[Federal Register Volume 81, Number 188 (Wednesday, September 28, 2016)]
[Proposed Rules]
[Pages 66555-66562]
[FR Doc No: 2016-23442]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

[Docket No. RM16-13-000]

Balancing Authority Control, Inadvertent Interchange, and
Facility Interconnection Reliability Standards

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Commission proposes to approve Reliability Standards BAL-
005-1 (Balancing Authority Control)

and FAC-001-3 (Facility Interconnection Requirements) submitted by the
North American Electric Reliability Corporation.

DATES: Comments are due November 28, 2016.

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

FOR FURTHER INFORMATION CONTACT:
    Syed Ahmad (Technical Information), Office of Electric Reliability,
Division of Reliability Standards, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426, Telephone:
(202) 502-8718<EMAIL_ADDRESS>    Julie Greenisen (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, Telephone:<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
    1. Under section 215 of the Federal Power Act (FPA),\1\ the
Commission proposes to approve Reliability Standards BAL-005-1
(Balancing Authority Control) and FAC-001-3 (Facility Interconnection
Requirements), submitted by the North American Electric Reliability
Corporation (NERC), and to retire Reliability Standards BAL-005-0.2b
(Automatic Generation Control), FAC-001-2 (Facility Interconnection
Requirements), and BAL-006-2 (Inadvertent Interchange). The Commission
also proposes to approve the associated implementation plans, violation
risk factors, and violation severity levels for Reliability Standards
BAL-005-1 and FAC-001-3. Finally, the Commission proposes to approve
three revised definitions for the glossary of terms used in NERC
Reliability Standards (NERC Glossary).
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    \1\ 16 U.S.C. 824(o).
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    2. Proposed Reliability Standards BAL-005-1 and FAC-001-3 will
enhance the reliability of the Bulk-Power System, as compared to
currently-effective Reliability Standards BAL-005-0.2b and FAC-001-2,
by clarifying and consolidating existing requirements related to
frequency control. The proposed Reliability Standards support more
accurate and comprehensive calculation of Reporting Area Control Error
(ACE) by requiring timely reporting of an inability to calculate
Reporting ACE and by requiring balancing authorities to maintain
minimum levels of annual availability of 99.5% for each balancing
authority's system for calculating Reporting ACE.\2\
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    \2\ NERC states that Reporting ACE ``represents a Balancing
Authority Area's [] Area Control Error [] measured in megawatts []
as the difference between the [Balancing Authority Area's] Actual
and Scheduled Net Interchange, plus its Frequency Bias Setting
obligation and meter error corrections. Reporting ACE helps
Responsible Entities provide reliable frequency control by
indicating the current state of the entity's contribution to
Reliability.'' NERC Petition at 3.
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    3. As discussed below, we have questions regarding the proposed
retirement of Requirement R15 of Reliability Standard BAL-005-0.2b,
which requires responsible entities to maintain and periodically test
backup power supplies at primary control centers and other critical
locations. Depending on the explanation received in comments, the
Commission may issue a directive in the final rule to restore the
substance of Requirement R15 in the Reliability Standards. Separately,
we propose to approve NERC's request to retire Reliability Standard
BAL-006-2 upon the latter of the effective date of proposed Reliability
Standard BAL-005-1 and the NERC Operating Committee's approval of an
Inadvertent Interchange Guideline document.

I. Background

A. Mandatory Reliability Standards and Order No. 693 Directive

    4. Section 215 of the FPA requires a Commission-certified Electric
Reliability Organization (ERO) to develop mandatory and enforceable
Reliability Standards that are subject to Commission review and
approval. Specifically, the Commission may approve, by rule or order, a
proposed Reliability Standard or modification to a Reliability Standard
if it determines that the Standard is just, reasonable, not unduly
discriminatory or preferential and in the public interest.\3\ Once
approved, the Reliability Standards may be enforced by NERC, subject to
Commission oversight, or by the Commission independently.\4\
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    \3\ 16 U.S.C. 824o(d)(2).
    \4\ Id. 824o(e).
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    5. Pursuant to section 215 of the FPA, the Commission established a
process to select and certify an ERO,\5\ and subsequently certified
NERC as the ERO.\6\ On March 16, 2007, the Commission issued Order No.
693, approving 83 of the 107 Reliability Standards filed by NERC,
including Reliability Standards BAL-005-0 (Automatic Generation
Control), FAC-001-0 (Facility Interconnection Requirements), and BAL-
006-1 (Inadvertent Interchange).\7\ However, in approving Reliability
Standards BAL-005-0 and BAL-006-1, the Commission directed NERC to
develop modifications to those Reliability Standards through the
standards development process.
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    \5\ Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and
Enforcement of Electric Reliability Standards, Order No. 672, FERC
Stats. & Regs. ] 31,204, order on reh'g, Order No. 672-A, FERC
Stats. & Regs. ] 31,212 (2006).
    \6\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g and compliance, 117 FERC ] 61,126 (2006),
aff'd sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009).
    \7\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, FERC Stats. & Regs. ] 31,242 at PP 420, 439, and 680,
order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
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    6. With respect to Reliability Standard BAL-005-0, the Commission
directed NERC to develop a modification that:

    (1) Develops a process to calculate the minimum regulating
reserve a balancing authority must have at any given time taking
into account expected load and generation variation and transactions
being ramped into or out of the balancing authority; (2) changes the
title of the Reliability Standard to be neutral as to the source of
regulating reserves and to allow the inclusion of technically
qualified DSM and direct control load management; (3) clarifies
Requirement R5 of this Reliability Standard to specify the required
type of transmission or backup plans when receiving regulation from
outside the balancing authority when using non-firm service; and (4)
includes Levels of Non-Compliance and a Measure that provides for a
verification process over the minimum required automatic generation
control or regulating reserves a balancing authority must
maintain.\8\
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    \8\ Id. P 420.

Since then, the Commission has approved one interpretation of
Reliability Standard BAL-005-0 and accepted two errata filings.\9\ The
currently-effective version of the Reliability Standard is BAL-005-
0.2b.
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    \9\ See Modification of Interchange and Transmission Loading
Relief Reliability Standards; and Electric Reliability Organization
Interpretation of Specific Requirements of Four Reliability
Standards, Order No. 713, 124 FERC ] 61,071 (2008); North American
Electric Reliability Corp., Docket No. RD09-2-000 (May 13, 2009)
(delegated letter order); North American Electric Reliability Corp.,
Docket No. RD12-4-000 (Sept. 13, 2012) (delegated letter order).

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    7. With respect to Reliability Standard BAL-006-1, the Commission
directed NERC to develop a modification ``that adds Measures concerning
the accumulation of large inadvertent imbalances and Levels of Non-
Compliance.'' \10\ The Commission explained the need for such a
modification as follows:
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    \10\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 428.

    While we agree that inadvertent imbalances do not normally
affect the real-time operations of the Bulk-Power System and pose no
immediate threat to reliability, we are concerned that large
imbalances represent dependence by some balancing authorities on
their neighbors and are an indication of less than desirable
balancing of generation with load. The Commission also notes that
the stated purpose of this Reliability Standard is to define a
process for monitoring balancing authorities to ensure that, over
the long term, balancing authorities do not excessively depend on
other balancing authorities in the Interconnection for meeting their
demand or interchange obligations.\11\
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    \11\ Id.

Since then, the Commission has approved one revision to Reliability
Standard BAL-006-1 to remove the regional waiver of certain
requirements for the Midwest ISO, following the Midwest ISO's
transition to a single balancing authority model.\12\ The currently-
effective version of the Reliability Standard is BAL-006-2.
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    \12\ See North American Electric Reliability Corp., 134 FERC ]
61,007 (2011).
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B. NERC Petition

