[Federal Register: March 24, 2010 (Volume 75, Number 56)]
[Proposed Rules]
[Page 14103-14111]
[DOCID:fr24mr10-16]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM09-15-000]

Version One Regional Reliability Standard for Resource and Demand
Balancing

March 18, 2010.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: Pursuant to section 215 of the Federal Power Act, the
Commission proposes to remand a revised regional Reliability Standard
developed by the Western Electricity Coordinating Council and approved
by the North American Electric Reliability Corporation, which the
Commission has certified as the Electric Reliability Organization
responsible for developing and enforcing mandatory Reliability
Standards. The revised regional Reliability Standard, designated by
WECC as BAL-002-WECC-1, would set revised Contingency Reserve
requirements meant to maintain scheduled frequency and avoid loss of
firm load following transmission or generation contingencies.

DATES: Comments are due May 24, 2010.

ADDRESSES: Comments and reply comments may be filed electronically via
the eFiling link on the Commission's Web site at http://www.ferc.gov.
Documents created electronically using word processing software should
be filed in the native application or print-to-PDF format and not in a
scanned format. This will enhance document retrieval for both the
Commission and the public. The Commission accepts most standard word
processing formats and commenters may attach additional files with
supporting information in certain other file formats. Attachments that
exist only in paper form may be scanned. Commenters filing
electronically should not make a paper filing. Service of rulemaking
comments is not required. Commenters that are not able to file
electronically must send an original and 14 copies of their comments
to: Federal Energy Regulatory Commission, Office of the Secretary, 888
First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:
Cory Lankford (Legal Information), Office of General Counsel, Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426,<PHONE_NUMBER>.
Nick Henery (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.
Scott Sells (Technical Information), Office of Electric Reliability,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Notice of Proposed Rulemaking

March 18, 2010.

    1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the
Commission proposes to remand a revised regional Reliability Standard
developed by the Western Electricity Coordinating Council (WECC) and
approved by the North American Electric Reliability Corporation (NERC),
which the Commission has certified as the Electric Reliability
Organization (ERO) responsible for developing and enforcing mandatory
Reliability Standards.\2\ The revised regional Reliability Standard,
designated by WECC as BAL-002-WECC-1 (Contingency Reserves),\3\ is
meant to ensure that adequate generating capacity is available at all
times to maintain scheduled frequency, and avoid loss of firm load
following transmission or generation contingencies. As discussed below,
the Commission believes that the proposed regional Reliability Standard
does not meet the statutory criteria for

approval that it be just, reasonable, not unduly discriminatory or
preferential, and in the public interest.\4\
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    \1\ 16 U.S.C. 824o (2006).
    \2\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g & compliance, 117 FERC ] 61,126 (2006), aff'd
sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
    \3\ NERC designates the version number of a Reliability Standard
as the last digit of the Reliability Standard number. Therefore,
original Reliability Standards end with ``-0'' and modified version
one Reliability Standards end with ``-1.''
    \4\ 16 U.S.C. 824o(d)(2).
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    2. The Commission proposes to remand the proposed regional
Reliability Standard based on concerns that it not only fails to
support the adoption of less stringent requirements than those in the
currently effective WECC regional standard that it would replace, but
may also in some respects be less stringent than the corresponding NERC
continent-wide Reliability Standard pertaining to contingency reserves.
Of particular concern with respect to whether the proposed standard is
less stringent than the continent-wide Reliability Standard is the
provision of proposed BAL-002-WECC-1 that would permit a balancing
authority, when an emergency is declared, to count ``Load, other than
Interruptible Load'' as contingency reserve. This provision allows a
balancing authority to activate load shedding when a single contingency
occurs instead of procuring and utilizing generating or demand response
resources held in reserve for contingencies to balance the Bulk-Power
System. We believe that such operation, which is not permitted in
either the current regional Reliability Standard or the NERC continent-
wide Reliability Standard, is detrimental to reliability.
    3. Further, we are concerned that proposed BAL-002-WECC-1,
Requirement R1, reformulates the minimum contingency reserve
requirement without providing adequate support that the new requirement
is sufficiently stringent to meet the requirements of NERC's continent-
wide Disturbance Control Standard, BAL-002-0. While NERC in its
transmittal letter provides several justifications for the proposed
modification to the minimum contingency reserve requirement, it also
states that WECC relied on just eight hours of operating data in its
analysis to support its proposal to make a modest reduction in the
amount of contingency reserve under the proposed Reliability Standard.
We believe that NERC and WECC should provide additional data and
analysis to support the proposed reformulation. Accordingly, we propose
to remand WECC regional Reliability Standard BAL-002-WECC-1.

I. Background

A. Mandatory Reliability Standards

    4. Section 215 of the FPA requires a Commission-certified ERO to
develop mandatory and enforceable Reliability Standards, which are
subject to Commission review and approval. Once approved, the
Reliability Standards may be enforced by the ERO, subject to Commission
oversight, or by the Commission independently.\5\
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    \5\ 16 U.S.C. 824o(e)(3).
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    5. Reliability Standards that the ERO proposes to the Commission
may include Reliability Standards that are proposed to the ERO by a
Regional Entity.\6\ A Regional Entity is an entity that has been
approved by the Commission to enforce Reliability Standards under
delegated authority from the ERO.\7\ When the ERO reviews a regional
Reliability Standard that would be applicable on an interconnection-
wide basis and that has been proposed by a Regional Entity organized on
an interconnection-wide basis, the ERO must rebuttably presume that the
regional Reliability Standard is just, reasonable, not unduly
discriminatory or preferential, and in the public interest.\8\ In turn,
the Commission must give ``due weight'' to the technical expertise of
the ERO and of a Regional Entity organized on an interconnection-wide
basis.\9\
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    \6\ 16 U.S.C. 824o(e)(4).
    \7\ 16 U.S.C. 824o(a)(7) and (e)(4).
    \8\ 18 CFR 39.5 (2009).
    \9\ 16 U.S.C. 824o(d)(2).
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    6. In Order No. 672, the Commission urged uniformity of Reliability
Standards, but recognized a potential need for regional
differences.\10\ Accordingly, the Commission stated that:
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    \10\ Rules Concerning Certification of the Electric Reliability
Organization; Procedures for the Establishment, Approval, and
Enforcement of Electric Reliability Standards, Order No. 672, 71 FR
8662 (Feb. 17, 2006), FERC Stats. & Regs. ] 31,204, at P 290 (2006);
order on reh'g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC
Stats. & Regs. ] 31,212 (2006).

    As a general matter, we will accept the following two types of
regional differences, provided they are otherwise just, reasonable,
not unduly discriminatory or preferential and in the public
interest, as required under the statute: (1) A regional difference
that is more stringent than the continent-wide Reliability Standard,
including a regional difference that addresses matters that the
continent-wide Reliability Standard does not; and (2) a regional
Reliability Standard that is necessitated by a physical difference
in the Bulk-Power System.\11\
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    \11\ Id. P 291.
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B. Western Electricity Coordinating Council

    7. On April 19, 2007, the Commission accepted delegation agreements
between NERC and each of eight Regional Entities.\12\ In its order, the
Commission accepted WECC as a Regional Entity organized on an
Interconnection-wide basis. As a Regional Entity, WECC oversees
transmission system reliability in the Western Interconnection. The
WECC region encompasses nearly 1.8 million square miles, including 14
western U.S. states, the Canadian provinces of Alberta and British
Columbia, and the northern portion of Baja California in Mexico.
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    \12\ North American Electric Reliability Corp., 119 FERC ]
61,060, at P 432 (2007).
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    8. In June 2007, the Commission approved eight regional Reliability
Standards for WECC including the currently effective regional
Reliability Standard for operating reserves, WECC-BAL-STD-002-0.\13\
The Commission found that the current regional Reliability Standard was
more stringent than the corresponding NERC Reliability Standard, BAL-
002-0, since WECC required a more stringent minimum reserve requirement
than the continent-wide requirement.\14\ Moreover, the Commission found
that WECC's requirement to restore contingency reserves within 60
minutes was more stringent than the 90 minute restoration period as set
forth in NERC's BAL-002-0.\15\
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    \13\ North American Electric Reliability Corp., 119 FERC ]
61,260, at P 53 (2007).
    \14\ Id.
    \15\ Id.
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    9. The Commission directed WECC to develop certain minor
modifications to WECC-BAL-STD-002-0, as identified by NERC in its
filing letter for the current standard.\16\ For example, the Commission
determined that: (1) Regional definitions should conform to definitions
set forth in the NERC Glossary of Terms Used in Reliability Standards
(NERC Glossary), unless a specific deviation has been justified; and,
(2) documents that are referenced in the Reliability Standard should be
attached to the Reliability Standard. The Commission also found that it
is important that regional Reliability Standards and NERC Reliability
Standards achieve a reasonable level of consistency in their structure
so that there is a common understanding of the elements. The Commission
also directed WECC to address stakeholder concerns regarding
ambiguities in the terms ``load responsibility'' and ``firm
transaction.'' \17\
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    \16\ Id. P 55.
    \17\ Id. P 56.
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II. WECC Regional Reliability Standard BAL-002-WECC-1

