act of 1996.

List of Subjects in 18 CFR Part 35

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

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

BILLING CODE 6717-01-P

[GRAPHIC] [TIFF OMITTED] TR24SE10.256

[GRAPHIC] [TIFF OMITTED] TR24SE10.257

[GRAPHIC] [TIFF OMITTED] TR24SE10.258

[FR Doc. 2010-23836 Filed 9-23-10; 8:45 am]
BILLING CODE 6717-01-C


[Federal Register Volume 81, Number 102 (Thursday, May 26, 2016)]
[Notices]
[Pages 33567-33568]
[FR Doc No: 2016-12382]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-77871; File No. SR-BATS-2015-100]

Self-Regulatory Organizations; BATS Exchange, Inc.; Notice of
Designation of a Longer Period for Commission Action on Proceedings To
Determine Whether To Approve or Disapprove a Proposed Rule Change, as
Modified by Amendments Nos. 1, 3, and 4 Thereto, To Amend BATS Rule
14.11(i) To Adopt Generic Listing Standards for Managed Fund Shares

May 20, 2016.
    On November 18, 2015, BATS Exchange, Inc. (now known as Bats BZX
Exchange, Inc., ``Exchange'') \1\ filed with the Securities and
Exchange Commission (``Commission''), pursuant to Section 19(b)(1) of
the Securities Exchange Act of 1934 (``Act'') \2\ and Rule 19b-4
thereunder,\3\ a proposed rule change to amend BATS Rule 14.11(i) by,
among other things, adopting generic listing standards for Managed Fund
Shares. The proposed rule change was published for comment in the
Federal Register on November 25, 2015.\4\ On January 4, 2016, the
Commission designated a longer period within which to approve the
proposed rule change, disapprove the proposed rule change, or institute
proceedings to determine whether to disapprove the proposed rule
change.\5\ On February 9, 2016, the Exchange filed Amendment No. 1 to
the proposed rule change,\6\ which replaced the originally filed
proposed rule change in its entirety.\7\ On February 11, 2016, the
Exchange both filed and withdrew Amendment No. 2 to the proposed rule
change. On February 11, 2016, the Exchange filed Amendment No. 3 to the
proposed rule change.\8\ On February 17, 2016, the Exchange filed
Amendment No. 4 to the proposed rule change.\9\ On February 22, 2016,
the Commission issued notice of filing of Amendment Nos. 1, 3, and 4 to
the proposed rule change and instituted proceedings under Section
19(b)(2)(B) of

the Act \10\ to determine whether to approve or disapprove the proposed
rule change, as modified by Amendment Nos. 1, 3, and 4 thereto.\11\ In
the Order Instituting Proceedings, the Commission solicited comments to
specified matters related to the proposal.\12\ The Commission has not
received any comments on the proposed rule change.
---------------------------------------------------------------------------