    8. On April 20, 2016, NERC filed a petition seeking approval of
proposed Reliability Standards BAL-005-1 (Balancing Authority Control)
and FAC-001-3 (Facility Interconnection Requirements), nine new or
revised definitions associated with the proposed Reliability Standards,
and retirement of currently-effective Reliability Standards BAL-005-
0.2b (Automatic Generation Control), FAC-001-2 (Facility
Interconnection Requirements), and BAL-006-2 (Inadvertent Interchange).
    9. NERC requests that the two revised Reliability Standards and the
revised definitions of Automatic Generation Control, Pseudo-Tie, and
Balancing Authority become effective on the first day of the first
calendar quarter twelve months from the effective date of the
applicable governmental authority's approval of NERC's petition. NERC
also requests that the retirement of Reliability Standard BAL-006-2
become effective upon the latter of the effective date of proposed
Reliability Standard BAL-005-1 and the NERC Operating Committee's
approval of the Inadvertent Interchange Guideline document. For the six
remaining definitions (Reporting ACE and its component definitions--
Actual Frequency, Actual Net Interchange, Scheduled Net Interchange,
Interchange Meter Error, and Automatic Time Error Correction), NERC
requests an effective date of July 1, 2016, to coincide with the
effective date for BAL-001-2.
    10. NERC subsequently withdrew its request for approval of the six
Reporting ACE-related definitions from the instant docket, and filed
for expedited approval of the six definitions in a separate docket. The
six definitions were approved by delegated letter order on June 23,
2016, and are no longer at issue in the instant proceeding.\13\
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    \13\ North American Electric Reliability Corp., Docket No. RD16-
7-000 (June 23, 2016) (delegated letter order).
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    11. NERC explains in its petition that proposed Reliability
Standards BAL-005-1 and FAC-001-3 and the proposed retirement of
Reliability Standard BAL-006-2 came about as part of the second phase
of NERC's project to ``clarify, consolidate, streamline, and enhance
the Reliability Standards addressing frequency control.'' \14\ NERC
indicates in its petition that the standard drafting team developed the
proposed revisions after reviewing applicable Commission directives,
``Paragraph 81'' criteria, and the recommendations of the periodic
review team that examined Reliability Standards BAL-005-0.2b and BAL-
006-2.\15\
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    \14\ NERC Petition at 2 (referencing Project 2010-14.2.1 Phase 2
of Balancing Authority Reliability-based Controls).
    \15\ Id. at 3 (citing North American Elec. Reliability Corp.,
138 FERC ] 61,193 at P 81, order on reh'g and clarification, 139
FERC ] 61,168 (2012); Petition of the North American Electric
Reliability Corporation for Approval of Retirement of Requirements
in Reliability Standards, Docket No. RM13-8-000, at Exhibit A
(``Paragraph 81 Criteria'') (filed Feb. 28, 2013); Electric
Reliability Organization Proposed to Retire Requirements in
Reliability Standards, Order No. 788, 145 FERC ] 61,147 (2013)).
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    12. NERC describes the revisions to Reliability Standard BAL-005-
0.2b as clarifying and refining the current requirements ``for
accurate, consistent, and complete'' Reporting ACE, which is a key
frequency control and reliability indicator.\16\ These revisions
include relocating some of the current requirements of Reliability
Standard BAL-005-0.2b, which relate to confirming that facilities are
within a balancing authority's metered boundary, into the proposed
Facility Interconnection Requirements Reliability Standard, FAC-001-3.
In addition, NERC proposes to relocate Requirement R3 of currently-
effective Reliability Standard BAL-006-2 into proposed Reliability
Standard BAL-005-1, explaining that the requirement relates to ensuring
that balancing authorities use consistent data sources to calculate
Reporting ACE, and therefore more properly belongs in Reliability
Standard BAL-005.
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    \16\ Id.
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    13. NERC explains that the proposed Reliability Standards
``represent substantial improvements over existing Reliability
Standards by helping to support more accurate and comprehensive
calculation of Reporting ACE and satisfying all remaining Commission
directives for Reliability Standards BAL-005 and BAL-006.'' \17\
Further, NERC maintains that proposed Reliability Standard BAL-005-1 is
an improvement over the currently-effective version, BAL-005-0.2b,
because it ``consolidates unnecessary or repetitive Requirements and
moves certain metrics for calculating Reporting ACE to the revised,
proposed definition of Reporting ACE.'' \18\ Among other things, NERC
proposes to move requirements applicable to generator operators and
transmission operators in currently-effective Reliability Standard BAL-
005-0.2b, into a more appropriate standard, explaining that ``[a]s the
purpose of FAC-001-3 is more commensurate with interconnection
responsibilities, interconnection procedures contained in currently
effective BAL-005-0.2b should be included in proposed Reliability
Standard FAC-001-3.'' \19\
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    \17\ Id. at 12.
    \18\ Id. at 13.
    \19\ Id. at 23.
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    14. In addition, NERC asserts that proposed Reliability Standard
BAL-005-1 improves on the currently-effective version of the
Reliability Standard because proposed Requirement R2 clarifies the
performance expectations for notification to reliability coordinators
when a balancing authority is unable to calculate Reporting ACE for 30
minutes or more,\20\ and Requirement R5 ``introduces a new obligation .
. . to assure the availability of a BA's system used to calculate
Reporting ACE,'' requiring a minimum availability of 99.5% in each
calendar year.\21\
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    \20\ Id. at 16.
    \21\ Id. at 19.
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    15. NERC states that the proposed package of revisions reflected in
its petition address the outstanding directives related to Reliability
Standards BAL-005 and BAL-006 from Order No. 693. Specifically, NERC
states that the title of Reliability Standard

BAL-005-1 has been modified from Automatic Generation Control to
Balancing Authority Control ``to reflect the connection to Reporting
ACE and resource-neutral requirements.'' \22\ In addition, NERC
indicates that it has revised the definition of Automatic Generation
Control to ensure a resource-neutral process for controlling demand and
resources.\23\
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    \22\ Id. at 13 (referencing Order No. 693, FERC Stats. & Regs. ]
31,242 at P 404, and noting that the Commission's directive related
to resource-neutrality for regulating reserves is now moot, as
Requirement R2 of Reliability Standard BAL-005-0.2b, which required
entities to maintain regulating reserves, has been retired).
    \23\ Id. at n.39.
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    16. NERC states that the requirements of proposed Reliability
Standard BAL-005-1 all have a ``medium'' violation risk factor, thereby
addressing the Commission's directive to revise the violation risk
factor for Reliability Standard BAL-005-0, Requirement R17 to
``medium.'' \24\ Similarly, NERC asserts that it has met the directive
to consider Xcel and FirstEnergy's comments about the scope of
Requirement R17, which set minimum accuracy requirements for time error
and frequency devices, by retiring part of the currently-effective
requirement and moving the minimum accuracy requirements into
Requirement R3 of Reliability Standard BAL-005-1. NERC maintains that
this has ``streamlined obligations to use specific frequency metering
equipment that is necessary for operation of [automatic generation
control (AGC)] and accurate calculation of Reporting ACE, as this
ensures that costs associated with implementation are commensurate with
reliability benefit.'' \25\
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    \24\ Id. at 17; see also North American Elec. Reliability Corp.,
121 FERC P 61,179 at P 58 (2007).
    \25\ Id. at 18.
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    17. NERC proposes to move Requirement R3 from currently-effective
Reliability BAL-006-2 into proposed Reliability Standard BAL-005-1, but
proposes to retire the rest of the requirements of Reliability Standard
BAL-006-2 (Requirements R1, R2, R4, and R5). NERC states that the
standard drafting team determined that, aside from Requirement R3, each
of the requirements in Reliability Standard BAL-006-2 are ``energy
accounting standards'' and/or are ``administrative'' in nature, and
should accordingly be retired.\26\
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    \26\ Id. at 25-26.
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    18. While NERC acknowledges that the Commission previously directed
it to develop measures concerning the accumulation of large inadvertent
imbalances, based on the Commission's concern that large imbalances may
indicate an underlying problem, NERC explains that the requirements of
Reliability Standard BAL-001-2, which require balancing authorities to
maintain clock-minute ACE within the Balancing Authority ACE Limit, as
well as the requirements of Reliability Standard BAL-003-1 and proposed
Reliability Standard BAL-002-2, which require entities to restore
Reporting ACE within predefined bounds, prevent any excessive
dependency on other entities. As NERC explains in its petition:

    Because entities are supporting frequency through this
coordinated suite of reliability standards, entities will not
excessively depend on other entities in the Interconnection such
that the purely economic issue that was addressed by BAL-006-2
becomes a reliability issue for a NERC Reliability Standard.\27\
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    \27\ Id. at 27.

    19. In order to address ``any remaining or potential concerns with
retirement of BAL-006-2,'' NERC proposes that the retirement become
effective only upon the Operating Committee's approval of an
Inadvertent Interchange Guideline document.\28\ NERC states that the
Inadvertent Interchange Guideline document was based on a white paper
developed by the standard drafting team for Reliability Standards BAL-
005 and BAL-006, and maintains that it provides an in-depth
justification for why a NERC Reliability Standard is not necessary for
inadvertent interchange.
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    \28\ The Inadvertent Interchange Guideline document is expected
to be presented to the NERC Operating Committee in mid-September
2016, and will be posted for a 45-day comment period.
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    20. With respect to the three proposed definitions that remain at
issue in this proceeding, NERC explains that (1) ``Automatic Generation
Control'' has been revised to set forth a resource-neutral process for
controlling demand and resources; (2) ``Pseudo-Tie'' has been updated
to reflect the use of the term ``Reporting ACE''; and (3) ``Balancing
Authority'' has been revised to more accurately describe a balancing
authority's resource demand function.

