96. Xcel states that the Final Rule anticipates the possibility of
placing the applicant at risk for being ordered to file a section 205
rate case for its existing investments and contend that this potential
risk will have the practical effect of discouraging limited section 205
incentive proposals. Accordingly, Xcel recommends that the Final Rule
be modified so that it can achieve its stated purpose of providing
assurance that the decision to construct new infrastructure is
evaluated on the basis of the risks and returns of that decision,
rather than the additional uncertainty associated with re-opening the
applicant's entire base rates to review and litigation.\156\ According
to Xcel, to the extent the Commission believes the new single-issue
rate must be harmonized with existing rates, the burden of proof should
remain on the Commission, or the utility's customers, to show the
existing filed rates are unjust and unreasonable and not shift the
burden to the public utility.\157\
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    \156\ 156 Xcel at 4-5.
    \157\ Id. at 5.
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2. Commission Determination
    97. The Final Rule recognized that requiring transmission owners to
open up their existing rates for review and litigation anytime they
sought recovery of costs associated with a new transmission project
could discourage new investment. Accordingly, the Final Rule permits an
applicant to propose transmission rates associated with a particular
project without proposing any changes to its existing transmission
rates under section 205. We disagree with TDU Systems and APPA/NRECA
that single-issue ratemaking will permit transmission owners to earn an
unjust and unreasonable return on their overall

transmission investment and we specifically committed that the
Commission would consider the need to combine or reconcile any project-
specific transmission rate proposal with any existing transmission
rate, where necessary.
    98. Indeed, the Final Rule specifies that the Commission may
require the applicant to file a full rate case for existing
transmission rates when evaluating a single-issue rate application, and
therefore provides a procedure for additional rate review. However, we
agree with Xcel that further clarification is necessary.\158\ As
indicated in the Final Rule, applicants for single-issue ratemaking are
only required to address cost and rate issues associated with the new
investment and therefore are not obligated to justify the
reasonableness of unchanged rates.\159\ As PSC of N.Y. and Winnfield
make clear, if intervenors or the Commission seek to challenge the
applications beyond the limited issues raised in their applications,
the intervenors or the Commission bear the burden of proof under
section 206 in establishing that the existing, unchanged components of
the rate are unjust and unreasonable. We further clarify that
Commission review of the single-rate application will not be delayed in
the event a separate section 206 investigation is initiated, thereby
ensuring that new investments are not impeded because of existing-
system rate issues.\160\
---------------------------------------------------------------------------

    \158\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 192.
    \159\ Public Service Comm'n of New York v. FERC, 642 F.2d 1335
(D.C. Cir. 1980) (``we cannot accept the proposition that because a
company files for higher rates, it bears the burden of proof on
those portions of its filing that represent no departure from the
status quo* * *. The emphasis is on making the petitioner justify
the changes in rates, not the constant elements'') (PSC of N.Y.);
City of Winnfield, La. v. FERC, 744 F.2d 871 (D.C. Cir. 1984) (``The
statutory obligation of the utility * * * is not to prove the
continued reasonableness of unchanged rates or unchanged attributes
of its rate structure'') (Winnfield).
    \160\ This clarification is also consistent with Commission
precedent:
    Protesters object to this option because of a concern that it
may permit certain transmission owners to continue to overrecover
their cost-of-service. However, this option provides just and
reasonable cost recovery for the RTEP upgrades, and provide the
necessary incentive for TOs to complete quickly the construction of
RTEP projects that are essential to the efficient operation of PJM.
As we said in the NYISO proceeding, if a concern arises regarding
over-recovery of transmission costs, such parties are free to seek
relief by filing a complaint with the Commission pursuant to section
206 of the FPA Allegheny Power System Operating Co., 111 FERC ]
61,308, at P 46 (2005), order on reh'g and clarification, 115 FERC ]
61,156 (2006).
---------------------------------------------------------------------------

    99. Based on the precedent cited above, we disagree with the
conclusion that acceptance of single-issue rate filings would represent
a dramatic shift in the historic balance between interests, and we
therefore see no need to require additional consumer protections such
as mandatory rate cases.