    \1\ In March 2016, BATS changed its name from ``BATS Exchange,
Inc.'' to ``Bats BZX Exchange, Inc.'' See Securities Act Release No.
77307 (Mar. 7, 2016), 81 FR 12996 (Mar. 11, 2016) (SR-BATS-2016-25)
(publishing notice of the name change to Bats BZX Exchange, Inc.).
    \2\ 15 U.S.C. 78s(b)(1).
    \3\ 17 CFR 240.19b-4.
    \4\ See Securities Exchange Act Release No. 76478 (Nov. 19,
2015), 80 FR 73841 (``Notice'').
    \5\ See Securities Exchange Act Release No. 76820, 81 FR 989
(Jan. 8, 2016). The Commission designated February 23, 2016 as the
date by which the Commission shall either approve or disapprove, or
institute proceedings to determine whether to disapprove, the
proposed rule change. See id.
    \6\ Amendment No. 1: (1) Clarifies the proposed treatment of
convertible securities under the proposed generic listing criteria;
(2) modifies the proposed criterion regarding American Depositary
Receipts (``ADRs'') to provide that no more than 10% of the equity
weight of the portfolio shall consist of non-exchange traded (rather
than unsponsored) ADRs; (3) modifies the proposed portfolio limit on
listed derivatives to require that at least 90% of the weight of
such holdings invested in futures, exchange-traded options, and
listed swaps shall, on both an initial and continuing basis, consist
of futures, options, and swaps for which the Exchange may obtain
information via the Intermarket Surveillance Group (``ISG'') from
other members or affiliates of the ISG or for which the principal
market is a market with which the Exchange has a comprehensive
surveillance sharing agreement (``CSSA''); (4) provides that a
portfolio's investments in listed and over-the-counter derivatives
will be calculated for purposes the proposed limits on such holdings
as the total absolute notional value of the derivatives; (5) makes
certain other conforming and clarifying changes. The amendments to
the proposed rule change are available at: http://www.sec.gov/comments/sr-bats-2015-100/bats2015100.shtml.
    \7\ See Amendment No. 1, supra note 6, at 4.
    \8\ Amendment No. 3 deletes from the proposal the following two
sentences: (1) ``Such limitation will not apply to listed swaps
because swaps are listed on swap execution facilities (``SEFs''),
the majority of which are not members of ISG.'' and (2) ``Such
limitation would not apply to listed swaps because swaps are listed
on SEFs, the majority of which are not members of ISG.'' Amendment
No. 3 also corrects an erroneous statement in Item 11 to indicate
that an Exhibit 4 was included in Amendment No. 1.
    \9\ Amendment No. 4 deletes from the proposal the following
sentence: ``Thus, if the limitation applied to swaps, there would
effectively be a cap of 10% of the portfolio invested in listed
swaps.'' Amendment No. 4 also amends two representations as follows
(added language in brackets): The Exchange or FINRA, on behalf of
the Exchange, will communicate as needed regarding trading in
Managed Fund Shares [and their underlying components] with other
markets that are members of the ISG, including all U.S. securities
exchanges and futures exchanges on which the components are traded[,
or with which the Exchange has in place a CSSA.] In addition, the
Exchange or FINRA[,] on behalf of the Exchange[,] may obtain
information regarding trading in Managed Fund Shares [and their
underlying components] from other markets that are members of the
ISG, including all U.S. securities exchanges and futures exchanges
on which the components are traded, or with which the Exchange has
in place a CSSA.''
    \10\ 15 U.S.C. 78s(b)(2)(B).
    \11\ See Securities Exchange Act Release No. 77202, 81 FR 9889
(Feb. 26, 2016) (``Order Instituting Proceedings''). Specifically,
the Commission instituted proceedings to allow for additional
analysis of the proposed rule change's consistency with Section
6(b)(5) of the Act, which requires, among other things, that the
rules of a national securities exchange be ``designed to prevent
fraudulent and manipulative acts and practices, to promote just and
equitable principles of trade,'' and ``to protect investors and the
public interest.'' See id., 81 FR at 9897.
    \12\ See id.
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    Section 19(b)(2) of the Act \13\ provides that, after initiating
disapproval proceedings, the Commission shall issue an order approving
or disapproving the proposed rule change not later than 180 days after
the date of publication of notice of the filing of the proposed rule
change. The Commission may, however, extend the period for issuing an
order approving or disapproving the proposed rule change by not more
than 60 days if the Commission determines that a longer period is
appropriate and publishes the reasons for such determination. The
proposed rule change was published for notice and comment in the
Federal Register on November 25, 2015.\14\ The 180th day after
publication of the notice of the filing of the proposed rule change in
the Federal Register is May 23, 2016.
---------------------------------------------------------------------------

    \13\ 15 U.S.C. 78s(b)(2).
    \14\ See supra note 4 and accompanying text.
---------------------------------------------------------------------------

    The Commission finds that it is appropriate to designate a longer
period within which to issue an order approving or disapproving the
proposed rule change so that it has sufficient time to consider the
proposed rule change, as modified by Amendment Nos. 1, 3, and 4
thereto.
    Accordingly, the Commission, pursuant to Section 19(b)(2) of the
Act,\15\ designates July 22, 2016, as the date by which the Commission
shall either approve or disapprove the proposed rule change, as
modified by Amendment Nos. 1, 3, and 4 thereto (File No. SR-BATS-2015-
100).
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    \15\ 15 U.S.C. 78s(b)(2).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\16\
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    \16\ 17 CFR 200.30-3(a)(57).
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Robert W. Errett,
Deputy Secretary.
[FR Doc. 2016-12382 Filed 5-25-16; 8:45 am]
 BILLING CODE 8011-01-P


[Federal Register Volume 78, Number 29 (Tuesday, February 12, 2013)]
[Notices]
[Pages 9908-9910]
[FR Doc No: 2013-03055]

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ENVIRONMENTAL PROTECTION AGENCY

[FRL-13-006 and 9779-7 ]

Notice of Availability of the Draft Issuance of the Small
Municipal Separate Storm Sewer System NPDES General Permit--New
Hampshire

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of Availability of Draft NPDES General Permits.