C. NERC Supplemental Filing

    21. On June 14, 2016, NERC submitted supplemental information in
support of its April 20, 2016 petition (Supplemental Filing), to
provide additional explanation and support for the retirement of
Requirement R15 in currently-effective Reliability Standard BAL-005-
0.2b.\29\ In its Supplemental Filing, NERC maintains that Requirement
R15 should be retired because the objectives of that requirement (i.e.,
to ensure the continued operation of AGC and certain data recording
equipment during the loss of normal power supply) are being addressed
through other Reliability Standards and requirements. Specifically,
NERC maintains that Reliability Standard EOP-008-1 requires a balancing
authority to have a backup control center facility and an operating
plan that allows it to meet its functional obligations with regard to
the reliable operation of the bulk electric system in the event that
its primary control center functionality is lost.\30\
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    \29\ As NERC notes in its Supplemental Filing, NERC stated in
its initial petition that ``Requirements R2, R7 and R15 . . . are
redundant, ineffective, and should be retired based on Commission-
approved Paragraph 81 Criteria.'' NERC Supplemental Filing at 1
(quoting April 20 Petition at 15).
    \30\ NERC Supplemental Filing at 2.
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    22. In addition, NERC maintains that the proposed performance
requirements of Requirement R3 of Reliability BAL-005-1, which would
require balancing authorities to ``use frequency metering equipment for
the calculation of Reporting ACE that is available a minimum of 99.95%
of each calendar year,'' will help to ensure that balancing authorities
can continuously operate the equipment necessary for the calculation of
Reporting ACE, effectively eliminating the need for Requirement
R15.\31\
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    \31\ Id. at 4.
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II. Discussion

    23. Pursuant to FPA section 215(d)(2), we propose to approve
Reliability Standards BAL-005-1 and FAC-001-3 as just, reasonable, not
unduly discriminatory or preferential, and in the public interest.
Proposed Reliability Standard BAL-005-1 and FAC-001-3 will enhance
reliability as compared to currently-effective Reliability Standards
BAL-005-0.2b and FAC-001-2, because the proposed Reliability Standards
clarify and consolidate existing requirements related to frequency
control. In addition, proposed Reliability Standard BAL-005-1 supports
more accurate and comprehensive calculation of Reporting ACE by
requiring timely reporting of an inability to calculate Reporting ACE
(Requirement R2) and by requiring minimum levels of availability and
accuracy for each balancing authority's system for calculating
Reporting ACE (Requirement R5).
    24. We also propose to approve the violation risk factors and
violation severity levels associated with Reliability Standards BAL-
005-1 and FAC-001-3; the proposed revisions to the definitions of
Automatic Generation Control, Pseudo-Tie, and Balancing Authority; the
proposed retirement of

Reliability Standards BAL-005-0.2b, FAC-001-2, and BAL-006-2 in
accordance with NERC's implementation plan; and NERC's implementation
plans for proposed Reliability Standards BAL-005-1 and FAC-001-3.
    25. As discussed below, the Commission seeks comment from NERC and
other interested entities regarding the retirement of Requirement R15
of Reliability Standard BAL-005-0.2b, which requires responsible
entities to maintain and periodically test backup power supplies at
primary control centers and other critical locations. Depending on the
explanation received in the comments, the Commission may issue a
directive in the final rule requiring NERC to restore this requirement
through the standards development process.

A. Retirement of Reliability Standard BAL-005-0.2b, Requirement R15

    26. Proposed Reliability Standard BAL-005-1 would eliminate
currently-effective Requirement R15 from the standard, which states as
follows:

    The Balancing Authority shall provide adequate and reliable
backup power supplies and shall periodically test these supplies at
the Balancing Authority's control center and other critical
locations to ensure continuous operation of AGC and vital data
recording equipment during loss of the normal power supply.

    27. NERC contends that Requirement R15 should be retired because it
is ``redundant'' and ``ineffective,'' and points to a number of other
Reliability Standards and requirements that, NERC maintains, achieve
the same objective as Requirement R15. Specifically, NERC explains that
requirements in Reliability Standard EOP-008-1 (Loss of Control Center
Functionality) and the performance requirements of Requirement R3 in
proposed Reliability Standard BAL-005-1 address the same objectives as
existing Requirement R15 (i.e., to ensure the continued operations of
AGC and certain data recording equipment during the loss of normal
power supply).\32\
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    \32\ Id. at 2-4.
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    28. NERC contends that Reliability Standard EOP-008-1 requires a
balancing authority to have a backup control center facility and an
operating plan that allows it to meet its functional obligations with
regard to the reliable operation of the bulk electric system in the
event that its primary control center functionality is lost. NERC
asserts that these requirements effectively address the same
reliability objective as Reliability Standard BAL-005-0.2b Requirement
R15 because a balancing authority's ``functional obligations regarding
reliable operations'' \33\ include the continuous operation of AGC and
the data recording equipment necessary to balance generation and load.
Further, NERC contends that Requirement R7 of Reliability Standard EOP-
008-1 requires balancing authorities to test their operating plans
annually to demonstrate the viability of their backup functionality.
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    \33\ Id. at 3.
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    29. NERC maintains that the proposed performance requirements in
Requirement R3 of Reliability Standard BAL-005-1, which require
balancing authorities to ``use frequency metering equipment for the
calculation of Reporting ACE that is available a minimum of 99.95% of
each calendar year,'' will help ensure that balancing authorities can
continuously operate the equipment necessary for the calculation of
Reporting ACE. NERC notes that if a balancing authority ``fails[s] to
have adequate and reliable backup power supplies at its control center
to ensure continuous operation of its AGC and vital data recording
equipment, the Balancing Authority risks violation of the performance
obligation in proposed Reliability Standard BAL-005-1, Requirement R3
if its normal power supply is lost.'' \34\
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    \34\ Id. at 4-5.
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Commission Request for Comments
    30. We recognize that the approach taken in revised Reliability
Standard BAL-005-1, combined with the requirements of Reliability
Standard EOP-008-1, represents a more performance-based approach to
maintaining functionality for reliable operation of the interconnected
bulk electric system, including ensuring the continued operation of AGC
and certain data recording equipment during the loss of normal power
supply, compared to the more specific approach of Requirement R15 in
Reliability Standard BAL-005-0.2b. Moreover, balancing authorities
currently appear to be the only type of functional entity explicitly
required to have and to test adequate and reliable backup supply at
critical locations. For example, there is no provision parallel to
Requirement R15 that reliability coordinators or transmission operators
provide ``adequate and reliable backup power supplies'' at their
primary control centers and ``other critical locations.''
    31. Nonetheless, after considering NERC's Petition and Supplemental
Filing addressing the matter, we continue to have questions as to
whether the objectives of Requirement R15 are met, as NERC contends, by
other requirements in Reliability Standard EOP-008-1 and proposed
Reliability Standard BAL-005-1. In particular, Requirement R15 of
currently-effective Reliability Standard BAL-005-0.2b helps to ensure
continued operability of balancing authorities' primary control
centers, despite the loss of normal power supply, without evacuation to
or activation of backup control centers. Thus, this provision appears
to provide additional robustness in the primary control center and
mitigates the risk of problems occurring in the transition to a
secondary control center. We also note that NERC's Independent Expert
Review Project (IERP) report did not include Requirement R15 among the
requirements recommended for retirement when it reviewed Reliability
Standard BAL-005-0.2b in 2013.\35\ While the IERP report explicitly
recommended retiring other provisions of Reliability Standard BAL-005-
0.2b, it recommended retaining Requirement R15 as part of the Future
Enforceable Set of requirements.\36\
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    \35\ Standards Independent Experts Review Project at 26, http://www.nerc.com/pa/Stand/Resources/Documents/Standards_Independent_Experts_Review_Project_Report.pdf.
    \36\ Id. at 1.
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    32. Accordingly, we are not persuaded based on the current record
that it is appropriate to eliminate balancing authorities' existing
obligation to have and periodically test backup power supply at a
primary control center. We, therefore, seek additional justification
for the retirement of Requirement R15 of Reliability Standard BAL-005-
0.2b. Specifically, the Commission seeks comment on the benefits and
potential burden of retaining Requirement R15. We also seek an
explanation as to why, historically, there is no parallel to
Requirement R15 for reliability coordinators and transmission
operators, and whether any reason exists to distinguish between
balancing authorities and other entities, such as reliability
coordinators and transmission operators, that may operate a control
center or critical facility with respect to the need for backup power
supply and testing at such locations.
    33. The Commission further seeks comment on the following
questions:

    1. If Requirement R15 of Reliability Standard BAL-005-0.2b is
retired, can balancing authorities comply with Reliability Standard
EOP-008-1 by having a primary control center and ``backup
functionality'' without a backup power supply at the primary control
center or without a backup

power supply at the location providing backup functionality? Are
reliability coordinators and transmission operators compliant with
Reliability Standard EOP-008-1 by having a primary control center
and ``backup functionality'' without a backup power supply at the
primary control center or without a backup power supply at the
location providing backup functionality?
    2. Explain the benefits and potential burdens for the reliable
operation of the bulk electric system in having a backup power
supply at the primary control center. Is it more appropriate to have
backup power supply sited at a location providing backup
functionality? Does the potential impact to reliability change if
the entity is a reliability coordinator or transmission operator?
    3. Describe current practices with respect to the availability
of backup power supplies at primary control centers and other
critical locations. In particular, do any reliability coordinators,
transmission operators, or balancing authorities currently have a
primary control center without a backup power supply?
    4. What does the reference in Reliability Standard BAL-005-0.2b
Requirement R15 to ``other critical locations'' include? Does it
include facilities beyond primary control centers and locations
providing backup functionality?
    5. Does the use of frequency metering equipment to calculate
Reporting ACE that is available a minimum of 99.95% of each calendar
year, as proposed in Reliability Standard BAL-005-1, Requirement R3,
ensure ``continuous operation of AGC and vital data recording
equipment during loss of the normal power supply,'' per Reliability
Standard BAL-005-0.2b, Requirement R15? What other functions would
be included as part of the metering equipment and data collection of
Reliability Standard BAL-005-1, Requirement R3? What functions
currently part of Reliability Standard BAL-005-0.2b, Requirement R15
would be omitted?
    6. Do the requirements in Reliability Standard EOP-008-1 for
backup functionality ensure the ``continuous operation of AGC and
vital data recording equipment,'' and the ability to collect data to
calculate Reporting ACE, in the case of the unavailability of such
equipment for a period within the bounds of proposed Reliability
Standard BAL-005-1, Requirement R3?