    10. On March 25, 2009, NERC submitted a petition (NERC Petition) to
the Commission seeking approval of

BAL-002-WECC-1 \18\ and requesting the concurrent retirement of BAL-
STD-002-0.\19\ In that March petition, NERC states that the proposed
regional Reliability Standard was approved by the NERC Board of
Trustees at its October 29, 2008 meeting. NERC also requests an
effective date for the proposed regional Reliability Standard of 90
calendar days after receipt of applicable regulatory approval.
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    \18\ See 18 CFR 39.5(a) (requiring the ERO to submit regional
Reliability Standards on behalf of a Regional Entity).
    \19\ The proposed regional Reliability Standard is not attached
to the NOPR. It is, however, available on the Commission's eLibrary
document retrieval system in Docket No. RM09-15-000 and is on the
ERO's Web site, available at: http://www.nerc.com.
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    11. The proposed regional Reliability Standard contains three main
provisions. Requirement R1 provides that each reserve sharing group
\20\ or balancing authority must maintain a minimum contingency reserve
that is the greater of (1) an amount of reserve equal to the loss of
the most severe single contingency; or (2) an amount of reserve equal
to the sum of three percent of the load and three percent of net
generation. Requirement R2 states that each reserve sharing group or
balancing authority must maintain at least half of the contingency
reserve as spinning reserve. Requirement R3 identifies acceptable types
of reserve to satisfy Requirement R1:
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    \20\ A ``reserve sharing group'' is a group whose members
consist of two or more balancing authorities that collectively
maintain, allocate, and supply operating reserves required for each
balancing authority's use in recovering from contingencies within
the group. See NERC Glossary, available at: http://www.nerc.com/
docs/standards/rs/Glossary_2009April20.pdf.

R3.1. Spinning Reserve;
R3.2. Interruptible Load;
R3.3. Interchange Transactions designated by the source Balancing
Authority as non-spinning contingency reserve;
R3.4. Reserve held by the other entities by agreement that is
deliverable on Firm Transmission Service;
R3.5. An amount of off-line generation which can be synchronized and
generating; or
R.3.6. Load, other than Interruptible Load, once the Reliability
Coordinator has declared a capacity or energy emergency.
    In addition, Measure M1 provides that a reserve sharing group or
balancing authority must have documentation that it maintained 100
percent of required contingency reserve levels ``except within the
first 105 minutes (15 minute Disturbance Recovery Period, plus 90
minute Contingency Reserve Restoration Period) following an event
requiring the activation of Contingency Reserves.''

III. Discussion

    12. As discussed below, proposed regional Reliability Standard BAL-
002-WECC-1 does not appear to satisfy the statutory criteria for
approval. The Commission therefore proposes to remand BAL-002-WECC-1 to
the Regional Entity with instructions for development of suitable
modifications. The Commission also discusses additional concerns with
the proposed regional Reliability Standard, and proposes that the
Regional Entity address these concerns on remand.

A. Calculation of Minimum Contingency Reserves

    13. NERC's Disturbance Control Standard, continent-wide Reliability
Standard BAL-002-0, requires each balancing authority or reserve
sharing group, at a minimum, to maintain at least enough contingency
reserve to cover the most severe single contingency. Similarly,
requirement WR1(a)(ii) of WECC's current WECC-BAL-STD-002-0 requires
balancing authorities to maintain a contingency reserve of spinning and
nonspinning reserves (at least half of which must be spinning),
sufficient to meet the NERC Disturbance Control Standard, BAL-002-0,
equal to the greater of: (1) the loss of generating capacity due to
forced outages of generation or transmission equipment that would
result from the most severe single contingency; or (2) the sum of five
percent of load responsibility served by hydro generation and seven
percent of the load responsibility served by thermal generation. In
approving the regional BAL-STD-002-0 Reliability Standard, the
Commission noted that the regional Reliability Standard is more
stringent than the NERC Reliability Standard, BAL-002-0, because WECC
requires a more stringent minimum reserve requirement than the
continent-wide requirement.
WECC and NERC Proposal
    14. As proposed, Requirement R1 of BAL-002-WECC-1 would require
each reserve sharing group or balancing authority that is not a member
of a reserve sharing group to maintain a minimum contingency reserve.
NERC contends that the proposed minimum contingency reserve amount is
more stringent than that required by the continent-wide Reliability
Standard.\21\ NERC explains that, whereas Requirement R3.1 of BAL-002-0
requires that each balancing authority or reserve sharing group carry,
at a minimum, at least enough contingency reserve to cover the most
severe single contingency, proposed Requirement R1.1 of BAL-002-WECC-1
requires that each balancing authority or reserve sharing group
maintain, as a minimum, contingency reserves equal to the loss of the
most severe single contingency or an amount of reserve equal to the sum
of three percent of the load (generation minus station service minus
net actual interchange) and three percent of net generation (generation
minus station service).\22\
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    \21\ NERC Petition at 9.
    \22\ Id. at 14.
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    15. NERC states that the proposed requirements for minimum
contingency reserves provide a comparable level of contingency reserves
to those contained in the currently approved regional Reliability
Standard. NERC explains that, based on operational experience, the
requirements have been revised to remove what it considers to be
ambiguous terms, such as ``load responsibility,'' and separate market
transactions from the determination of required reserves that exist
using the methodology in the current Reliability Standard.\23\ In
support of the revised minimum contingency reserve calculations, NERC
states that, based on technical studies covering a total eight hours
from the four operating seasons (summer, fall, winter and spring, both
on and off-peak), the drafting team determined that the sum of 3
percent of load and 3 percent of net generation level was appropriate
to approximate the same level of contingency reserves as the existing
approved standard provides throughout the year.
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    \23\ Id. at 16.
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    16. NERC contends, however, that, due to ambiguities that exist
using the current methodology, historical information necessary to
calculate the required contingency reserve levels under the proposed
methodology is not readily available from collected data. NERC explains
that this situation exists because the calculations are based on the
term ``load responsibility'' as it is used in the current regional
Reliability Standard and not on load itself. Thus, NERC comments, WECC
does not have additional data available in order to compare the
contingency reserve levels required under the existing methodology with
the prospective reserve levels under the proposed methodology. NERC
states that requiring an additional survey of the applicable entities
would place an undue burden on those entities to compile and submit the
data, and on the drafting team to evaluate and verify the data,
considering the amount of time that has passed since the proposed
regional Reliability Standard was approved by the WECC Board of
Directors.

    17. NERC acknowledges that even the data collected illustrates that
the proposed methodology for calculating minimum contingency reserves
results in a slight reduction in required total reserves in the
interconnection for each of the eight hours assessed as compared to the
total reserves required under the current methodology.\24\ In fact, the
eight hours of data shows an overall decrease in required reserves
under the proposed methodology of approximately 350 MWs (from
approximately 10,850 MWs to 10,500 MWs) on high load days. NERC argues,
however, that, under the currently effective regional Reliability
Standard, the potential exists for the total reserves required in the
Western Interconnection to be reduced if firm transactions are
purchased from balancing authorities or from reserve sharing groups
whose reserve requirements are determined by the most severe single
contingency.\25\
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    \24\ Id. at 15.
    \25\ Id.
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    18. NERC also contends that industry will benefit from the improved
clarity in the proposed regional Reliability Standard.\26\ NERC states
that the ambiguity associated with the term ``load responsibility,'' as
it is used in the current regional Reliability Standard, results in
confusion regarding the location and amount of the reserves being
carried in the interconnection. NERC explains that:
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    \26\ Id. at 15-16. In its order approving the current regional
Reliability Standard, the Commission directed WECC, in preparing a
revised regional Reliability Standard, to resolve concerns raised by
stakeholders that certain terms, including ``load responsibility,''
were ambiguous. North American Electric Reliability Corp., 119 FERC
] 61,260 at P 56.

[t]he identification of the entities responsible for providing
reserves may be lost as purchases are bundled and remarketed. With
regard to the ability to audit applicable entities for compliance to
the existing BAL-STD-002-0 relative to the proposed BAL-002-WECC-1
standard, WECC has been able to audit the current standard with a
reasonable level of consistency; however, the industry would benefit
from greater clarity. The interpretation of the term ``load
responsibility,'' which is used to determine the amount of reserves
required has been problematic for WECC, particularly because FERC
Order No. 888 expanded the types of commercial products traded in
the electric power industry. The influence of routine commercial
transactions and terms in the existing regional Reliability Standard
has introduced the possibility of varying interpretations for the
term ``load responsibility'' and a degree of uncertainty as to the
responsibility for reserves, resulting in challenges when evaluating
compliance.\27\
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    \27\ NERC Petition at 16.