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SUMMARY: The Director of the Office of Ecosystem Protection,
Environmental Protection Agency-Region 1 (EPA), is issuing this Notice
of Availability of a draft National Pollutant Discharge Elimination
System (NPDES) general permit for discharges from small Municipal
Separate Storm Sewer Systems (MS4s) to certain waters of the State of
New Hampshire. The draft NPDES general permit establishes Notice of
Intent (NOI) requirements, prohibitions, and management practices for
stormwater discharges from small MS4s. A prior Notice of Availability
of a draft general permit was issued by EPA in December 2008. EPA has
substantially modified the draft general permit and is issuing a new
draft general permit pursuant to 40 CFR 124.6.

DATES: Comments must be received on or before April 15, 2013. The
general permit shall be effective on the date specified in the Federal
Register publication of the Notice of Availability of the final general
permit. The final general permit will expire five years from the
effective date.
    Public Hearing Information: EPA will hold a public hearing in
accordance with 40 CFR 124.12 and will provide interested parties with
the opportunity to provide written and/or oral comments for the
official draft permit record. The public hearing will be held March 14,
2013 from 2:00pm to 5:00pm at the following location: NH Department of
Environmental Services Pease Field Office--Pease International
Tradeport--222 International Drive, Suite 175--Portsmouth, New
Hampshire 03801.

ADDRESSES: Submit comments by one of the following methods:
     Email<EMAIL_ADDRESS>     Mail: Newton Tedder, US EPA--Region 1, 5 Post Office
Square--Suite 100, Mail Code--OEP06-4, Boston, MA 02109-3912.
    No facsimiles (faxes) will be accepted.
    The draft permit is based on an administrative record available for
public review at EPA-Region 1, Office of Ecosystem Protection, 5 Post
Office Square--Suite 100, Boston, Massachusetts 02109-3912. A
reasonable fee may be charged for copying requests. The fact sheet for
the draft permit sets forth principal facts and the significant
factual, legal, methodological and policy questions considered in the
development of the draft permit and is available upon request. A brief
summary is provided as SUPPLEMENTARY INFORMATION below.

FOR FURTHER INFORMATION CONTACT: Additional information concerning the
draft permit may be obtained between the hours of 9:00 a.m. and 5:00
p.m. Monday through Friday excluding legal holidays from: Newton
Tedder, Office of Ecosystem Protection, Environmental Protection
Agency, 5 Post Office Square--Suite 100, Boston, MA 02109-3912;
telephone:<PHONE_NUMBER>; email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Background of Proposed Permit

    EPA is proposing to reissue three draft NPDES general permits for
the discharge of stormwater from small MS4s to certain waters within
the State of New Hampshire. The three permits are:

NHR041000--Traditional cities and towns
NHR042000--Non-traditional state, federal, county and other publicly
owned systems
NHR043000--Non-traditional transportation systems
    While these are technically distinct permits, for convenience we
have grouped them together in a single document and have provided a
single fact sheet for all three of them, and this document refers to
the draft general ``permit'' in the singular. The draft general permit,
appendices, and fact sheet are available at: http://www.epa.gov/region1/npdes/stormwater.
    The conditions in the draft permit are established pursuant to
Clean Water Act (CWA) section 402(p)(3)(iii) to ensure that pollutant
discharges from small MS4s are reduced to the Maximum Extent
Practicable (MEP), protect water quality, and satisfy the appropriate
requirements of the CWA. The regulations at 40 CFR 122.26(b)(16) define
a small municipal separate storm sewer system as ``all separate storm
sewers that are:
    (1) Owned or operated by the United States, a State, city, town,
borough, county, parish, district, association, or other public body
(created by or pursuant to State law) having jurisdiction over disposal
of sewage, industrial wastes, stormwater, or other wastes, including
special districts under State law such as a sewer district, flood
control district or drainage district, or similar entity, or an Indian
tribe or an authorized Indian tribal organization, or a designated and
approved management agency under section 208 of the CWA that discharges
to waters of the United States.
    (2) Not defined as `large' or `medium' municipal separate storm
sewer systems pursuant to paragraphs (b)(4) or (b)(7) or designated
under paragraph (a)(1)(v) of this section [40 CFR 122.26].
    (3) This term includes systems similar to separate storm sewer
systems in municipalities such as systems at military bases, large
hospital or prison complexes, and highways or other thoroughfares. The
term does not include separate storm sewers in very discrete areas,
such as individual buildings.''
    The draft general permit sets forth the requirements for the small
MS4 to ``reduce the discharge of pollutants to the maximum extent
practicable, including management practices, control techniques, and
system, design