III. Information Collection Statement

    34. The Paperwork Reduction Act (PRA) \37\ requires each federal
agency to seek and obtain Office of Management and Budget (OMB)
approval before undertaking a collection of information directed to ten
or more persons, or contained in a rule of general applicability. The
OMB regulations require that OMB approve certain reporting and
recordkeeping (collections of information) imposed by an agency.\38\
Upon approval of a collection(s) of information, OMB will assign an OMB
control number and expiration date. Respondents subject to the filing
requirements of this rule will not be penalized for failing to respond
to these collections of information unless the collections of
information display a valid OMB control number.
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    \37\ 44 U.S.C. 3501-3520.
    \38\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    35. The Commission is submitting these reporting and recordkeeping
requirements to OMB for its review and approval under section 3507(d)
of the PRA. Comments are solicited on the Commission's need for this
information, whether the information will have practical utility, the
accuracy of the provided burden estimate, ways to enhance the quality,
utility, and clarity of the information to be collected, and any
suggested methods for minimizing the respondent's burden, including the
use of automated information techniques.
    36. This Notice of Proposed Rulemaking (NOPR) proposes to approve
revisions to Reliability Standards BAL-005, associated with FERC-725R
and FAC-001, associated with FERC-725D. These proposed revisions
streamline and clarify the current requirements related to the
calculation of Reporting ACE--a key frequency control and reliability
indicator factor--including consolidating the seventeen requirements of
currently-effective BAL-005-0.2b, associated with FERC-725R, into seven
requirements in BAL-005-1, relocation of certain requirements related
to interconnection requirements for transmission owners and generation
owners into FAC-001-3, relocation of Requirement R3 in currently-
effective BAL-006-2 into proposed BAL-005-1, and relocation of certain
metrics and calculations required for calculating Reporting ACE into
the NERC definition of Reporting ACE and its component definitions.
    37. NERC's proposed revisions to Reliability Standards BAL-005 and
FAC-001will not result in an increase in the record-keeping and
reporting requirements imposed on balancing authorities, other than the
one-time cost of administering the change to the revised standard. All
other recordkeeping and reporting obligations imposed on balancing
authorities under the revised requirements essentially track those that
already exist under currently-effective Reliability Standards BAL-005-
0.2b and FAC-001-2. The proposed revisions to FAC-001-3 will result in
a limited increase in the record-keeping and reporting requirements
imposed on those transmission owners and generator owners that are not
also transmission operators and generator operators (about 198 entities
in the United States), as shown in the chart below.\39\ Many of the
revisions to the Reliability Standards reflected in this NOPR were
developed to help clarify and streamline existing requirements related
to calculation of Reporting ACE, and are expected to simplify these
entities' overall burden with respect to recordkeeping, reporting, and
compliance. Moreover, the NOPR proposes to allow the retirement of the
bulk of the requirements in Reliability Standard BAL-006-2, further
reducing the overall record-keeping and reporting requirements for
balancing authorities. Accordingly, the Commission estimates that the
overall change in the record-keeping and reporting requirements as a
result of this rulemaking will be de minimis on a per-entity basis.
---------------------------------------------------------------------------

    \39\ Proposed Reliability Standard FAC-001-3 replaces and
strengthens currently effective Reliability Standard FAC-001-2 by
moving currently effective Requirement R1 of Reliability Standard
BAL-005-0.2b to proposed Reliability Standard FAC-001-3, requiring
that transmission owner and generator owner interconnection
requirements include procedures for confirming that new or
materially modified facilities connecting to the bulk electric
system are within a balancing authority's metered boundaries. NERC
explains that these interconnection requirements should be relocated
to Reliability Standard FAC-001-3, as FAC-001-3 establishes facility
interconnection requirements.
---------------------------------------------------------------------------

    38. Public Reporting Burden: The changes reflected in proposed
Reliability Standard BAL-005-1 are not expected to result in an
increase in the annual record-keeping and reporting requirements on
applicable entities (balancing authorities). However, balancing
authorities will have to perform a one-time review of the new standard
to ensure that their compliance practices (including record-keeping)
are consistent with the revised requirements. The relocation of
Requirement R1 of Reliability Standard BAL-005-0.2b into Reliability
Standard FAC-003-1 will result in an increase in the number of entities
subject to the requirement, as the requirement will be applicable to
transmission owners and generator owners rather than transmission
operators and generator operators. This limited increase in annual
record-keeping and reporting burden, along with the one-time burden of
administering the change from BAL-005-0.2b to BAL-005-1, is however
expected to be offset to some extent by the decrease in record-keeping
and reporting burden associated with the retirement of Reliability
Standard BAL-006-2 (in considering the overall record-keeping and
reporting requirements associated with the revised Reliability
Standards).

----------------------------------------------------------------------------------------------------------------
                                                                                Average     Annual  burden
 Data collection  FERC 725D &      Number of        Number of      Total number    burden hours   hours  & total
725R  (modifications in  RM16- respondents \40\   responses  per   of responses     & cost per     annual  cost
           13-000)                                  respondent                     response \41\       \42\
                               (1).............  (2)............     (1) x (2) =             (4)     (3) x (4) =
                                                                             (3)                             (5)
----------------------------------------------------------------------------------------------------------------
BAL-005-1 (FERC-725R)........  BA 105..........  1 (one-time)...             105               1             105
                                                                                $95.35         $10,325
FAC-001-3 R3 (FERC-725D).....  GO/TO 198 \43\..  1 (annual).....             198               1  ..............
                                                                                \44\ $63.25      $12,523.50
Retirement of current          BA 105..........  -1 (annual)....            -105              -1             105
 standard BAL-006-02                                                                     -$31.15      -$3,270.75
 currently in (FERC-725R).
                                                                 -----------------------------------------------
    Total....................  ................  ...............  ..............  ..............      $19,577.75
----------------------------------------------------------------------------------------------------------------

    Title: FERC-725D, Mandatory Reliability Standards: FAC Reliability
Standards; FERC-725R, Mandatory Reliability Standards: BAL Reliability
Standards
---------------------------------------------------------------------------

    \40\ The estimated number of respondents is based on the NERC
compliance registry as of August 12, 2016. According to the NERC
compliance registry, there are 70 U.S. balancing authorities (BA) in
the Eastern Interconnection, 34 balancing authorities in the Western
Interconnection and one balancing authority in the Electric
Reliability Council of Texas (ERCOT).
    \41\ The burden hours and cost are based on the hourly cost for
an engineer for BAL-005-1, the average of the hourly cost for an
engineer and clerical staff for FAC-001-3, and the hourly cost for
clerical staff for changes associated with the retirement of BAL-
006-2.
    \42\ For purposes of determining the overall annual cost of the
record-keeping and reporting changes reflected in this NOPR, the
one-time cost associated with administering the change to BAL-005-1
is being treated as an annual cost.
    \43\ Per the NERC compliance registry, there are 56 generator
owners (GO) that are not also generator operators and 142
transmission owners (TO) that are not also transmission operators,
for a total of 198 new entities in the United States subject to FAC-
001-3 Requirement R3.
    \44\ The project cost per response for record-keeping and
reporting associated with the revisions in FAC-001-3 reflect an
average of the hourly cost for an engineer and for clerical staff.
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    Action: Proposed Revisions.
    OMB Control No: 1902-0247 (FERC-725D); 1902-0268 (FERC-725R).
    Respondents: Business or other for-profit and not-for-profit
institutions.
    Frequency of Responses: On-going.
    Necessity of the Information: The Commission has reviewed the
requirements of Reliability Standards BAL-005-1 and FAC-001-3 and has
made a determination that the requirements of these Reliability
Standards are necessary to implement section 215 of the FPA.
    Internal Review: The Commission reviewed the proposed Reliability
Standards and made a determination that its action is necessary to
implement section 215 of the FPA. The Commission has assured itself, by
means of its internal review, that there is specific, objective support
for the burden estimates associated with the information requirements.
    39. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, email:
<EMAIL_ADDRESS>phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>].
    40. For submitting comments concerning the collection(s) of
information and the associated burden estimate(s), please send your
comments to the Commission and to the Office of Management and Budget,
Office of Information and Regulatory Affairs, Washington, DC 20503
[Attention: Desk Officer for the Federal Energy Regulatory Commission,
phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>]. For security reasons,
comments to OMB should be submitted by email to:
<EMAIL_ADDRESS>Comments submitted to OMB should include
FERC-725R and Docket Number RM16-13-000.