    19. In addition, NERC states that the existing regional Reliability
Standard considers load served by hydro and thermal generation but does
not explicitly require contingency reserves for other types of
generation such as wind, solar or other renewable resources. NERC
concludes that the proposed regional Reliability Standard adds clarity
by explicitly requiring reserves for renewable resources.\28\ NERC
argues further that even though the use of the proposed method for
calculating minimum contingency reserves results in a reduction in
total reserves required in the interconnection, such impact is
negligible when compared to the uncertainty in the actual amount of
reserves being carried in the interconnection under the existing
regional Reliability Standard and the potential shortfall in reserves
existing as a result of new technologies not currently addressed in the
existing regional Reliability Standard.
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    \28\ NERC Petition at 16.
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NOPR Proposal
    20. The Commission proposes to find that the eight hours of data
provided by WECC is insufficient to demonstrate that the proposed
minimum contingency reserve requirements are sufficiently stringent to
ensure that entities within the Western Interconnection will meet the
requirements of NERC's continent-wide Disturbance Control Standard,
BAL-002-0. In the regional Reliability Standard development process,
several commenters raised similar concerns about the lack of technical
justification for the proposed method for calculating minimum
contingency reserve levels.\29\ The Commission believes that NERC did
not adequately respond to these concerns.
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    \29\ See, e.g., NERC, Petition at Exhibit C (Record of
Development of Proposed Reliability Standard), Avista, October 30,
2007 Comments at 21; Alberta Electric System Operator, October 30,
2007 Comments at 23; Bonneville Power Administration, October 30,
2007 Comments at 28; Grant County PUD, October 30, 2007 Comments at
16-17; PacifiCorp Commercial and Trading, October 30, 2007 Comments
at 33-34; NorthWestern Energy, October 30, 2007 Comments at 36;
Northwest Power Pool Reserve Sharing Group, October 30, 2007
Comments at 8; PacifiCorp, October 30, 2007 Comments at 34; Pacific
Gas & Electric, January 2, 2008 Comments at 4; Portland General
Electric Merchant, October 30, 2007 Comments at 25.
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    21. In its March 2007 petition proposing the currently effective
regional Reliability Standard, NERC explained that WECC-BAL-STD-002-0
and the other seven regional Reliability Standards were WECC's
translation of existing WECC criteria that the WECC Operating Committee
and Western Interconnection Regional Advisory Body both concluded to be
critical to maintaining reliability within the Western
Interconnection.\30\ NERC stated that all of these regional Reliability
Standards were ``well vetted, approved, tested, and proven effective in
monitoring and enforcing critical reliability elements in the Western
Interconnection'' \31\ and were developed in response to the 1996
blackouts. NERC also stated that, in developing WECC-BAL-STD-002-0 and
the other seven regional Reliability Standards, the ``WECC Operating
Committee undertook a comprehensive review of all WECC criteria,
policies, and guidelines in an effort to identify all unique * * *
criteria it believed critical to the reliability of the Western
Interconnection'' \32\ and concluded that these eight regional
Reliability Standards were of the ``highest priority.'' \33\ These
statements indicate that these eight regional Reliability Standards
were necessary to maintain reliability in the Western Interconnection.
Our review of the provisions relating to the calculation of minimum
contingency reserve requirements in the proposed Reliability Standard
indicates that they may be less stringent than the currently-effective
regional Reliability Standard, WECC-BAL-STD-002-0, and may also be less
stringent than the currently-effective continent-wide Reliability
Standard. NERC and WECC have not provided an adequate explanation or
supporting studies to resolve these concerns.
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    \30\ NERC, March 26, 2007 Petition Proposing Current Regional
Reliability Standard, Docket No. RR07-11-000, at 4.
    \31\ Id.
    \32\ Id.
    \33\ Id.
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    22. NERC admits that the eight hours of data illustrates that the
proposed methodology for calculating contingency reserves results in a
reduction of total reserves required in the Western Interconnection for
each of the eight hours assessed when compared with the methodology in
the current regional Reliability Standard. Neither NERC nor WECC has
provided sufficient evidence that the proposed regional Reliability
Standard provides adequate requirements to ensure that entities within
WECC will continue to satisfy the continent-wide disturbance control
standard and will not cause frequency-related instability, uncontrolled
separation or cascading outages. Moreover, the evidence provided is
insufficient to demonstrate that the proposed regional Reliability
Standard is more stringent than the

corresponding NERC Reliability Standard.
    23. Although the proposed Reliability Standard offers some added
clarity by eliminating reference to the term ``load responsibility''
and including renewables in the calculation of contingency reserves,
the Commission proposes to find that NERC and WECC have not provided
sufficient technical justification to support the proposed revised
method for calculating contingency reserves. Thus, we propose to remand
BAL-002-WECC-1 so that WECC can develop additional support and make
modifications as appropriate for a future proposal, consistent with the
above discussion. In preparing its response, NERC could provide a
variety of technical justifications. For example, NERC could provide
statistically significant data, supported by a sampling representative
of all balancing authorities and expected operating conditions (such as
each season, peak periods, off-peak periods and reportable
disturbances), to cover the range of operating conditions that must be
addressed to ensure that the proposed amount of contingency reserve
that are on-line and deliverable will exceed the performance under the
NERC Reliability Standards, taking into account the specific electrical
characteristics and topology of the Western Interconnection.
Alternatively, NERC could provide model simulations demonstrating that
the proposed amount of contingency reserves are on-line and deliverable
for all expected operating conditions and will exceed the performance
required under the NERC Reliability Standards, taking into account the
specific electrical characteristics and topology of the Western
Interconnection.
    24. The Commission recognizes that NERC has suggested that
confusion exists with regard to the term ``load responsibility.''
However, the Commission believes that any confusion concerning the term
``load responsibility'' has been addressed by WECC and therefore does
not have a reliability impact. WECC has defined the term ``load
responsibility'', although not in its regional Reliability
Standard.\34\ Under WECC's definition for ``load responsibility'', a
balancing authority's ``load responsibility'', for maintaining adequate
contingency reserves, is determined by a balancing authority's firm
load (net generation minus net actual interchange); minus loads
contractually interruptible within 10 minutes; minus imports where the
source balancing authority is responsible for contingency reserves;
plus exports where the exporting balancing authority is responsible for
contingency reserves. WECC's procedures for load responsibility require
that the entities (purchasing selling entity or load serving entity)
that are party to the import or export are required to identify the
transaction to the balancing authority using the e-tagging
prescheduling tool and identify the associated contingency reserves.
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    \34\ WECC's interpretation of ``Load Responsibility,'' which was
approved by the WECC Board of Directors September 7, 2007, places
the responsibility on the balancing authorities to determine the
amount of and assure that adequate contingency reserves are
provided. See WECC Interpretation of Load Responsibility (Sept. 7,
2007), available at: http://www.wecc.biz/Standards/Interpretations/
Interpretation%20of%20Load%20Responsibility.pdf. Likewise, the
current regional Reliability Standard places the responsibility on
the balancing authorities to determine the amount of and assure that
adequate contingency reserves are provided.
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B. Use of Firm Load To Meet Contingency Reserve Requirement

    25. Requirement R1 of NERC's continent-wide Reliability Standard
BAL-002-0, allows balancing authorities to supply their contingency
reserves from generation, controllable load resources, or coordinated
adjustments to interchange schedules.\35\ Similarly, WECC's current
WECC-BAL-STD-002-0 identifies acceptable types of non-spinning reserve
and, among those identified, ``interruptible load.'' \36\
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    \35\ Reliability Standard BAL-002-0, Requirement R1.
    \36\ WECC-BAL-STD-002-0, Requirement WR1(b).
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WECC Proposal
    26. Requirement R3 of BAL-002-WECC-1 requires that each reserve
sharing group or balancing authority use certain types of reserves that
must be fully deployable within ten minutes of notification to meet
their contingency reserve requirement. Requirement R3.2 allows these
entities to count ``Interruptible Load'' as contingency reserves.\37\
In addition, Requirement R3.6 allows entities to use ``Load, other than
Interruptible Load, once the Reliability Coordinator has declared a
capacity or energy emergency.'' \38\
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    \37\ BAL-002-WECC-1, Requirement R3.2.
    \38\ BAL-002-WECC-1, Requirement R3.6.
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    27. NERC contends that the changes made by the proposed regional
Reliability Standard related to the treatment of firm load have reduced
the number of occasions when an entity may use firm load as contingency
reserves.\39\ NERC explains that, under the proposed regional
Reliability Standard, balancing authorities or reserve sharing groups
may only use firm load as contingency reserves once the reliability
coordinator has declared a capacity or energy emergency. NERC also
states that the proposed regional Reliability Standard continues to
require that reserves must be deliverable to be included in the minimum
calculations of contingency reserves.
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    \39\ NERC Petition at 19.
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NOPR Proposal
    28. The Commission does not agree with NERC that the proposed
regional Reliability Standard reduces the occasions when an entity may
use firm load as contingency reserves. The Commission proposes to find
that Requirement R3.6 is not technically sound because it permits
balancing authorities and reserve sharing groups within WECC to use
firm load to meet their minimum contingency reserve requirement ``once
the Reliability Coordinator has declared a capacity or energy
emergency,'' thus creating the possibility that firm load could be shed
due to the loss of a single element on the system.\40\
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    \40\ Order No. 672, FERC Stats. & Regs. ] 31,204, at P 324
(identifying guidelines for what constitutes a just and reasonable
Reliability Standard including the ``proposed Reliability Standard
must be designed to achieve a specified reliability goal and must
contain a technically sound means to achieve this goal'').
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    29. Although NERC states in its petition that the proposed regional
Reliability Standard ``reduce[s] the number of occasions when an entity
may use firm load as contingency reserves,'' the currently effective
regional Reliability Standard does not allow the use of firm load to
meet minimum contingency reserve levels. In fact, the current regional
Reliability Standard does not mention ``firm load'' as an acceptable
type of reserve.
    30. In the 2007 proceeding in which the Commission approved the
currently effective WECC-BAL-STD-002-0, one commenter argued that the
definition of ``interruptible'' is unclear and that firm transactions
are potentially curtailable and thus interruptible under a ``very
narrow interpretation.'' \41\ The Commission rejected the protest on
this issue stating that ``the meaning of the term `interruptible' is
generally well understood in the industry, i.e., transmission or
generation subject to interruption at the provider's discretion.'' \42\
Thus, if entities within