and engineering methods'' (See section 402(p)(3)(B)(iii) of the CWA).
MEP is the statutory standard that establishes the level of pollutant
reductions that MS4 operators must achieve. EPA believes that
implementation of best management practices (BMPs) designed to control
storm water runoff from the MS4 is generally the most appropriate
approach for reducing pollutants to satisfy the MEP standard. Pursuant
to 40 CFR 122.44(k), the draft permit contains BMPs, including
development and implementation of a comprehensive stormwater management
program (SWMP) as the mechanism to achieve the required pollutant
reductions.
    Section 402(p)(3)(B)(iii) of CWA also authorizes EPA to include in
an MS4 permit ``such other provisions as [EPA] determine[s] appropriate
for control of [hellip] pollutants.'' This provision forms a basis for
imposing water quality-based effluent limitations (WQBELs), consistent
with the authority in Section 301(b)(1)(C) of the CWA. See Defenders of
Wildlife v. Browner, 191 F.3d 1159, 1166-67 (9th Cir. 1999); 64 FR
68722, 68753, 68788 (Dec. 8, 1999). Accordingly, the draft permit
contains the water quality-based effluent limitations, expressed in
terms of BMPs, which EPA has determined are necessary and appropriate
under the CWA.
    EPA issued a final general permit to address stormwater discharges
from small MS4s on May 1, 2003. The 2003 general permit required small
MS4s to develop and implement a SWMP designed to control pollutants to
the maximum extent practicable and protect water quality. This draft
permit builds on the requirements of the previous general permit.
    EPA views the MEP standard in the CWA as an iterative process. MEP
should continually adapt to current conditions and BMP effectiveness.
Compliance with the requirements of this general permit will meet the
MEP standard. The iterative process of MEP consists of a municipality
developing a program consistent with specific permit requirements,
implementing the program, evaluating the effectiveness of the BMPs
included as part of the program, then revising those parts of the
program that are not effective at controlling pollutants, then
implementing the revisions, and evaluating again. The changes contained
in the draft general permit reflect the iterative process of MEP.
Accordingly, the draft general permit contains more specific tasks and
details than the 2003 general permit.
    EPA initially proposed a draft permit in December 2008. Based on
comments and information gathered while developing responses, EPA has
modified the initial draft general permit and is issuing a new draft
permit pursuant to 40 CFR 124.6. The changes to the draft general
permit include, but are not limited to: provisions addressing
discharges to impaired waters without a Total Maximum Daily Load,
including requirements related to discharges to the Great Bay watershed
and chlorides-impaired waters; provisions related to Total Maximum
Daily Loads that have been approved since December 2008; illicit
discharge detection elimination and monitoring provisions. The draft
general permit has also been revised to provide for coverage to MS4s
that became subject to NPDES permit requirements with the issuance of
updated urbanized area delineations based on the results of the 2010
Census. The 2008 draft general permit also addressed certain areas
outside of New Hampshire. This revised draft general permit applies
only to New Hampshire
    EPA is specifically seeking public comment on the specific permit
Parts listed above, but will accept comment on all permit provisions.
Please note that the new Draft Permit completely supersedes the 2008
draft permit, and EPA is providing an entirely new comment period under
40 CFR 124.10. Consequently, all persons who believe any condition of
the new Draft Permit is inappropriate must raise all reasonably
ascertainable issues and submit all reasonably available arguments
supporting their position during this public comment period, which
includes the public hearing.

Summary of Permit Conditions

Obtaining Authorization

    In order for a small MS4 to obtain authorization to discharge, it
must submit a complete and accurate NOI containing the information in
Appendix E of the draft general permit. The NOI must be submitted
within 90 days of the effective date of the final permit. The effective
date of the final permit will be specified in the Federal Register
publication of the Notice of Availability of the final permit. A small
MS4 must meet the eligibility requirements of the general permit found
in Part 1.2 and Part 1.9 prior to submission of its NOI. A small MS4
will be authorized to discharge under the permit upon receipt of
written notice from EPA following a public notice of the submitted NOI.
EPA will authorize the discharge, request additional information, or
require the small MS4 to apply for an alternative permit or an
individual permit.

Water Quality Based Effluent Limitations

    The draft permit includes provisions to ensure that discharges do
not cause or contribute to exceedances of water quality standards. The
provisions in Parts 2.1 and 2.2 of the general permit constitute the
water quality-based effluent limitations of the permit. The purpose of
these parts of the permit is to establish the board inclusion of water
quality-based effluent limitations for those discharges requiring
additional controls in order to achieve water quality standards and
other water quality related objectives, consistent with 40 CFR
122.44(d). The non-numeric effluent limitation requirements of this
permit are expressed in the form of control measures and BMPs (see Part
2.3 of the general permit).