IV. Environmental Analysis

    41. 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.\45\ 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.\46\ The actions proposed here
fall within this categorical exclusion in the Commission's regulations.
---------------------------------------------------------------------------

    \45\ Regulations Implementing National Environmental Policy Act
of 1969, Order No. 486, FERC Stats. & Regs., ] 30,783 (1987).
    \46\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Certification

    42. The Regulatory Flexibility Act of 1980 (RFA) \47\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking. It
only requires consideration of alternatives that are less burdensome to
small entities and an agency explanation of why alternatives were
rejected. The Small Business Administration (SBA) revised its size
standard effective January 22, 2014 for electric utilities from a
standard based on megawatt hours to a standard based on the number of
employees, including affiliates. Under SBA's size standards, some
balancing authorities, generation owners, and transmission owners will
fall under the following category and associated size threshold:
Electric bulk power transmission and control, at 500 employees.\48\
---------------------------------------------------------------------------

    \47\ 5 U.S.C. 601-612.
    \48\ 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121
(Electric Bulk Power Transmission and Control).
---------------------------------------------------------------------------

    43. As noted above, the Commission estimates a very limited, one-
time increase in record-keeping and reporting burden on balancing
authorities due to the changes in the revised Reliability Standards,
with no other increase in the cost of compliance. Approximately 24 of
the 105 balancing authorities are expected to meet the SBA's definition
for a small entity. In addition, approximately 198 entities will be
subject to new record-keeping and reporting requirements under revised
Reliability Standard FAC-001-3, with no other increase in the cost of
compliance. Approximately 177 of these entities are expected to meet
the SBA's definition of a small entity.
    44. Even assuming that the one-time cost of compliance for
administering the change from Reliability Standard BAL-005-0.2b to BAL-
005-1 is an annual

cost, and assuming that all of the affected entities qualify as small
entities, the total annual cost to the industry as a whole is minimal
($19,577.75), and the average cost per affected entity is $63.23.
    45. According to SBA guidance, the determination of significance of
impact ``should be seen as relative to the size of the business, the
size of the competitor's business, and the impact the regulation has on
larger competitors.'' \49\ The Commission does not consider the
estimated burden to be a significant economic impact. As a result, the
Commission certifies that the reforms proposed in this NOPR would not
have a significant economic impact on a substantial number of small
entities.
---------------------------------------------------------------------------

    \49\ U.S. Small Business Administration, A Guide for Government
Agencies: How to comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

VI. Comment Procedures

    46. The Commission invites interested persons to submit comments on
the matters and issues proposed in this notice to be adopted, including
any related matters or alternative proposals that commenters may wish
to discuss. Comments are due November 28, 2016. Comments must refer to
Docket No. RM16-13-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments.
    47. 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.
    48. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
    49. 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.

VII. Document Availability

    50. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
    51. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
    52. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
    By direction of the Commission.

    Issued: September 22, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2016-23442 Filed 9-27-16; 8:45 am]
 BILLING CODE 6717-01-P


8 1 8. Responses to Comments EPA Region 8 ( Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming) 8 2 Comment: 1047 1 Region: 8 State: MT Area: Libby, MT Comment: Governor Martz disagrees with EPA's intention to identify the entire state as a single attainment Section 107( d) area with the exception of Lincoln County. She is disappointed by EPA's position as the State of Montana has committed considerable resources in developing the appropriate method for defining Section 107( d) areas that best suits Montana's unique mix of sources, meteorology, and geography. She reiterates Montana's original recommendation. She submits additional information illustrating the PM2.5 attainment/ unclassifiable areas defined by the Universal Transverse Mercator ( UTM) coordinate system using 10,000 meter grid intervals and additional information clarifying Montana's intended use of the UTM Grid coordinate system for describing PM2.5 attainment Section 107( d) areas and for potential tracking of increment within baseline areas.

Governor Martz disagrees with EPA that defining attainment area boundaries for purposes of increment tracking is premature. In fact, planning for PM2.5 increment tracking as part of the initial designation process is appropriate and has been approved by EPA for another Region 8 state. In closing, the governor expresses adamant opposition to EPA's intended action to modify the Section 107( d) attainment areas from Montana's original geographic area descriptions. Designation of the entire state results in one unmanageable Section 107( d) attainment area.

EPA Response: EPA's initial recommendation was to designate the entire state of Montana as one single attainment/ unclassifiable area. However, based on recent conversations with the State and a letter from the State dated November 10, 2004 in which the State modified their recommendation to designate attainment/ unclassifiable areas using county boundaries, EPA has agrees to define the attainment/ unclassifiable areas in Montana on a county by county basis, consistent with the EPA's 8 hour ozone designations. At this time it would be premature to subdivide the entire State into over 4,000 10 km by 10 km squares, as Montana has recommended. While the state continues to assert that the rest of state or even county by county delineation is unmanageable for tracking increment consumption, it has been used in many states for many years. We have also made designations based on county boundaries and states have used these boundaries to track increment consumption for many years as well. On the other hand, we are concerned that the creation of 4,000 plus attainment/ unclassifiable areas could make it difficult to effectively track increment consumption. We are also concerned about the general policy and legal implications for the PSD program. We have never dealt with the subdividing of a state on this scale, and we are not prepared to do so until we have had a sufficient chance to determine the adequacy of such an approach.

In reaching our decision, we have carefully considered Montana's response to our July 20, 2004 letter as well as discussions that followed this letter. Based on Montana's response, we are relatively comfortable with the use of Universal Transverse Mercator 8 3 ( UTM) coordinates to define geographic boundaries. As Montana points out, we have approved the use of UTM coordinates to define other designation boundaries in Montana.

Montana's response, however, has not convinced us ( 1) that the extent of subdividing proposed by Montana is appropriate to a PM2.5 increment that has not been established, ( 2) that Montana could effectively track increment consumption in multiple baseline areas with multiple baseline dates, ( 3) that the proposed level of subdivision is consistent with the purposes of the PSD program.

At this point, we don't know which pollutants or precursors would have to be tracked under an increment for PM2.5 or at what level such an increment or significant ambient impacts would be set. We have no basis to conclude that thousands of attainment/ unclassifiable areas 10,000 meters on a side would be appropriate for PM2.5.

Montana indicates it currently tracks increment consumption in approximately 40 baseline areas. Montana makes no projection of the number of baseline areas that might result if its recommendations were accepted. Theoretically, with a starting point of over 4,000 separate attainment/ unclassifiable areas, hundreds or perhaps even thousands of baseline areas could result. The state has presented no evidence that it could effectively administer tracking of increment consumption in so many areas.

We note that Montana previously requested the redesignation of its attainment areas for other pollutants into 10,000 meter by 10,000 meter squares across the entire state. EPA, per a December 13, 2000 memorandum signed by John Seitz, then head of EPA's Office of Air Quality Planning and Standards, stated concerns regarding Montana's and other states' requests and a need for EPA to reexamine its relevant rules and policies. Among other things, the Seitz memo stated a concern that redesignating PSD baseline areas to only encompass the impact area of a PSD source " could allow for unexamined growth in emissions, with possible deterioration of air quality up to the level of the National Ambient Air Quality Standards ( NAAQS.)" The Seitz memo went on to state that the " proposed actions do not appear to be consistent with Congressional intent or the PSD mandates of the Act, as allowing baseline areas of such size might jeopardize air quality and could be difficult to administer in some cases." Montana's February 25, 2004 and August 30, 2004 recommendations for PM2.5 designations are analogous to the redesignations the Seitz memo addressed.

While the Governor indicates we are being inconsistent in our treatment of other states, we note that Utah and Wyoming's situations are distinguishable from Montana's. Wyoming primarily recommended county boundaries to define attainment/ unclassifiable areas for PM2.5, with further subdivision based on the boundaries of a limited number of cities and towns. This is not equivalent to Montana's recommendation to establish over 4,000 separate attainment/ unclassifiable areas. Wyoming's recommendation is largely equivalent to the use of county boundaries to define attainment/ unclassifiable areas that we've historically been willing to accept and that states have used to track increment consumption. As stated above, EPA and the State of Montana recently came to an agreement to identify attainment/ unclassifiable areas on a county by county basis. 8 4 We recently learned that when we issued our July 20, 2004 letter stating our agreement with the State of Utah's recommended attainment/ unclassifiable area boundaries, we misinterpreted Utah's recommendation. While we thought that Utah was primarily recommending designations according to county boundaries, with some smaller areas covering metropolitan areas along the Wasatch Front, Utah was actually recommending designations by township boundaries. Townships are six mile by six mile squares. Thus, Utah's original recommendation would have resulted in thousands of separate attainment/ unclassifiable areas within the State.

However, in recent discussions, EPA and Utah have come to agree that EPA's original interpretation of Utah's recommended boundaries is appropriate at this time. As with Wyoming, attainment/ unclassifiable boundaries in Utah are being defined largely by county boundaries, with subdivision of a limited number of counties along the Wasatch Front into two areas. This is not equivalent to Montana's initial recommendation which recommended 4,000 10 km by 10 km squares. We note that EPA has committed to work with Utah in the future to define a process for identifying boundary areas for when a major source locates in an area.

Montana indicated that tracking increment consumption within county boundaries would provide little advantage over entire state designations due to the large size of counties in Montana and the diverse topography. However, Utah, Wyoming and other states in Region 8 and across the country could make similar claims. As we explained in response to comments regarding the boundary designations for Utah and Wyoming, we believe the boundary designations we're making for Utah and Wyoming will allow for adequate tracking of increment consumption and be consistent with the purposes of the PSD program.

Given our actions on Wyoming, Utah, and the other Region 8 states, Montana has not been singled out. Also, because we have not established a PM2.5 increment, the State should not face any immediate effects from our decision. Before we establish a PM2.5 increment, we can revisit this issue. At that time, we would have a better sense of the implications of Montana's proposal for PM2.5 specifically. In the meantime, it would be appropriate to further study the possible effects of subdividing the State into many, many small attainment/ unclassifiable areas. We welcome Montana's input on these issues.

Comment: 1012 1 Region: 8 State: MT | WY | UT Area:

Comment: 1st Comment: Commenters express concern about the recommendations that several western states have made to designate unreasonably small areas as nonattainment/ unclassifiable areas for PM2.5. Montana, Utah, and Wyoming recommended dividing the portions of their states that were not designated as nonattainment for PM2.5 into many attainment/ unclassifiable areas. Commenters suggest that these state proposals would undermine the Clean Air Act's prevention of significant 8 5 deterioration ( PSD) program. The commenters disagree with EPA's intended approval of Utah and Wyoming's recommended designations. If EPA fails to disallow the recommendations, it will disregard Congress's intent to protect existing air quality that is better than the NAAQS through PSD, since failing to trigger PSD increment protections in significant portions of these states would result in those areas simply being governed by the NAAQS. The designation of PM2.5 areas based on arbitrary grid or jurisdictional boundaries within a state would also constitute arbitrary and capricious action because such boundaries bear no conceivable relationship to any of the relevant requirements or purposes of the CAA. In order to make PSD protections meaningful, EPA should promulgate PSD regulations for PM2.5 as required under Section 166 of the CAA.