WECC have interpreted the term ``interruptible load'' to include firm
load, this is a mistake.
---------------------------------------------------------------------------

    \41\ North American Electric Reliability Corp., 119 FERC ]
61,260 at P 50.
    \42\ Id. P 59. The NERC Glossary defines Interruptible Load as
interruptible demand or the demand that the end-use customer makes
available to its load-serving entity via contract or agreement for
curtailment. See NERC Glossary, available at: http://www.nerc.com/
docs/standards/rs/Glossary_2009April20.pdf.
---------------------------------------------------------------------------

    31. The Commission does not support a regional practice by
balancing authorities or reserve sharing groups to count firm load
towards their minimum contingency reserve requirements. Neither the
corresponding NERC continent-wide Reliability Standard, BAL-002-0, nor
the currently effective WECC regional Reliability Standard permit a
balancing authority to consider firm load when satisfying minimum
contingency reserve requirements. Accordingly, the Commission proposes
to find that the proposed regional Reliability Standard is less
stringent than the continent-wide Reliability Standard because it would
allow entities to count firm load towards their minimum contingency
reserve requirements.
    32. Moreover, we are concerned that the provision of the proposed
WECC regional Reliability Standard that would allow a balancing
authority to include firm load as contingency reserve when an emergency
is declared is inappropriate because there are provisions of NERC
continent-wide Reliability Standards that specifically address the
actions entities must take in emergency situations. The proposed WECC
regional Reliability Standard appears to be incongruent with these
other provisions. Specifically, the requirements of Reliability
Standard EOP-002-2.1 ensure that entities are prepared to handle
capacity and energy emergency situations, and include minimum remedies
required for mitigating capacity and energy emergencies to meet the
Disturbance Control Standard and resolve the emergency conditions.
Attachment 1 of EOP-002-2.1, Energy Emergency Alerts, describes three
emergency alert levels, in order of severity. A reliability coordinator
(either by its own initiative or at the request of a balancing
authority or load serving entity) may initiate a level one energy
emergency alert if a load-serving entity is, or expects to be, unable
to provide customers' energy requirements or the load-serving entity
cannot schedule resources due to, for example, available transfer
capability or transmission loading relief limitations.\43\ A level two
alert is more severe, addressing situations when an entity can no
longer provide its customers' energy requirements. A level three alert
is called when a firm load interruption is imminent or in progress.
---------------------------------------------------------------------------

    \43\ An energy emergency level 1 can be declared either if an
entity foresees or is experiencing in real-time, conditions where
all available resources are committed to firm load, firm
transactions, and reserve commitments are being met, but the entity
is concerned about sustaining its required operating reserve.
Reliability Standard EOP-002-2.1, Attachment 1.
---------------------------------------------------------------------------

    33. As mentioned above, Requirement R3.6 of proposed BAL-002-WECC-
1, would allow an entity to include firm load to satisfy contingency
reserve requirements once the reliability coordinator ``has declared a
capacity or energy emergency'' and applies when any level alert is
initiated without qualification. This is of concern to the Commission
because, if an entity initiated energy emergency alert level 1, under
BAL-002-WECC-1, that entity could count firm load as contingency
reserve instead of taking other actions to remedy the situation as set
forth in NERC Reliability Standard EOP-002-2.1 (e.g., public appeals,
voltage reduction, firm or non-firm imports, emergency assistance from
neighboring entities, and demand-side management). This practice is not
allowed under the corresponding continent-wide Reliability Standard,
BAL-002-0. Since the proposed regional Reliability Standard includes
requirements that are less stringent than BAL-002-0, the Commission
proposes to remand BAL-002-WECC-1 and direct WECC to modify the
regional Reliability Standard to ensure consistency with the continent-
wide Reliability Standards.

C. Contingency Reserve Restoration Period

    34. NERC Reliability Standard BAL-002-0 provides that a balancing
authority or reserve sharing group responding to a disturbance must
fully restore its contingency reserves within 90 minutes following the
disturbance recovery period, which is set at 15 minutes.\44\ Thus,
under BAL-002-0, if there is a disturbance, a balancing authority or
reserve sharing group has 105 minutes to fully restore its contingency
reserves. The current WECC regional BAL Reliability Standard requires
reserve sharing groups and balancing authorities to maintain 100
percent of required operating reserve levels except within the first 60
minutes following an event requiring the activation of operating
reserves.\45\ Thus, currently, applicable entities in WECC have 60
minutes to restore their operating reserves to 100 percent. In the
March 2007 petition asking the Commission to approve the currently
effective WECC-BAL-STD-002-0, NERC explained that the increased
stringency was meant to address concerns arising out of the 1996
blackouts in California and that, according to WECC, the regional
requirements were critical to the reliability of the Western
Interconnection.\46\
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    \44\ Reliability Standard BAL-002-0, Requirements R4 and R6.
    \45\ WECC regional Reliability Standard WECC-BAL-STD-002-0,
Measure of Compliance WM1.
    \46\ NERC, March 26, 2007 Petition Proposing Current Regional
Reliability Standard, Docket No. RR07-11-000, at 5.
---------------------------------------------------------------------------

    35. In approving WECC-BAL-STD-002-0, the Commission found that
WECC's requirement to restore contingency reserves within 60 minutes
was more stringent than the 90 minute restoration period set forth in
NERC's BAL-002-0.\47\
---------------------------------------------------------------------------

    \47\ North American Electric Reliability Corp., 119 FERC ]
61,260 at P 53.
---------------------------------------------------------------------------

WECC Proposal
    36. WECC proposes to replace the current 60 minute restoration
period requirement with a new provision that would require the
restoration of contingency reserves within 90 minutes from the end of
the disturbance recovery period (15 minutes). NERC states that the 60
minute restoration period required by the current regional Reliability
Standard was developed and used under a manual interchange transaction
structure among vertically integrated utilities. NERC states that, due
to a substantial increase in the number of market participants and
interchange transactions in the Western Interconnection, entities
within the Western Interconnection have implemented an electronic
tagging system (e-tagging). NERC states that the adoption of the e-
tagging system accommodates multiple market participants and the
corresponding increased number of interchange transactions makes the
current mid-hour reserve restoration period more cumbersome and makes
the inappropriate rejection of reserve restoration transactions more
likely because such transactions are outside the e-tagging cycle. Thus,
NERC contends that eliminating the 60 minute reserve restoration
requirement and adopting the proposed new requirements, which provide
the same reserve restoration period as NERC's BAL-002-0, results in
more efficient communication among balancing authorities because it
aligns the restoration of contingency reserves with the e-tagging
system approval cycle.
NOPR Proposal
    37. The Commission proposes to remand the regional Reliability
Standard BAL-002-WECC-1 based on the lack of any technical
justification or analysis of the potential increased risk

to the Western Interconnection resulting from the increase in the
contingency reserve restoration period. Without sufficient data, the
Commission is unable to determine whether the increase in contingency
reserve restoration period is sufficient to maintain the reliable
operation of the Bulk-Power System in the Western Interconnection. A
requirement to restore contingency reserves following a disturbance
improves reliability by ensuring an entity will be in position to
respond to the next disturbance, thus preventing adverse reliability
impacts. When a contingency has occurred and operating reserves,
generation or interruptible load, have been deployed, the system
typically has insufficient reserves to respond to another contingency
until such reserves are replenished. During this time, the system is in
a vulnerable position, an emergency state, in which the next
contingency could lead to cascading outages. Exposure in such a state
should be limited to the extent possible. The Commission notes that in
the Western Interconnection a significant number of transmission paths
are voltage or frequency stability limited, in contrast to other
regions of the Bulk-Power System where transmission paths more often
are thermally limited. Disturbances that result in a ``stability
limited'' transmission path overload, generally, must be responded to
in a shorter time frame than a disturbance that results in a
``thermally limited'' transmission path overload. The Commission
understands that this physical difference is one of the reasons for the
need for certain provisions of regional Reliability Standards in the
Western Interconnection.
    38. Proposed BAL-002-WECC-1 does not include a requirement that an
entity restore either contingency reserves or operating reserves.
Instead, proposed compliance measure M1 provides that an entity should
have documentation to prove it maintained the required contingency
reserve level except during the 105 minutes following a disturbance,
which represents a 45 minute increase over the current requirement. As
an initial matter, a Reliability Standard should set forth substantive
compliance obligations in the ``Requirements'' section of the
Reliability Standard, and not in the ``Compliance Measures'' section.
Moreover, we believe that there is no need for a provision of regional
Reliability Standard that simply restates the requirement of a
corresponding continent-wide Reliability Standard. This is unnecessary,
duplicative, and potentially confusing if the regional Reliability
Standard is intended to create the same obligation as the continent-
wide Reliability Standard. Instead, the regional Reliability Standard
should remain silent with regard to any such requirements, and possibly
cross-reference the corresponding continent-wide Reliability Standard
as appropriate.
    39. The only justification offered by NERC for the extension of the
reserve restoration period to match the continent-wide Reliability
Standard is the adoption of the e-tagging system by entities in the
Western Interconnection. The e-tagging system is an efficient tool used
for day-ahead and hour-ahead market accounting and as input for day-
ahead and hour-ahead transfer capability analysis of scheduled
interchange transactions and development of day-ahead and hour-ahead
capacity and energy resource schedules. Proposing to adapt reliability
requirements to resolve problems extending from software to the extent
it is intended to better enable economic transactions is not a
technical justification since it does not address any change in the
need for the reliability requirement. Extending the contingency reserve
restoration period from 60 minutes to 105 minutes increases exposure to
unstable operating conditions. Although adoption of the e-tagging
system may result in more efficient communication among transmission
operators and balancing authorities for day-ahead and hour-ahead
scheduling, this fact alone does not appear sufficient to justify the
extension of the reserve restoration period.
    40. Although NERC BAL-002-0 provides for a 90-minute contingency
restoration period, WECC explained in 2007 that it needed a shortened
contingency restoration period to ensure the reliability of the Bulk-
Power System in the Western Interconnection. In its March 2007 petition
for approval of the currently effective WECC regional Reliability
Standard, NERC presented arguments from WECC that its experience in the
1996 blackouts led to an analysis of essential criteria to ensure the
reliability of the Bulk-Power System in the Western Interconnection
and, as a result, WECC developed more stringent requirements as it
relates to this issue for the region.\48\ The proposal in the immediate
proceeding, however, offers marketing or administrative reasons for
increasing the contingency reserve restoration period. NERC does not
provide a technical justification regarding how this proposed
modification adequately ensures the reliability of the Bulk-Power
System in the Western Interconnection. We encourage Regional Entities
periodically to reevaluate their need for regional Reliability
Standards. However, when a Regional Entity proposes to modify a
regional Reliability Standard it previously claimed was necessary to
maintain reliability in that region by adopting less stringent
requirements, the Regional Entity must demonstrate that the modified
requirements are sufficient to maintain reliability in the region.
---------------------------------------------------------------------------