K. Public Power

    100. In the Final Rule, the Commission noted that ratemaking
incentives are generally not directly available to non-jurisdictional
entities, i.e. public power entities, because they do not file their
rates with the Commission.\161\ However, the Commission recognized that
public power participation can play an important role in the expansion
of the transmission system and stated that public power participation
in new transmission projects are encouraged. The Commission stated that
the Commission will review appropriate requests for incentive
ratemaking for investment in new transmission projects when public
power participates with jurisdictional entities as part of a proposal
for incentives for a particular joint project.\162\
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    \161\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 354.
    \162\ Id. The Commission did not require a consortium approach
that includes public power and other entities for new investment
because it would be more appropriate for applicants to fashion
proposals tailored to the specific circumstances and needs of a
particular project. Id. P 356-57.
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1. Rehearing Requests
    101. TAPS requests the Commission to clarify that any approved
incentive will be equally available to all owners of facilities that
are found to merit incentives, regardless of the entity's form or
business model and that the Commission will look with disfavor on
incentive rate treatment applications by vertically-integrated
utilities that exclude other utilities from co-owning a facility
located in their common footprint.\163\ TAPS contends that it is unduly
discriminatory to allow large utilities to veto transmission incentives
by refusing to participate in inclusive ownership arrangements. TDU
Systems request the Commission to clarify that the option to
participate in planning, financing and construction of new investment
belongs to the public power system and that public utilities should not
be allowed to use the availability of this option to avoid their
obligation to construct needed network upgrades. TDU Systems urge the
Commission to reconsider its determination that the Commission will not
require public power or other joint participation in a transmission
project in order for investment in a project to be eligible for
incentives. They assert that conditioning a grant of any incentive rate
treatments upon a robust, collaborative and open joint and regional
planning process with all LSEs in the region and mandating compensation
or credits for public power systems transmission facilities would
better promote the Commission's goal under section 219.\164\ Similarly,
APPA/NRECA state that public power participation ensures that the
lowest cost facilities are built, provide cash flow, and reduce
uncertainty, thereby reducing the overall need for incentive rate
treatments.\165\ NECOE and APPA/NRECA also argue that public utilities
should be required to offer joint ownership opportunities as a
condition to receiving incentives. NECOE asserts that merely
encouraging transmission owners to seek participation by public power
has not worked in New England, thereby denying ratepayers the low cost
benefits of public power. NECOE further contends that the exclusion of
non-transmission owner investment from network upgrades violates Order
No. 2000's open-architecture principles.\166\ At a minimum, NECOE
recommends that the Commission should require incentive applicants to
state whether they have sought potential LSE co-investors, including
public and consumer-owned utilities and where co-investors were sought
but not permitted to participate, the proponent of an incentive should
be required to explain why this was the case.\167\
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    \163\ TAPS at 22.
    \164\ TDU Systems at 34-35.
    \165\ APPA/NRECA at 51.
    \166\ NECOE at 9, citing Carolina Power and Light Cos., 95 FERC
] 61,282 at 61,995 (2001).
    \167\ NECOE at 5.
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2. Commission Determination
    102. The Final Rule determined that the Commission would not
condition recovery of incentives on the type of business structure and
stated that the Commission will entertain appropriate requests for
incentive ratemaking for investment in new transmission projects when
public power participates as part of a proposal for incentives for a
particular joint project.\168\ While the Commission encourages public
power participation, we will not require such participation as a
condition of any proposed incentive rate treatment. As we state
elsewhere in this order, the Commission cannot compel investment or
certain types of investment. Our focus in this rule is to provide
incentives that will facilitate voluntary investments by utilities.
However, the Commission will look favorably on an

incentive request that includes public power joint ownership. A wide
variety of entities, such as merchant companies, private equity
participants, and pool administrators can potentially build
transmission infrastructure. In the context of a rule to provide rate
incentives for the construction of new transmission and to encourage
deployment of technologies to increase the capacity and efficiency of
existing transmission facilities, we do not believe that mandating an
opportunity for public power participation is necessary nor do we
believe that failure to do so would be unduly discriminatory. However,
we note that the Commission has initiated a rulemaking in Docket Nos.
RM05-17-000 and RM05-25-000 to investigate necessary reforms to its
existing pro forma OATT.\169\ Among the reforms under consideration is
to require all jurisdictional public utilities to establish regional
transmission planning open to all participants in a region--including
public entities. We believe that the OATT reform rulemaking is a more
appropriate forum to consider any issues or allegations regarding undue
discrimination with regard to public power participation in
transmission expansion decisions. Accordingly, we will not restrict
eligibility for incentive rate treatment to projects that allow public
power participation.
---------------------------------------------------------------------------