2nd Comment: The commenter believes that EPA's action approving the states' request is premature and arbitrary and capricious. Congress pointedly required EPA to issue regulations to prevent significant deterioration of air quality for PM2.5 in tandem with or prior to the air quality status designations under section 107. This reflects the obvious interlocking statutory linkages between the PSD program and the 107 designations. We respectfully request that EPA swiftly carry out its long overdue statutory responsibility to issue PSD regulations for PM2.5 and reject or at the very least hold in abeyance any final action on Utah and Wyoming as well as Montana's recommendations until it has promulgated the framework regulations required to prevent significant deterioration with respect to PM2.5, so that the implications of the proposed boundaries can be meaningfully assessed.

EPA Response: EPA's Response to 1st Comment: We are approving Wyoming's recommendation for attainment/ unclassifiable boundaries based on the boundaries of counties and ten cities/ towns. For Utah, we are defining attainment/ unclassifiable boundaries as county boundaries, with the exception of a limited number of counties along the Wasatch Front, which are being divided in two. 1 For Montana we are approving a recommendation for attainment/ unclassifiable boundaries based on the boundaries of county by county. We believe this is reasonable for the following reasons.

First, while attainment areas have often been delineated as " rest of state", we have also commonly used county boundaries to designate attainment/ unclassifiable areas. For example, for TSP, county by county designations were used for the states of Kentucky and Kansas. In certain limited instances, we have redesignated portions of counties as separate attainment/ unclassifiable areas. For example, in the Powder River Basin, parts of Converse and Campbell Counties, Wyoming are designated separate attainment/ unclassifiable areas for PM10.

There is no requirement in the CAA or our regulations that attainment/ unclassifiable areas encompass an entire state. Second, Utah and Wyoming's further limited delineation of areas within a county should not unreasonably complicate the tracking of increment within the States or subdivide the States to such a degree as to undermine the PSD program. It is worth noting that the extent of a baseline area for tracking increment consumption is not limited by the initial designation of attainment/ unclassifiable area 8 6 boundaries. Instead, all attainment/ unclassifiable areas in which the triggering source's emissions would have a significant ambient impact are included in the baseline area.

We note commenters' support for our July 20, 2004 letter regarding Montana's recommendations. Based on further discussions with the State of Montana and a letter from the State dated November 10, 2004, we are approving a recommendation to define the attainment/ unclassifiable areas within Montana on a county by county basis, similar to that which was done under EPA's 8 hour ozone designations.

Footnote 1: We recently learned that when we issued our July 20, 2004 letter stating our agreement with the State of Utah's recommended attainment/ unclassifiable area boundaries, we misinterpreted Utah's recommendation. While we thought that Utah was primarily recommending designations according to county boundaries, with some smaller areas covering metropolitan areas along the Wasatch Front, Utah was actually recommending designations by township boundaries for most of the state. However, in recent discussions, EPA and Utah have come to agree that EPA's original interpretation of Utah's recommended boundaries is appropriate at this time. As with Wyoming, attainment/ unclassifiable boundaries in Utah are being defined largely by county boundaries, with subdivision of a limited number of counties along the Wasatch Front into two areas.

EPA's Response to 2nd Comment: As noted above, for Montana we are defining the entire State other than the Libby nonattainment area on a county by county basis. For Wyoming, we believe it is reasonable to delineate attainment/ unclassifiable areas by the county and 10 city/ town boundaries the state has proposed. For Utah, we believe it is reasonable to delineate attainment/ unclassifiable areas primarily by county boundaries, with the division in two of Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and Weber counties. These boundary designations are consistent with others we are doing for PM2.5 and have done for other pollutants, where we have commonly used county boundaries to define attainment areas. As discussed above, Utah and Wyoming's further delineation within counties should not unreasonably complicate the tracking of increment within the states or undermine the PSD program We don't anticipate that any PSD regulations for PM2.5 would so alter the basic structure of the PSD program so as to render these designations inappropriate. We acknowledge the commenters' request that we quickly issue PSD regulations for PM2.5.

Comment: 1093 1 Region: 8 State: UT Area:

Comment: Utah recommended attainment area designations in a February 13, 2004 letter from Governor Walker to EPA. We have learned that EPA understood Utah's February 13, 2004 letter to indicate that county boundaries would be used to define attainment/ unclassifiable area boundaries for most of the state. While this was not Utah's original intent, we can agree that counties would be an initial system of boundaries that 8 7 could be amended in the future using a collection of townships to refine boundaries based on the EPA designation criteria, PSD rules and a more detailed township boundary setting process to be developed.

Utah does not propose to use single townships as a nonattainment area or a PSD air quality impact/ baseline area. We understand that such a proposal would not be approved by EPA. Townships are to be used as the " currency" for defining the boundaries of larger non attainment or PSD analysis areas, not the areas themselves.

Utah understands that its February 13, 2004 boundary recommendations for Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and Weber counties are acceptable to EPA. These boundary recommendations are illustrated in Attachment 1 to the February 13, 2004 letter.

EPA Response: EPA and Utah are in agreement that the PM2.5 attainment/ unclassifiable boundary areas to be identified in Part 81 will reflect EPA's interpretation of Utah's recommendation; i. e., county by county designations, with subdivision of a limited number of counties into two areas ( Box Elder, Cache, Davis, Salt Lake, Tooele, Utah and Weber Counties). EPA commits to work with Utah to develop a process for identifying boundary areas when a major source locates in an area.

Comment: 1012 1 Region: 8 State: UT | MT | WY Area:

Comment: 1st Comment: Commenters express concern about the recommendations that several western states have made to designate unreasonably small areas as nonattainment/ unclassifiable areas for PM2.5. Montana, Utah, and Wyoming recommended dividing the portions of their states that were not designated as nonattainment for PM2.5 into many attainment/ unclassifiable areas. Commenters suggest that these state proposals would undermine the Clean Air Act's prevention of significant deterioration ( PSD) program. The commenters disagree with EPA's intended approval of Utah and Wyoming's recommended designations. If EPA fails to disallow the recommendations, it will disregard Congress's intent to protect existing air quality that is better than the NAAQS through PSD, since failing to trigger PSD increment protections in significant portions of these states would result in those areas simply being governed by the NAAQS. The designation of PM2.5 areas based on arbitrary grid or jurisdictional boundaries within a state would also constitute arbitrary and capricious action because such boundaries bear no conceivable relationship to any of the relevant requirements or purposes of the CAA. In order to make PSD protections meaningful, EPA should promulgate PSD regulations for PM2.5 as required under Section 166 of the CAA.

2nd Comment: The commenter believes that EPA's action approving the states' request is premature and arbitrary and capricious. Congress pointedly required EPA to issue regulations to prevent significant deterioration of air quality for PM2.5 in tandem with or 8 8 prior to the air quality status designations under section 107. This reflects the obvious interlocking statutory linkages between the PSD program and the 107 designations. We respectfully request that EPA swiftly carry out its long overdue statutory responsibility to issue PSD regulations for PM2.5 and reject or at the very least hold in abeyance any final action on Utah and Wyoming as well as Montana's recommendations until it has promulgated the framework regulations required to prevent significant deterioration with respect to PM2.5, so that the implications of the proposed boundaries can be meaningfully assessed.

EPA Response: EPA's Response to 1st Comment: We are approving Wyoming's recommendation for attainment/ unclassifiable boundaries based on the boundaries of counties and ten cities/ towns. For Utah, we are defining attainment/ unclassifiable boundaries as county boundaries, with the exception of a limited number of counties along the Wasatch Front, which are being divided in two. 1 For Montana we are approving a recommendation for attainment/ unclassifiable boundaries based on the boundaries of county by county. We believe this is reasonable for the following reasons.

First, while attainment areas have often been delineated as " rest of state", we have also commonly used county boundaries to designate attainment/ unclassifiable areas. For example, for TSP, county by county designations were used for the states of Kentucky and Kansas. In certain limited instances, we have redesignated portions of counties as separate attainment/ unclassifiable areas. For example, in the Powder River Basin, parts of Converse and Campbell Counties, Wyoming are designated separate attainment/ unclassifiable areas for PM10.

There is no requirement in the CAA or our regulations that attainment/ unclassifiable areas encompass an entire state. Second, Utah and Wyoming's further limited delineation of areas within a county should not unreasonably complicate the tracking of increment within the States or subdivide the States to such a degree as to undermine the PSD program. It is worth noting that the extent of a baseline area for tracking increment consumption is not limited by the initial designation of attainment/ unclassifiable area boundaries. Instead, all attainment/ unclassifiable areas in which the triggering source's emissions would have a significant ambient impact are included in the baseline area.

We note commenters' support for our July 20, 2004 letter regarding Montana's recommendations. Based on further discussions with the State of Montana and a letter from the State dated November 10, 2004, we are approving a recommendation to define the attainment/ unclassifiable areas within Montana on a county by county basis, similar to that which was done under EPA's 8 hour ozone designations.