    \48\ NERC, March 26, 2007 Petition Proposing Current Regional
Reliability Standard, Docket No. RR07-11-000, at 4-5.
---------------------------------------------------------------------------

    41. It appears to the Commission that the proposed modification set
forth in Measure M1 may weaken the reliability of the Bulk-Power System
in the Western Interconnection. Accordingly, the Commission proposes to
remand BAL-002-WECC-1 and to direct WECC to either: (1) Retain the
current 60-minute rule; or (2) provide technical justification and
supporting data demonstrating how WECC will maintain adequate
reliability with the proposed 105-minute reserve restoration period.
The regional entity could provide a variety of technical justifications
to support this modification. For example, WECC could perform a
statistically significant analysis of the level of risk associated with
the conditions using the 60-minute reserve restoration period as
compared to the projected level of risk associated with the proposed
90-minute restoration period. The analysis must demonstrate that the
proposed revisions do not expose entities within the Western
Interconnection to a level of risk that is greater than the level of
risk accepted by entities operating under the requirements of the
continent-wide NERC Reliability Standard, taking into account the
specific electrical characteristics and topology of the Western
Interconnection. Alternatively, WECC could perform model simulations,
representative of all operating conditions, showing how the system
would deploy contingency reserves after a first contingency (n-1) and,
prior to restoration of the reserves, apply a second contingency (n-1-
1) to determine if the system will stabilize. Based on comments made by
the Reliability Standards drafting team, submitted as part of the
development record in Exhibit C to the NERC petition, the Commission
believes that NERC should be able to provide this

information without any undue burden.\49\
---------------------------------------------------------------------------

    \49\ NERC Petition, Exhibit C at p. 24 (stating that ``the WECC
Performance Work Group performed studies in 2005 that show little if
any increase in risk to the system by changing the restoration
period to the NERC time''). The referenced studies, however, are not
part of the record in this proceeding.
---------------------------------------------------------------------------

D. Including Demand-Side Management as a Resource

    42. In Order No. 693, the Commission directed the ERO to submit a
modification to continent-wide Reliability Standard BAL-002-0 that
includes a Requirement that explicitly allows that demand-side
management be used as a resource for contingency reserves, and
clarifies that demand-side management should be treated on a comparable
basis and must meet similar technical requirements as other resources
providing this service.\50\ The Commission directed the ERO to list the
types of resources that can be used to meet contingency reserves to
provide users, owners and operators of the Bulk-Power System a set of
options to meet contingency reserves.\51\ The Commission clarified that
the purpose of this directive was to ensure comparable treatment of
demand-side management with conventional generation or any other
technology and to allow demand-side management to be considered as a
resource for contingency reserves on this basis without requiring the
use of any particular contingency reserve option.\52\ The Commission
further clarified that in order for demand-side management to
participate, it must be technically capable of providing contingency
reserve service, with the ERO determining the technical
requirements.\53\
---------------------------------------------------------------------------

    \50\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ]
31,242, at P 330 (2007), order on reh'g, Order No. 693-A, 120 FERC ]
61,053 (2007).
    \51\ Id. P 331, 335.
    \52\ Id. P 333.
    \53\ Id. P 334.
---------------------------------------------------------------------------

1. BAL-002-WECC-1
WECC Proposal
    43. The proposed regional Reliability Standard does not explicitly
address the use of demand side management as a resource for contingency
reserves. NERC states that it raised this concern with WECC, and WECC
responded that the drafting team wrote the regional Reliability
Standard ``to permit load, Demand-Side Management, generation, or
another resource technology that qualifies as Spinning Reserve or
Contingency Reserve to be used as such.'' WECC further explained that
demand-side management that is deployable within ten minutes is a
subset of interruptible load, which is an acceptable type of reserve
set forth in proposed Requirement R3.2.\54\
---------------------------------------------------------------------------

    \54\ NERC Petition at 40.
---------------------------------------------------------------------------

NOPR Proposal
    44. While WECC indicates that the phrase ``interruptible load'' is
intended to include demand-side management as contingency reserve, we
believe that the regional Reliability Standard should state this
explicitly, consistent with Order No. 693. Accordingly, pursuant to
section 215(d)(5) of the FPA, we propose to direct WECC to develop a
modification to BAL-002-WECC-1 that explicitly provides that demand-
side management, that is technically capable of providing this service,
may be used as a resource for contingency reserves. Consistent with the
Commission's directive in Order No. 693, the modification should list
the types of resources, including demand-side management, which can be
used to meet contingency reserves. The modification should also ensure
comparable treatment of demand-side management with conventional
generation or any other technology and allow demand-side management to
be considered as a resource for contingency reserves on this basis
without requiring the use of any particular contingency reserve option.
    45. In addition, there appears to be a conflict related to the
definition of Spinning Reserve as it is used in the proposed regional
Reliability Standard. Requirement R3.1 provides that Spinning Reserves
may be used to meet the minimum contingency reserve requirement. The
NERC Glossary defines Spinning Reserves as ``[u]nloaded generation that
is synchronized and ready to serve additional demand.'' This definition
omits the use of demand-side management or other technologies that
could be used as a resource because it limits acceptable Spinning
Reserve resources to generation resources. An alternative definition of
spinning reserves exists in the NERC Glossary as Operating Reserve--
Spinning, which includes as part of the definition of Operating
Reserve, ``load fully removable from the system within the Disturbance
Recovery Period following the contingency event.'' Thus, this second
definition would capture the use of demand-side management as a
resource in the calculation of spinning reserve because it allows
entities to include reductions in load as spinning reserve resources.
Furthermore, the definition of Operating Reserve-Spinning is consistent
with our instruction on the continent-wide Reliability Standard as
discussed in Order No. 693.\55\ Accordingly, we propose to direct the
Regional Entity to develop a modification to the regional Reliability
Standard that references this broader definition of spinning reserve to
include demand-side management.
---------------------------------------------------------------------------

    \55\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 333
(indicating that NERC's continent-wide Reliability Standard should
provide for the inclusion of other technologies that may be able to
provide contingency reserves, including demand-side management). The
Commission understands that NERC is currently developing
modifications to BAL-002-0 that will, inter alia, address relevant
directives set forth in Order No. 693.
---------------------------------------------------------------------------

2. NERC Glossary
    46. As discussed above, the NERC Glossary offers two definitions of
spinning reserve: Spinning Reserve and Operating Reserve-Spinning. The
definition of Spinning Reserve does not include demand-side management
as a resource, whereas the definition of Operating Reserve-Spinning
does. Considering that the term Spinning Reserve is not used in any
approved Reliability Standard other than the current regional
Reliability Standard, WECC-BAL-STD-002-0, the Commission proposes to
direct NERC to remove this term from the NERC Glossary upon retirement
of the current regional Reliability Standard.
    47. Although the definitions of Operating Reserve-Spinning and
Operating Reserve-Supplemental both include ``[l]oad fully removable
from the system within the Disturbance Recovery Period following the
contingency event,'' which is broad enough to include demand-side
management, demand-side management should still be explicitly included.
Consistent with Order No. 693, the proposed directive to remove the
term Spinning Reserve from the NERC Glossary would promote comparable
treatment of demand-side management with conventional generation or any
other technology and to allow demand-side management to be considered
as a resource for operating reserves on this basis without requiring
the use of any particular operating reserve option.\56\ Moreover, in
order for demand-side management or any other technology to be used as
a spinning reserve resource, it must be technically capable of
providing operating reserve service.\57\ Accordingly, the Commission
proposes to direct the ERO to develop modifications to the definitions
of Operating Reserve-Spinning and

Operating Reserve-Supplemental to provide for the inclusion of other
technologies that could reliably contribute to operating reserves,
including demand-side management.\58\
---------------------------------------------------------------------------