    \168\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 354.
    \169\ See OATT Reform NOPR, supra note 63.
---------------------------------------------------------------------------

L. Other Issues

    103. Parties request rehearing on a number of other issues
discussed below.
1. Recovery of Costs of Abandoned Facilities
    104. In the Final Rule, the Commission allowed applicants to seek
recovery of 100 percent of prudently-incurred costs associated with
abandoned transmission projects due to factors beyond the control of
the public utility. The purpose of the incentive was to reduce the risk
associated with potential upgrades or other improvements to the
transmission system.
    105. TDU Systems assert that the Commission should clarify that it
would allow prudently incurred abandoned plant costs under limited
circumstances. They contend that applicants for the incentive rate
treatment that allows recovery of prudently-incurred abandoned plant
costs should be required to demonstrate that, as a precondition to
receiving the incentive, they will suffer cash flow problems if such a
recovery was not allowed.\170\ APPA/NRECA argue that the Commission
should allow the incentive of abandoned cost recovery only on the
condition that the public utility has engaged in open, regional
transmission planning process to ensure some balance between the
interests of shareholders and ratepayers. They claim that the
Commission wrongly relied on its granting of incentive rate treatment
to American Transmission Company as a basis for this incentive without
recognizing that the project was the result of joint planning.\171\
Therefore, they assert that the Commission should not ask customers to
pay for abandoned projects that they never had an opportunity to
consider in the first instance.
---------------------------------------------------------------------------

    \170\ TDU Systems at 38.
    \171\ APPA/NRECA, 44-45. See Order No. 679, FERC Stats. & Regs.
] 31,222 at P 1, 116, 122, 131; American Transmission Co., LLC, 105
FERC ] 61,388 (2003).
---------------------------------------------------------------------------

    106. We decline to specify any particular demonstration that an
applicant must make to justify recovery of abandoned plant cost beyond
the required nexus test described earlier. Also, as discussed in the
prior section on public power participation, we do not intend to
mandate public power participation as a pre-requisite for any
particular transmission rate treatment in this rule--including recovery
of abandoned plant costs. We note that in a recent case involving
incentives,\172\ the Commission expressly conditioned its approval of
incentives (including a request for recovery of costs associated with
any abandonment of the project) upon the project being included in the
PJM regional transmission expansion plan.\173\ For these reasons, we
deny rehearing on this issue.
---------------------------------------------------------------------------

    \172\ Allegheny Energy, Inc., 116 FERC ] 61,059 (2006), reh'g
pending.
    \173\ American Electric Power Service Corp., 116 FERC ] 61,059
(2006), reh'g pending.
---------------------------------------------------------------------------

    107. According to TDU Systems, the Commission must ensure that
there is no double recovery of costs in instances in which other
incentives are allowed for an abandoned project. In the event the
applicant receives the ROE incentive and the abandoned plant incentive
rate treatment, TDU Systems argue there should be an offset of the rate
impacts of these incentives to avoid over-recovery of costs so that the
incentive can be provided at the least reasonable cost to
consumers.\174\ As described earlier in this order, we intend to
evaluate any incentives requested as a package. To the extent that
certain requested rate treatments have the effect of lowering the risk
of a particular project, the Commission will take that into account in
establishing an appropriate equity return for the project.
---------------------------------------------------------------------------

    \174\ TDU Systems at 38.
---------------------------------------------------------------------------

2. Prudently Incurred Costs
    108. MISO TOs request clarification that limited section 205
filings are permissible for the recovery of costs of prudently-incurred
costs necessary to comply with mandatory reliability standards in
section 215.\175\ MISO TOs argue that these costs may be imposed on
transmission owners pursuant to statutory requirements and that without
this clarification, they may be subject to extensive and expensive
litigated cases, thereby discouraging utilities from recovering these
costs that Congress authorized them to recover.
---------------------------------------------------------------------------

    \175\ MISO TOs at 4-5.
---------------------------------------------------------------------------