Footnote 1: We recently learned that when we issued our July 20, 2004 letter stating our agreement with the State of Utah's recommended attainment/ unclassifiable area boundaries, we misinterpreted Utah's recommendation. While we thought that Utah was primarily recommending designations according to county boundaries, with some smaller areas covering metropolitan areas along the Wasatch Front, Utah was actually recommending designations by township boundaries for most of the state. However, in 8 9 recent discussions, EPA and Utah have come to agree that EPA's original interpretation of Utah's recommended boundaries is appropriate at this time. As with Wyoming, attainment/ unclassifiable boundaries in Utah are being defined largely by county boundaries, with subdivision of a limited number of counties along the Wasatch Front into two areas.

EPA's Response to 2nd Comment: As noted above, for Montana we are defining the entire State other than the Libby nonattainment area on a county by county basis. For Wyoming, we believe it is reasonable to delineate attainment/ unclassifiable areas by the county and 10 city/ town boundaries the state has proposed. For Utah, we believe it is reasonable to delineate attainment/ unclassifiable areas primarily by county boundaries, with the division in two of Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and Weber counties. These boundary designations are consistent with others we are doing for PM2.5 and have done for other pollutants, where we have commonly used county boundaries to define attainment areas. As discussed above, Utah and Wyoming's further delineation within counties should not unreasonably complicate the tracking of increment within the states or undermine the PSD program We don't anticipate that any PSD regulations for PM2.5 would so alter the basic structure of the PSD program so as to render these designations inappropriate. We acknowledge the commenters' request that we quickly issue PSD regulations for PM2.5.

Comment: 1012 1 Region: 8 State: WY | UT | MT Area:

Comment: 1st Comment: Commenters express concern about the recommendations that several western states have made to designate unreasonably small areas as nonattainment/ unclassifiable areas for PM2.5. Montana, Utah, and Wyoming recommended dividing the portions of their states that were not designated as nonattainment for PM2.5 into many attainment/ unclassifiable areas. Commenters suggest that these state proposals would undermine the Clean Air Act's prevention of significant deterioration ( PSD) program. The commenters disagree with EPA's intended approval of Utah and Wyoming's recommended designations. If EPA fails to disallow the recommendations, it will disregard Congress's intent to protect existing air quality that is better than the NAAQS through PSD, since failing to trigger PSD increment protections in significant portions of these states would result in those areas simply being governed by the NAAQS. The designation of PM2.5 areas based on arbitrary grid or jurisdictional boundaries within a state would also constitute arbitrary and capricious action because such boundaries bear no conceivable relationship to any of the relevant requirements or purposes of the CAA. In order to make PSD protections meaningful, EPA should promulgate PSD regulations for PM2.5 as required under Section 166 of the CAA.

2nd Comment: The commenter believes that EPA's action approving the states' request is premature and arbitrary and capricious. Congress pointedly required EPA to issue regulations to prevent significant deterioration of air quality for PM2.5 in tandem with or 8 10 prior to the air quality status designations under section 107. This reflects the obvious interlocking statutory linkages between the PSD program and the 107 designations. We respectfully request that EPA swiftly carry out its long overdue statutory responsibility to issue PSD regulations for PM2.5 and reject or at the very least hold in abeyance any final action on Utah and Wyoming as well as Montana's recommendations until it has promulgated the framework regulations required to prevent significant deterioration with respect to PM2.5, so that the implications of the proposed boundaries can be meaningfully assessed.

EPA Response: EPA's Response to 1st Comment: We are approving Wyoming's recommendation for attainment/ unclassifiable boundaries based on the boundaries of counties and ten cities/ towns. For Utah, we are defining attainment/ unclassifiable boundaries as county boundaries, with the exception of a limited number of counties along the Wasatch Front, which are being divided in two. 1 For Montana we are approving a recommendation for attainment/ unclassifiable boundaries based on the boundaries of county by county. We believe this is reasonable for the following reasons.

First, while attainment areas have often been delineated as " rest of state", we have also commonly used county boundaries to designate attainment/ unclassifiable areas. For example, for TSP, county by county designations were used for the states of Kentucky and Kansas. In certain limited instances, we have redesignated portions of counties as separate attainment/ unclassifiable areas. For example, in the Powder River Basin, parts of Converse and Campbell Counties, Wyoming are designated separate attainment/ unclassifiable areas for PM10.

There is no requirement in the CAA or our regulations that attainment/ unclassifiable areas encompass an entire state. Second, Utah and Wyoming's further limited delineation of areas within a county should not unreasonably complicate the tracking of increment within the States or subdivide the States to such a degree as to undermine the PSD program. It is worth noting that the extent of a baseline area for tracking increment consumption is not limited by the initial designation of attainment/ unclassifiable area boundaries. Instead, all attainment/ unclassifiable areas in which the triggering source's emissions would have a significant ambient impact are included in the baseline area.

We note commenters' support for our July 20, 2004 letter regarding Montana's recommendations. Based on further discussions with the State of Montana and a letter from the State dated November 10, 2004, we are approving a recommendation to define the attainment/ unclassifiable areas within Montana on a county by county basis, similar to that which was done under EPA's 8 hour ozone designations.

Footnote 1: We recently learned that when we issued our July 20, 2004 letter stating our agreement with the State of Utah's recommended attainment/ unclassifiable area boundaries, we misinterpreted Utah's recommendation. While we thought that Utah was primarily recommending designations according to county boundaries, with some smaller areas covering metropolitan areas along the Wasatch Front, Utah was actually recommending designations by township boundaries for most of the state. However, in 8 11 recent discussions, EPA and Utah have come to agree that EPA's original interpretation of Utah's recommended boundaries is appropriate at this time. As with Wyoming, attainment/ unclassifiable boundaries in Utah are being defined largely by county boundaries, with subdivision of a limited number of counties along the Wasatch Front into two areas.

EPA's Response to 2nd Comment: As noted above, for Montana we are defining the entire State other than the Libby nonattainment area on a county by county basis. For Wyoming, we believe it is reasonable to delineate attainment/ unclassifiable areas by the county and 10 city/ town boundaries the state has proposed. For Utah, we believe it is reasonable to delineate attainment/ unclassifiable areas primarily by county boundaries, with the division in two of Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and Weber counties. These boundary designations are consistent with others we are doing for PM2.5 and have done for other pollutants, where we have commonly used county boundaries to define attainment areas. As discussed above, Utah and Wyoming's further delineation within counties should not unreasonably complicate the tracking of increment within the states or undermine the PSD program We don't anticipate that any PSD regulations for PM2.5 would so alter the basic structure of the PSD program so as to render these designations inappropriate. We acknowledge the commenters' request that we quickly issue PSD regulations for PM2.5.


[Federal Register Volume 80, Number 184 (Wednesday, September 23, 2015)]
[Notices]
[Pages 57351-57353]
[FR Doc No: 2015-24136]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EF15-9-000]

Before Commissioners: Norman C. Bay, Chairman; Philip D. Moeller,
Cheryl A. LaFleur, Tony Clark, and Colette D. Honorable; Bonneville
Power Administration; Order Approving Rates on an Interim Basis and
Providing Opportunity for Additional Comments

    1. In this order, we approve the Bonneville Power Administration's
(Bonneville) proposed 2016 wholesale power and transmission rates on an
interim basis, pending our further review. We also provide an
additional period of time for the parties to file comments.

I. Background

    2. On July 29, 2015, Bonneville filed a request for interim and
final approval of its wholesale power \1\ and transmission rates \2\ in
accordance with

the Pacific Northwest Electric Power Planning and Conservation Act
(Northwest Power Act) \3\ and Part 300 of the Commission's
regulations.\4\ Bonneville projects that the filed rates will produce
average annual power revenues of $2.861 billion, and average annual
revenues from transmission and ancillary services rates of $1.085
billion. Bonneville asserts that this level of annual revenues is
sufficient to recover its costs for the 2016-2017 rate approval period,
while providing cash flow to ensure at least a 95 percent probability
of making all payments to the United States Treasury in full and on
time for each year of the rate period.
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    \1\ The proposed wholesale power rates for which Bonneville
seeks approval for the period October 1, 2015 through September 30,
2017, include: Priority Firm Power Rate (PF-16); New Resource Firm
Power Rate (NR-16); Industrial Firm Power Rate (IP-16); Firm Power
Products and Services Rate (FPS-16); and Power General Rate Schedule
Provisions (GRSPs).
    \2\ The proposed transmission rates for which Bonneville seeks
approval for the period October 1, 2015 through September 30, 2017,
include: Formula Power Transmission Rate (FPT-16.1); Formula Power
Transmission Rate (FPT-16.3); Integration of Resources Rate (IR-16);
Network Integration Rate (NT-16); Point-to-Point Rate (PTP-16);
Southern Intertie Rate (IS-16); Montana Intertie Rate (IM-16); Use-
of-Facilities Transmission Rate (UFT-16); Advance Funding Rate (AF-
16); Ancillary Services and Control Area Services Rates (ACS-16);
Townsend-Garrison Transmission Rate (TGT-16); WECC and Peak Service
Rate (PW-16); Oversupply Rate (OS-16); Eastern Intertie Rate (IE-
16); and Transmission General Rate Schedule Provisions (GRSPs).
    \3\ 16 U.S.C. 839e (2012).
    \4\ 18 CFR Part 300 (2015).
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II. Notice of Filing