    \56\ See id.
    \57\ See id. P 334.
    \58\ The Commission recognizes that there may be regional
limitations on the amount of demand-side management, or other
technically capable resources, that can be reliably employed. Any
modifications proposed to the Commission must allow regional
discretion to make this determination based on the technical issues
inherent to those regions.
---------------------------------------------------------------------------

IV. Information Collection Statement

    48. The Office of Management and Budget (OMB) regulations require
that OMB approve certain reporting and recordkeeping (collections of
information) imposed by an agency.\59\ The information contained here
is also subject to review under section 3507(d) of the Paperwork
Reduction Act of 1995.\60\ By remanding the proposed Reliability
Standard the Commission is maintaining the status quo until future
revisions to the Reliability Standard are approved by the Commission.
Thus, the Commission's proposed action does not add to or increase
entities' reporting burden.
---------------------------------------------------------------------------

    \59\ 5 CFR 1320.11.
    \60\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

V. Environmental Analysis

    49. 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.\61\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment. Included in the exclusion are rules that are clarifying,
corrective, or procedural or that do not substantially change the
effect of the regulations being amended.\62\ The actions proposed
herein fall within this categorical exclusion in the Commission's
regulations.
---------------------------------------------------------------------------

    \61\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \62\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act Certification

    50. The Regulatory Flexibility Act of 1980 (RFA) \63\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize
any significant economic impact on a substantial number of small
entities. The Small Business Administration's Office of Size Standards
develops the numerical definition of a small business.\64\ For electric
utilities, a firm is small if, including affiliates, it is primarily
engaged in the transmission, generation and/or distribution of electric
energy for sale and its total electric output for the preceding twelve
months did not exceed four million megawatt hours. The RFA is not
implicated by this proposed rule because by remanding the proposed
Reliability Standard the Commission is maintaining the status quo until
future revisions to the Reliability Standard are approved by the
Commission.
---------------------------------------------------------------------------

    \63\ 5 U.S.C. 601-612.
    \64\ See 13 CFR 121.201.
---------------------------------------------------------------------------

VII. Comment Procedures

    51. 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 May 24, 2010. Comments must refer to
Docket No. RM09-15-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments.
    52. 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.
    53. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Office of the Secretary, 888 First
Street, NE., Washington, DC 20426.
    54. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

VIII. Document Availability

    55. 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.
    56. 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.
    57. 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>
    By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2010-6477 Filed 3-23-10; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 79, Number 135 (Tuesday, July 15, 2014)]
[Notices]
[Pages 41335-41337]
[FR Doc No: 2014-16502]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-72576; File No. SR-DTC-2014-06]

Self-Regulatory Organizations; The Depository Trust Company;
Order Approving Proposed Rule Change To Modify the Receiver Authorized
Deliver and Reclaim Processing Value Limits by Transaction

July 9, 2014.

I. Introduction

    On May 30, 2014, The Depository Trust Company (``DTC'') filed with
the Securities and Exchange Commission (``Commission'') proposed rule
change SR-DTC-2014-06 (``Proposed Rule Change'') pursuant to Section
19(b)(1) of the Securities Exchange Act of 1934

(``Act'') \1\ and Rule 19b-4 thereunder.\2\ The Proposed Rule Change
was published for comment in the Federal Register on June 5, 2014.\3\
The Commission did not receive any comments on the Proposed Rule
Change. This order approves the Proposed Rule Change.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ Securities Exchange Act Release No. 72283 (May 30, 2014), 79
FR 32599 (June 5, 2014).
---------------------------------------------------------------------------

II. Description

    DTC filed the Proposed Rule Change to modify its Rules, By-Laws,
and Organization Certificate (``Rules'') to lower limits against which
valued Deliver Orders (``DOs'') and Payment Orders (``POs'') \4\ will
be required to be accepted for receipt (i.e., ``matched'' for
settlement) via DTC's Receiver Authorized Delivery (``RAD'') process.
With the Proposed Rule Change, DTC seeks to reduce the intraday
uncertainty that may arise from reclaim transactions linked to DOs and
POs and any potential credit and liquidity risk from such transactions.
---------------------------------------------------------------------------

    \4\ A DO is a book-entry movement of a particular security
between two DTC participants (``Participants''). A PO is a method
for settling funds related to transactions and payments not
associated with a DO. For purposes of this Proposed Rule Change, the
defined term ``DOs'' includes all valued DOs except for DOs of: (i)
Money Market Instruments (``MMI'') and (ii) institutional delivery
(``ID'') transactions affirmed through Omgeo, both of which are not
impacted by the Proposed Rule Change.
---------------------------------------------------------------------------

    Currently, as set forth in the DTC Settlement Service Guide
(``Guide''), valued DOs and POs, excluding DOs of MMIs and ID
transactions, in amounts above $7.5 million and $500,000, respectively,
are subject to the RAD process, which allows a receiver of DOs and/or
POs (``Receiver'') to review and reject transactions that it does not
recognize prior to DTC's processing of the transaction.\5\ In contrast,
lower valued DOs and POs do not require the Receiver's acceptance prior
to processing. Instead, if the Receiver does not recognize a DO or PO
it has received, the DO or PO may be returned by the Receiver to the
original deliverer of the DO or PO (``Deliverer'') in a reclaim
transaction (``Reclaim''). While both the Reclaim and RAD
functionalities allow a Receiver to exercise control over which
transactions to accept, Reclaims tend to create uncertainty because
transactions may be returned late in the day, when the Deliverer may
have limited options to respond. Because Reclaims are permitted without
regard to DTC's risk management controls, a Deliverer that is subject
to a Reclaim may incur a greater settlement obligation than otherwise
anticipated, increasing credit and liquidity risk to the Deliverer and
to DTC.\6\
---------------------------------------------------------------------------

    \5\ In 2013, DTC took an initial step to address this
uncertainty by lowering the RAD threshold over which transactions
must be matched for DOs and POs from $15 million and $1 million,
respectively, to the current limits mentioned above. Securities
Exchange Act Release No. 69985 (July 12, 2013); 78 FR 42991 (July
18, 2013) (SR-DTC-2013-04).
    \6\ DTC's risk management controls, including Collateral Monitor
and Net Debit Cap, are designed so that DTC can effect system-wide
settlement notwithstanding the failure to settle of the largest DTC
Participant or affiliated family of Participants. The Collateral
Monitor tests that a Participant has adequate collateral to secure
the amount of its net debit balance so that DTC may borrow funds to
cover that amount for system-wide settlement if the Participant
defaults. See DTC Rules, http://dtcc.com/~/media/Files/Downloads/
legal/rules/dtc--rules.ashx. The Net Debit Cap limits the net debit
balance a Participant can incur so that the unpaid settlement
obligation of the Participant, if any, cannot exceed available DTC
liquidity resources. Id.
---------------------------------------------------------------------------

    Pursuant to the Proposed Rule Change, DTC will revise the Guide to
reflect that: (i) With respect to valued DOs, DTC will lower the RAD
threshold to $.01 via a three-phase reduction as described below, and
(ii) with respect to POs, DTC will reduce the RAD threshold to zero
immediately upon implementation of the Proposed Rule Change. As such,
in the first phase of implementation of the Proposed Rule Change, DTC
will reduce the RAD threshold for DOs to $100,000. In the second phase,
the RAD threshold for valued DOs will be reduced to $20,000. In the
third phase, the RAD threshold for DOs will be reduced to $.01. In
addition, to further promote finality of settlement, new issues will no
longer be exempt from RAD.
    Also, the Guide will be updated to reflect that certain DO and PO
functions will no longer be accessible through DTC's Participant
Terminal System. Instead, such functions will be accessible through a
DTC web application known as ``Settlement Web.'' Further, the Guide
will be updated via a technical change to clarify that the RAD
threshold for institutional transactions remains at $15 million, rather
than at the $7.5 million amount currently in effect for non-
institutional transactions. Finally, the Guide will be revised to
remove a provision that overvalued deliveries are automatically routed
to RAD, as this section will become redundant upon implementation of
the Proposed Rule Change since all DOs will be subject to RAD.
    The effective date of the Proposed Rule Change, including the dates
of the implementation phases described above, will be announced via a
DTC Important Notice.\7\
---------------------------------------------------------------------------

    \7\ For purposes of taking into account the incremental
implementation of the Proposed Rule Change as described above,
beginning on an implementation date that shall be announced via DTC
Important Notice (``Initial Implementation Date'') DTC will lower
the RAD limit for non-institutional DOs to $100,000 and POs to zero.
From a date that is approximately two weeks following the Initial
Implementation Date and that shall be announced by Important Notice,
until a date that is approximately six weeks following the Initial
Implementation Date and that shall be announced by Important Notice,
DTC will lower the RAD limit for non-institutional DOs to $20,000.
From a date that is approximately six weeks following the Initial
Implementation Date and that shall be announced by Important Notice,
DTC will lower the RAD limit for non-institutional DOs to $.01.
---------------------------------------------------------------------------

III. Discussion

    Section 19(b)(2)(C) of the Act \8\ directs the Commission to
approve a proposed rule change of a self-regulatory organization if it
finds that such proposed rule change is consistent with the
requirements of the Act and rules and regulations thereunder applicable
to such organization. Section 17A(b)(3)(F) of the Act requires, among
other things, that the rules of a clearing agency be designed to
promote the prompt and accurate clearance and settlement of securities
transactions.\9\ In addition, Rule 17Ad-22(d)(12) of the Act requires
that a clearing agency establish, implement, maintain and enforce
written policies and procedures reasonably designed to ensure that
final settlement occurs no later than the end of the settlement day and
require that intraday or real-time finality be provided where necessary
to reduce risks.\10\
---------------------------------------------------------------------------