Non-Numeric Effluent Limitations

    When EPA has not promulgated effluent limitations for a category of
discharges, or if an operator is discharging a pollutant not covered by
an effluent limitation guideline, effluent limitations may be based on
the best professional judgment (BPJ) of the agency or permit writer.
The BPJ limits in the general permit are in the form of non-numeric
control measures, commonly referred to as best management practices
(BMPs). EPA has interpreted the CWA to allow BMPs to take the place of
numeric effluent limitations under certain circumstances. 40 CFR
122.44(k) provides that permits may include BMPs to control or abate
the discharge of pollutants when: ``(1) [a]uthorized under section
304(e) of the CWA for the control of toxic pollutants and hazardous
substances form ancillary industrial activities; (2) [a]uthorized under
section 402(p) of the CWA for the control of stormwater discharges; (3)
[n]umeric effluent limitations are infeasible; or (4) [t]he practices
are reasonable to achieve effluent limitations and standards or to
carry out the purposes and intent of the CWA.'' The permit regulates
stormwater discharges using BMPs. Due to the variability associated
with stormwater, EPA believes the use of BMPs is the most appropriate
method to regulate discharges of stormwater from municipal systems in
accordance with the above referenced regulation.
    The small MS4s are required to implement a SWMP that includes the
following control measures: public education and outreach; public
participation; illicit discharge detection and elimination;
construction stormwater management; stormwater

management in new development and redevelopment; and good housekeeping
in municipal operations. Implementation of the SWMP involves the
identification of BMPs and measurable goals for BMPs. The draft permit
identifies an objective for each control measure.
    EPA is soliciting public comments on the issues discussed in this
notice or on other relevant matters. The public comment process and the
public hearing will be conducted in accordance with 40 CFR 124, EPA's
Procedures for Decisionmaking. EPA will consider and respond to all
significant comments before taking final action. All persons, including
applicants, who believe any condition of the draft permit is
inappropriate must raise all reasonably ascertainable issues and submit
all reasonably available arguments supporting their position by the
close of the public comment period, either by submitting written
comments to the EPA New England Regional Office listed in the ADDRESSES
section of this Federal Register, or by submitting written or oral
comments at the public hearing. Any supporting materials which are
submitted shall be included in full and may not be incorporated by
reference, unless they are already part of the administrative record in
this proceeding, or consist of State or Federal statutes and
regulations, EPA documents of general applicability, or other generally
available reference materials.

Other Legal Requirements

A. Endangered Species Act
    The provisions related to the ESA have not been changed from those
in the 2008 draft permit. However, the Atlantic Sturgeon (Acipenser
oxyrinchus) has been added to the list of species of concern for this
draft permit. EPA requested concurrence from the appropriate Federal
services (U.S. Fish and Wildlife Service and National Marine Fisheries
Service) in connection with the 2008 draft and has renewed this request
for the new Draft Permit.
B. Executive Order 12866
    EPA has determined that this general permit is not a ``significant
regulatory action'' under the terms of Executive Order 12866 and is
therefore not subject to OMB review.
C. Paperwork Reduction Act
    The information collection requirements of this permit were
previously approved by the Office of Management and Budget (OMB) under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.,
and assigned OMB control number 2040-0004.
D. Regulatory Flexibility Act
    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601 et seq.,
requires that EPA prepare a regulatory flexibility analysis for rules
subject to the requirements of 5 U.S.C. 553(b) that have a significant
impact on a substantial number of small entities. However, general
NPDES permits are not ``rules'' subject to the requirements of 5 U.S.C.
553(b) and are therefore not subject to the RFA.
E. Unfunded Mandates Reform Act
    Section 201 of the Unfunded Mandates Reform Act (UMRA), Public Law
104-4, generally requires Federal agencies to assess the effects of
their ``regulatory actions'' (defined to be the same as ``rules''
subject to the RFA) on tribal, state, and local governments and the
private sector. However, general NPDES permits are not ``rules''
subject to the requirements of 5 U.S.C. 553(b) and are therefore not
subject to the RFA or the UMRA.

    Authority: This action is being taken under the Clean Water Act,
33 U.S.C. 1251 et seq.

    Dated: February 5, 2013.
H. Curtis Spalding,
Regional Administrator, Region 1.
[FR Doc. 2013-03055 Filed 2-11-13; 8:45 am]
BILLING CODE 6560-50-P