    3. Notice of Bonneville's application was published in the Federal
Register,\5\ with protests and interventions due on or before August
28, 2015. Timely motions to intervene were filed by the Turlock
Irrigation District, Calpine Corporation, Public Power Council,
Industrial Customers of Northwest Utilities, Northwest Requirements
Utilities, Public Power Council, Idaho Power Company, PacifiCorp, Puget
Sound Company, M-S-R Public Power Agency, Caithness Shepherds Flat LLC,
Modesto Irrigation District, Pacific Northwest Generating Cooperative,
Western Public Agencies Group, Powerex Corporation and Portland General
Electric Company.
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    \5\ 80 FR 46,983 (Aug. 8, 2015).
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    4. Iberdrola Renewables, LLC (Iberdrola) filed a motion to
intervene and protest. Iberdrola asserts that Bonneville's Oversupply
Rate, OS-16, violates the Northwest Power Act by incorrectly allocating
Bonneville's power costs to Bonneville's transmission customers.\6\
Iberdrola quotes Northwest Power Act section 7(g) as saying all costs
of fish and wildlife measures, as well as all costs associated with the
sale of or inability to sell excess power, must be allocated to power
rates.\7\ Iberdrola argues Bonneville's oversupply management costs are
fish and wildlife costs as well as costs associated with the inability
to sell excess electric power, and thus should be allocated to power
customers, not transmission customers.\8\ Iberdrola continues that,
although Bonneville states that oversupply costs occur because wind
generators have been interconnected to its system, the oversupply costs
are actually caused by Bonneville having too much generation and not
enough load, and having fish-protection restrictions on spillage that
require Bonneville to pay someone to take the excess generation.\9\
Finally, Iberdrola argues that if Bonneville wishes to extend the use
of the Oversupply Management Proposal (OMP) for the 2016-17 rate
period, it should submit those rates to the Commission for review and
approval under Federal Power Act section 211A.\10\
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    \6\ Iberdrola Protest at 3.
    \7\ Id. at 4.
    \8\ Id. at 5.
    \9\ Id. at 6.
    \10\ Id. at 7-8; 16 U.S.C. 824j-1(f) (2012).
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    5. Avista Corporation, Portland General Electric Company, Puget
Sound Energy, Inc, and PacifiCorp (collectively Joint Commenters) filed
Joint Comments requesting that the Commission reject Bonneville's
proposed allocation of oversupply costs to transmission customers and
deny Bonneville's application for confirmation and approval of the OS-
16 Rate.\11\ The Joint Commenters request that the OS-16 Rate should be
rejected as a permanent solution to Bonneville's purported
oversupply.\12\ The Joint Commenters also request that the Commission
not rely on its prior OS-14 rate determinations in reviewing the OS-16
rate,\13\ and that Bonneville's proposed allocation of oversupply costs
to transmission is based on the flawed premise that interconnection of,
or scheduling of transmission for, generation in Bonneville's Balancing
Authority Area causes oversupply.\14\ The Joint Commenters also assert
that it is Bonneville's reliance on OMP and its failure to take all
reasonable actions to avoid excess spill that lead to the erroneous
conclusion that transmission of displaceable generation interconnected
in Bonneville's Balancing Authority Area causes oversupply.\15\ The
Joint Commenters further assert that the Northwest Power Act \16\ and
Transmission System Act \17\ cost allocation standards prohibit the
allocation of oversupply costs to transmission rates.\18\
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    \11\ Joint Commenters at 18.
    \12\ Joint Commenters at 2, citing Bonneville Power Admin., 149
FERC ] 61,043 (2014).
    \13\ Id. at 5-6.
    \14\ Id. at 7-11.
    \15\ Id. at 11-14.
    \16\ 16 U.S.C. 839 (2012).
    \17\ 16 U.S.C. 838 (2012).
    \18\ Id. at 14-17.
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III. Discussion

A. Procedural Matters

    6. Pursuant to Rule 214 of the Commission's Rules of Practice and
Procedure,\19\ the timely, unopposed motions to intervene serve to make
the entities that filed them parties to this proceeding.
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    \19\ 18 CFR 385.214 (2015).
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    7. Rule 213(a)(2) of the Commission's Rules of Practice and
Procedure \20\ prohibits an answer to a protest or an answer unless
otherwise ordered by the decisional authority.
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    \20\ 18 CFR 385.213(a)(2) (2015),
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B. Standard of Review

    8. Under the Northwest Power Act, the Commission's review of
Bonneville's regional power and transmission rates is limited to
determining whether Bonneville's proposed rates meet the three specific
requirements of section 7(a)(2) of the Northwest Power Act: \21\
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    \21\ 16 U.S.C. 839e(a)(2) (2012). Bonneville also must comply
with the financial, accounting, and ratemaking requirements in
Department of Energy Order No. RA 6120.2.
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    (A) They must be sufficient to assure repayment of the federal
investment in the Federal Columbia River Power System over a reasonable
number of years after first meeting Bonneville's other costs;
    (B) they must be based upon Bonneville's total system costs; and
    (C) insofar as transmission rates are concerned, they must
equitably allocate the costs of the federal transmission system between
federal and non-federal power.
    9. Commission review of Bonneville's non-regional, non-firm rates
also is limited. Review is restricted to determining whether such rates
meet the requirements of section 7(k) of the Northwest Power Act,\22\
which requires that they comply with the Bonneville Project Act, the
Flood Control Act of 1944, and the Federal Columbia River Transmission
System Act. Taken together, those statutes require that Bonneville's
non-regional, non-firm rates:
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    \22\ 16 U.S.C. 839e(k) (2012).
---------------------------------------------------------------------------

    (A) Recover the cost of generation and transmission of such
electric energy, including the amortization of investments in the power
projects within a reasonable period;
    (B) encourage the most widespread use of Bonneville power; and

    (C) provide the lowest possible rates to consumers consistent with
sound business principles.
    10. Unlike the Commission's statutory authority under the Federal
Power Act, the Commission's authority under sections 7(a) and 7(k) of
the Northwest Power Act does not include the power to modify the rates.
The responsibility for developing rates in the first instance is vested
with Bonneville's Administrator. The rates are then submitted to the
Commission for approval or disapproval. In this regard, the
Commission's role can be viewed as an appellate one: to affirm or
remand the rates submitted to it for review.\23\
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    \23\ See, e.g., United States Department of Energy--Bonneville
Power Admin., 67 FERC ] 61,351, at 62,216-17 (1994); see also, e.g.,
Aluminum Co. of America v. Bonneville Power Admin., 903 F.2d 585,
592-93 (9th Cir. 1989).
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    11. Moreover, review at this interim stage is further limited. In
view of the volume and complexity of a Bonneville rate application,
such as the one now before the Commission in this filing, and the
limited period in advance of the requested effective date in which to
review the application,\24\ the Commission generally defers resolution
of issues on the merits of Bonneville's application until the order on
final confirmation. Thus, the proposed rates, if not patently
deficient, generally are approved on an interim basis and the parties
are afforded an additional opportunity in which to raise issues with
regard to Bonneville's filing.\25\
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    \24\ See 18 CFR 300.10(a)(3)(ii) (2015).
    \25\ See, e.g., United States Department of Energy--Bonneville
Power Administration, 64 FERC ] 61,375, at 63,606 (1993); United
States Department of Energy--Bonneville Power Admin., 40 FERC ]
61,351, at 62,059-60 (1987).
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    12. The Commission declines at this time to grant final
confirmation and approval of Bonneville's proposed wholesale power and
transmission rates. The Commission's preliminary review nevertheless
indicates that Bonneville's wholesale power and transmission rates
filing appears to meet the statutory standards and the minimum
threshold filing requirements of Part 300 of the Commission's
regulations.\26\ Moreover, the Commission's preliminary review of
Bonneville's submittal indicates that it does not contain any patent
deficiencies. The proposed rates therefore will be approved on an
interim basis pending our further review. We note, as well, that no one
will be harmed by this decision because interim approval allows
Bonneville's rates to go into effect subject to refund with interest;
the Commission may order refunds with interest if the Commission later
determines in its final decision not to approve the rates.\27\
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    \26\ See, e.g., United States Department of Energy--Bonneville
Power Admin., 105 FERC ] 61,006, at PP 13-14 (2003); United States
Department of Energy--Bonneville Power Admin., 96 FERC ] 61,360, at
62,358 (2001).
    \27\ See 18 CFR 300.20(c) (2015).
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    13. In addition, we will provide an additional period of time for
parties to file comments and reply comments on issues related to final
confirmation and approval of Bonneville's proposed rates. This will
ensure that the record in this proceeding is complete and fully
developed.
    The Commission orders:
    (A) Interim approval of Bonneville's proposed wholesale power and
transmission rates is hereby granted, to become effective on October 1,
2015, through September 30, 2017, subject to refund with interest as
set forth in section 300.20(c) of the Commission's regulations \28\
pending final action and either their approval or disapproval.
---------------------------------------------------------------------------

    \28\ 18 CFR 300.20(c) (2015).
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    (B) Within thirty (30) days of the date of this order, parties who
wish to do so may file additional comments regarding final confirmation
and approval of Bonneville's proposed rates. Parties who wish to do so
may file reply comments within twenty (20) days thereafter.
    (C) The Secretary shall promptly publish this order in the Federal
Register.

    By the Commission.

    Issued: September 17, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2015-24136 Filed 9-22-15; 8:45 am]
 BILLING CODE 6717-01-P