    \8\ 15 U.S.C. 78s(b)(2)(C).
    \9\ 15 U.S.C. 78q-1(b)(3)(F).
    \10\ 17 CFR 240.17Ad-22(d)(12).
---------------------------------------------------------------------------

    The Commission finds the Proposed Rule Change is consistent with
the Act. More specifically, as the Proposed Rule Change pertains to the
lower RAD threshold for non-institutional transactions, the resulting
limit on Reclaim transactions, and the removal of the new issue
exemption, the Commission finds that the Proposed Rule Change is
consistent with Section 17A(b)(3)(F) of the Act \11\ because it will
increase the number of deliveries that will require Receiver approval
prior to DTC processing, which reduces the intraday uncertainty and
associated risks that may arise from Reclaims, thus facilitating the
prompt and accurate clearance and settlement of securities
transactions. The Commission also finds these aspects of the Proposed
Rule Change consistent with Rule 17Ad-22(d)(12) of the Act \12\ because
more

transactions will be subject to DTC's risk management controls, which
helps ensure that final settlement occurs no later than the end of the
settlement day.
---------------------------------------------------------------------------

    \11\ 15 U.S.C. 78q-1(b)(3)(F).
    \12\ 17 CFR 240.17Ad-22(d)(12).
---------------------------------------------------------------------------

    Additionally, the Commission finds the Proposed Rule Change, as it
pertains to changes to DTC's Participant Terminal System and Settlement
Web services, the RAD threshold for institutional transactions, and
overvalued deliveries, consistent with both Section 17A(b)(3)(F) of the
Act \13\ and Rule 17Ad-22(d)(12) of the Act \14\ because specifying the
application through which Participants may access certain settlement
functions, clarifying the RAD threshold of institutional transactions,
and eliminating redundant provisions promotes the prompt and accurate
clearance and settlement of securities transactions and improves DTC's
written policies and procedures that are designed to ensure final
settlement no later than the end of the settlement day.
---------------------------------------------------------------------------

    \13\ 15 U.S.C. 78q-1(b)(3)(F).
    \14\ 17 CFR 240.17Ad-22(d)(12).
---------------------------------------------------------------------------

IV. Conclusion

    On the basis of the foregoing, the Commission finds that the
Proposed Rule Change is consistent with the requirements of the Act and
in particular with the requirements of Section 17A of the Act \15\ and
the rules and regulations thereunder.
---------------------------------------------------------------------------

    \15\ 15 U.S.C. 78q-1.
---------------------------------------------------------------------------

    It is therefore ordered, pursuant to Section 19(b)(2) of the Act,
that proposed rule change SR-DTC-2014-06 be, and hereby is,
approved.\16\
---------------------------------------------------------------------------

    \16\ In approving the proposed rule change, the Commission
considered the proposal's impact on efficiency, competition, and
capital formation. 15 U.S.C. 78c(f).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\17\
---------------------------------------------------------------------------

    \17\ 17 CFR 200.30-3(a)(12).
---------------------------------------------------------------------------

Kevin M. O'Neill,
Deputy Secretary.
[FR Doc. 2014-16502 Filed 7-14-14; 8:45 am]
BILLING CODE 8011-01-P


Summary of Petition

A summary of the pesticide petition is given below. The petitioner
prepared the summary of the petition.

EPA Registration Division contact: Venus Eagle,<PHONE_NUMBER>

 E. I. DuPont de Nemours and Company, DuPont Crop Protection

[6G7089]

	EPA has received a pesticide petition ([6G7089]) from E. I. DuPont de
Nemours and Company, DuPont Crop Protection, Wilmington, Delaware,
proposing, pursuant to section 408(d) of the Federal Food, Drug, and
Cosmetic Act (FFDCA), 21 U.S.C. 346a(d), to amend 40 CFR part 180 to
establish temporary tolerances for residues of DPX-E2Y45,
3-Bromo-N-[4-chloro-2-methyl-6-[(methylamino)carbonyl]phenyl]-1-(3-chlor
o-2-pyridinyl)-1H-pyrazole-5-carboxamide in or on the raw agricultural
commodities: Apple --> 0.3 parts per million (ppm), celery-->7.0 ppm,
cucumber --> 0.09 ppm, head lettuce -->4.0 ppm, leaf lettuce -->7.5 ppm,

pear --> 0.3 ppm, pepper -->0.5 ppm, spinach -->13.0 ppm, squash -->0.25
ppm, tomato -->0.3 ppm and watermelon --> 0.2 ppm .  EPA has determined
that the petition contains data or information regarding the elements
set forth in section 408(d)(2) of the FFDCA; however, EPA has not fully
evaluated the sufficiency of the submitted data at this time or whether
the data supports granting of the petition.  Additional data may be
needed before EPA rules on the petition.

A. Residue Chemistry

1. Plant metabolism.   The metabolism of DPX-E2Y45 is adequately
understood to support the proposed temporary tolerances. Studies in
apple trees, lettuce, and tomatoes showed no significant metabolites.
The only significant residue is the parent compound.

2. Animal Metabolism. The metabolism of DPX-E2Y45 in ruminants is
adequately understood to support the temporary tolerances.  A goat
metabolism study was conducted for 7 days in which DPX-E245 was dosed
daily at 10.4 mg/kg of food consumed.   A total of 93.57% of the
residues were excreted over the course of the study.  The highest levels
of total radioactive residues in milk were observed between the second
and third day of dosing at 0.081 ug/g and decreased to 0.047 ug/g by day
7.  The total radioactive residues in the edible tissues were low (0.02
– 0.09 ug/g) except for the liver, which contained 0.64 ug/g.
DPX-E2Y45 was found in all tissues together with trace levels of
oxidized metabolites.  These results indicate that there is not a
significant transfer of residues of DPX-E2Y45 and its metabolites to
fat, meat or milk.

3. Analytical method.   The analytical procedure for analysis of
DPX-E2Y45 in crop matrices is based on DuPont-13294, “Method
Validation for the Analysis of DPX-E2Y45 in Various Crop Matrices”.
DPX-E2Y45 is separated from co-extracts by reversed phase liquid
chromatography (LC) and is detected by positive ion Atmospheric Pressure
Chemical Ionization (APCI) mass spectrometry/mass spectrometry (MS/MS).
The Limit of Quantitation (LOQ) is 0.010 mg/kg (ppm) and the Limit of
Detection (LOD) is estimated to be 0.003 mg/kg (ppm).

	4. Magnitude of residues.

Cucurbits: The average field residue value for all cucurbits was 0.046
ppm and the maximum was 0.12 ppm.

Seven field trials were conducted on cucumber.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 1 day after the last
application (PHI- Post Harvest Interval).  The mean field residue value
for cucumbers was 0.030 ppm and the maximum at 0.083 ppm.

Seven field trials were conducted on cantaloupe/muskmelon.  Two
applications were made, generating the maximum seasonal labeled use rate
of 0.20 lb. ai/A (225 g ai/ha/season).  Harvesting was conducted 1 day
after the last application.  The mean field residue value for
cantaloupe/muskmelon was 0.061 ppm and the maximum at 0.12 ppm.

Six field trials were conducted on summer squash.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 1 day after the last
application.  The mean field residue value for summer squash was 0.048
ppm and the maximum at 0.093 ppm.

Pome fruit:  The average field residue value for all pome fruit was
0.069 ppm and the maximum was 0.30 ppm.

Seventeen field trials were conducted on apples.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 14 days after the last
application.  The mean field residue value for apples was 0.069 ppm and
the maximum at 0.30 ppm.

Eleven field trials were conducted on pears.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 14 days after the last
application.  The mean field residue value for pears was 0.069 ppm and
the maximum at 0.14 ppm.

Fruiting Vegetables:  The average field residue value for all fruiting
vegetables was 0.088 ppm and the maximum was 0.43 ppm.

Twenty field trials were conducted on tomatoes.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 1 day after the last
application.  The mean field residue value for tomatoes was 0.079 ppm
and the maximum at 0.19 ppm.

Eleven field trials were conducted on bell pepper.  Two applications
were made, generating the maximum seasonal labeled use rate of 0.20 lb.
ai/A (225 g ai/ha/season).  Harvesting was conducted 1 day after the
last application.  The mean field residue value for bell pepper was
0.077 ppm and the maximum at 0.19 ppm.

Nine field trials were conducted on non-bell pepper.  Two applications
were made, generating the maximum seasonal labeled use rate of 0.20 lb.
ai/A (225 g ai/ha/season).  Harvesting was conducted 1 day after the
last application.  The mean field residue value for non-bell pepper was
0.12 ppm and the maximum at 0.43 ppm.

Leafy Vegetables:  The average field residue value for all leafy
vegetables was 3.7 ppm and the maximum was 9.7 ppm.

Seven field trials were conducted on head lettuce.  Two applications
were made, generating the maximum seasonal labeled use rate of 0.20 lb.
ai/A (225 g ai/ha/season).  Harvesting was conducted 1 day after the
last application. The mean field residue value for head lettuce was 0.99
ppm and the maximum at 2.5 ppm.

Seven field trials were conducted on leaf lettuce.  Two applications
were made, generating the maximum seasonal labeled use rate of 0.20 lb.
ai/A (225 g ai/ha/season).  Harvesting was conducted 1 day after the
last application. The mean field residue value for leaf lettuce was 4.4
ppm and the maximum at 6.3 ppm.

Seven field trials were conducted on celery.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 1 day after the last
application. The mean field residue value for celery was 2.3 ppm and the
maximum at 3.8 ppm.

Seven field trials were conducted on spinach.  Two applications were
made, generating the maximum seasonal labeled use rate of 0.20 lb. ai/A
(225 g ai/ha/season).  Harvesting was conducted 1 day after the last
application. The mean field residue value for spinach was 6.9 ppm and
the maximum at 9.7 ppm.

Processing Studies –DPX-E2Y45 residues in apples concentrated in wet
and dry pomace relative to the unprocessed fruit by average factors of
2.6 and 11, respectively.  DPX-E2Y45 residues were either not detected
or reduced in concentration relative to the unprocessed fruit upon
processing to juice, apple sauce, apple preserves and canned apples.

DPX-E2Y45 residues in tomatoes concentrated in puree and paste relative
to the unprocessed fruit by an average factor of 1.5 for both
commodities.  No concentration was observed in canned tomatoes, juice
and ketchup (average processing factors).

Cattle Feeding Study.   A cattle feeding study was conducted with
DPX-E2Y45 at doses of 1, 3, 10, and 50 mg/kg feed.  Based on final
residue values for the directly treated pome commodities contributing to
the cattle diet (apple dry pomace), the potential dietary burden in beef
and dairy cattle is less than 1 mg/kg in the feed. There were no
quantifiable residues (greater than 0.010 mg/kg)  in any matrix (milk,
skim milk, cream, liver, kidney, fat, or muscle) at  the 1 mg/kg dietary
feeding level.

B. Toxicological Profile

	1. Acute toxicity. Based on EPA criteria, DPX-E2Y45 is classified as
follows for Toxicity Categories:

Guideline	Title	Results	Category

870.1100

870.1200

870.1300

870.2400

870.2500

870.2600	Acute Oral Toxicity

Acute Dermal Toxicity

Acute Inhalation Toxicity

Primary Eye Irritation

Primary Dermal Irritation

Skin Sensitization	LD50: >5000 mg/kg (Rat)

LD50: >5000 mg/kg (Rat)

LC50: >5.1 mg/L (Rat)

Mild irritation (Rabbit)

No irritation (Rabbit)

Not a sensitizer (Mouse LLNA)	Category IV

Category IV

Category IV

Category IV

Category IV

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

	Formulated products are as equally non-toxic following acute exposures
as is technical DPX-E2Y45.  The acute inhalation toxicity for the 20 SC
formulation could not be determined above the maximum practically
attainable atmospheric aerosol concentration of 2 mg/L.

	2. Genotoxicty.  DPX-E2Y45 has shown no genotoxic activity in the
following listed in-vitro and in-vivo tests:

Bacterial reverse mutation

In-vitro mammalian gene mutation (CHO/HGPRT)

In-vitro chromosomal aberration (human lymphocytes)

In-vivo mouse micronucleus

	3. Reproductive and developmental toxicity.  In developmental toxicity
studies in rats and rabbits, DPX-E2Y45 exhibited no effects on any
parameter in pregnant females or their offspring at levels up to and
including the maximum tested dose of 1,000 mg/kg bw/day.

	No reproductive toxicity was observed in a two-generation reproduction
study with DPX-E2Y45 in rats.  No adverse effects were observed on
reproduction, fertility, sperm parameters, estrous cycle, litter size,
pup survival and developmental landmarks up to the maximum tested dose
of 20,000 ppm in the diet.  There were no adverse histological findings
indicative of reproductive toxicity.  There was a slight reduction in
the F1 pup (but not F2 pup) weight during lactation at the highest dose
level (mean maternal intake during lactation equal to 3118 mg/kg
bw/day); this was attributed, in part, to weight loss in one dehydrated
dam during lactation which had a litter with some of the lowest pup
weights.  The slight change in pup weight was without subsequent effects
since overall body weight, weight gain and development in F1 rats fed
20,000 ppm were similar to control animals.

	4. Subchronic toxicity.

	Subchronic (90-day) feeding studies were conducted with rats, mice and
dogs. No adverse effects were observed at the highest dietary
concentrations tested of 20,000 ppm in rats (1188 mg/kg bw/day for males
and 1526 mg/kg bw/day for females), 7,000 ppm in mice (1135 mg/kg bw/day
for males and 1539 mg/kg bw/day for females) and 40,000 ppm in dogs
(1163 mg/kg bw/day for males and 1220 mg/kg bw/day for females).

	A 28-day dermal toxicity study in rats was conducted at doses of 100,
300 and 1000 mg/kg bw/day.  The NOAEL for male and female rats was 300
mg/kg bw/day based on reductions in body weight gain and food efficiency
at 1000 mg/kg bw/day.

	No adverse target organ effects were observed in any subchronic
toxicity study.

5. Chronic toxicity. Chronic toxicity studies with DPX-E2Y45 are
ongoing.

	6. Animal metabolism. A rat metabolism study is ongoing.  The majority
of the dose (> 92%) is excreted within 7 days of a single gavage dosing.
 DPX-E2Y45 undergoes extensive metabolism in the rat; the distribution
of residues in the tissues is extensive and the residues are
non-accumulating.

	Daily dosing of DPX-E2Y45 to goats at a level of 10 ug/g in the diet
for 7 days resulted in total residues less than or equal to 0.02 mg/kg
in the meat, 0.07 mg/kg in the fat, 0.64 mg/kg in the liver and 0.08
mg/kg in the milk.  The majority of the residues (90%) were excreted in
the feces and urine.  DPX-E2Y45 is a significant residue in all tissues
and 1-4 additional residues were identified in the liver, kidney, muscle
and fat; additional minor components (<0.01 ug/g) were also observed.
The metabolism of DPX-E2Y45 is well understood.

	7. Metabolite toxicology. Due to the extremely low toxicity of the
parent compound and the extensive metabolism observed in mammalian
systems, DPX-E2Y45 metabolites are not expected to result in any
significant toxicity.

	8. Endocrine disruption.  No adverse effects were observed on any
endocrine tissue in repeat dose studies in rats, mice and dogs.

C. Aggregate Exposure

	1. Dietary exposure. No acute exposure assessment was conducted since
an aRfD was not established as an effect attributable to a single
exposure was not observed in the oral toxicity studies conducted with
DPX-E2Y45.  An assessment was conducted to determine the chronic
exposure of the US population and population subgroups to DPX-E2Y45.
Tolerance values are being proposed for leafy vegetable crop group 4,
fruiting vegetable crop group 8, cucurbit vegetables crop group 9, and
pome fruit crop group 11; tolerances are not being proposed for meat and
milk, since residues are not expected in these commodities.  The chronic
exposure analysis included all crops with proposed tolerance values.

	i. Food.  The chronic dietary exposure assessment of the currently
proposed uses of DPX-E2Y45 was determined with the chronic module of the
Dietary Exposure Evaluation Model software with Food Commodity Intake
Database (DEEM-FCIDTM ), version 2.14, from Exponent, Inc. using the
chronic reference dose (cRfD) of 1.135 mg/kg bw/day, derived from a NOEL
of 1135 mg/kg bw/day (90-day subchronic study in mice), and uncertainty
factors of 10X for interspecies variation, 10x for intraspecies
variation, and 10X for the current incompleteness of the toxicology
database.  The analysis used proposed tolerance values and no
adjustments for processing or percent crop treated (100% crop treated
was assumed); the actual dietary exposure will be much less than that
discussed here.  The chronic exposure to DPX-E2Y45 for the overall US
Population in this very conservative analysis is 0.005539 mg/kg bw/day,
which is less than 1% of the cRfD.  The exposure of the most sensitive
subgroup, Children 1-2 years, is 0.008101 mg/kg bw/day, which is less
than 1% of the cRfD.  There are large margins of safety for all
population groups.

	ii. Drinking water.  The FIRST (Version 1.0) and SCI-GROW (version 2.3)
models were used to estimate conservative concentrations of DPX-E2Y45 in
surface and ground water, respectively.  The highest average annual
surface water value from FIRST, 4.2 ug/L, was used in the DEEM-FCIDTM
software to determine aggregate exposure to food and water on a chronic
basis, since it was higher than the average annual ground water value.
The resultant aggregate exposure values (0.005627 mg/kg bw/day for the
US Population, 0.008232 mg/kg bw/day for Children 1-2 years) were not
significantly greater than the exposure values determined on the basis
of food alone and continue to be less than 1% of the cRfD described
above. The margins of safety for all population groups remain large.

	2. Non-dietary exposure.  There are no residential uses of DPX-E2Y45,
and therefore no need to assess non-dietary exposure.

D. Cumulative Effects

	It is not necessary at this time to consider cumulative effects because
there is no indication that toxic effects of DPX-E2Y45 have a common
mechanism with those of any other chemical compounds.

E. Safety Determination

	1. U.S. population. Based on the risk assessments described above there
is a reasonable certainty that no harm will result to the general
population from the aggregate exposure to DPX-E2Y45.  No additional
safety factors are warranted.

	2. Infants and children. Based on the risk assessments described above
there is a reasonable certainty that no harm will result to the infants
and children from the aggregate exposure to DPX-E2Y45.  No additional
safety factors are warranted.

E. I. DuPont de Nemours & Company
            	DPX-E2Y45

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