    109. We agree that rapid processing of the recovery of mandatory
reliability costs will facilitate more timely investment in these
important projects. Therefore, we clarify that applicants may file to
recover these costs in limited section 205 filings.
3. Regional Planning
    110. Parties contend that any public utility seeking incentive
rates for its new transmission project should be required to
demonstrate that the project was formulated through an open, regional
planning process. Industrial Consumers assert that conditioning the
granting of incentives upon the inclusion of a proposed transmission
project in a regional planning process is critical to satisfying
section 219's requirements to demonstrate customer benefit and promote
economically efficient transmission. They claim that a coordinated
regional planning process that considers the relative costs and
benefits of multiple projects provides an optimal forum for determining
least-cost solutions and avoiding unnecessary duplication of
expenditures.\176\ Similarly, NARUC and TAPS argue that no incentive
should be available for projects that are to be sited in regions that
plan regionally but which bypass the regional planning processes,
noting that the Commission is proposing to require all jurisdictional
public utilities to engage in regional planning in other Commission
proceedings.\177\ Further, TDU Systems argue that nothing in section
219 suggests that the Commission may not impose a regional planning
requirement and that making regional planning process a threshold
requirement for incentive applications would be congruent with the
mandate of section 219 to promote reliable and economically efficient
transmission and

generation of electricity.\178\ APPA/NRECA also contend that the
Commission has broad discretion in deciding particular incentives and
that a regional planning requirement would harmonize section 219 with
the objectives of section 217(b) to facilitate the planning and
expansion of transmission facilities to meet the reasonable needs of
LSEs. They also argue that the imposition of regional planning as a
threshold requirement for incentive applicants is required by the
mandate of section 219.\179\
---------------------------------------------------------------------------

    \176\ Industrial Consumers at 11.
    \177\ NARUC at 6; TAPS at 7.
    \178\ TDU Systems at 9-10.
    \179\ APPA/NRECA at 16-19.
---------------------------------------------------------------------------

    111. The Final Rule grants a rebuttable presumption that projects
resulting from regional planning qualify for incentive rate treatments,
and we affirm that finding as discussed above. We will not, however,
limit incentive rate treatments to projects that result from regional
planning processes. While the Commission agrees that there are
substantial benefits to be derived from regional planning, there may be
transmission projects that arise outside of the context of a regional
plan that help to ensure reliability or reduce the costs of delivered
power and which deserve incentive rate treatment. Although the
Commission has proposed to require regional planning as part of its
OATT reform effort,\180\ we note that many utilities are in regions in
which no formal regional planning process exists at this time. However,
as we stated in the Final Rule, and as modified by this order, projects
are not entitled to a rebuttable presumption if they have not gone
through a regional planning process, or have not received construction
approval from an appropriate state commission or siting authority.\181\
Applicants seeking incentives for such projects must independently
demonstrate that the project will maintain reliability or reduce
congestion.
---------------------------------------------------------------------------

    \180\ OATT Reform NOPR, supra note 63.
    \181\ In addition, and as modified by this order, an applicant
may also rely upon the Commission's siting authority for meeting the
requirements of section 219(a).
---------------------------------------------------------------------------

4. CWIP
    112. Because the long lead times required to plan and construct new
transmission can negatively affect cash flow and the ability of a
utility to attract capital at reasonable prices, the Final Rule allows
public utilities to propose including 100 percent CWIP in rate base and
expensing pre-commercial operations costs associated with new
transmission investment.\182\
---------------------------------------------------------------------------

    \182\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 115-22.
---------------------------------------------------------------------------

    113. TDU Systems assert that the Commission should only allow 100
percent recovery CWIP and pre-commercial operations costs in the event
the applicant shows that the transmission project will take more than
four years to complete and that the applicant should have to
demonstrate a regional need for the project to ensure that consumers
receive measurable benefits.\183\ In addition, TDU Systems contend
that, with respect to pre-commercial expenses, the Commission should:
(1) Ensure that these costs are not later capitalized in subsequent
rate filings; and (2) limit the pre-commercial costs to be expensed to
planning, siting and environmental costs so that costs that raise
inter-generational equity concerns, such as the design and construction
of facilities, are not included.\184\
---------------------------------------------------------------------------

    \183\ TDU Systems at 9-10.
    \184\ Id. at 37.
---------------------------------------------------------------------------

    114. We decline to establish any generic restrictions on the types
of transmission projects or construction periods in order for a project
to qualify for CWIP treatment under this rule. We leave to the
applicant's discretion whether the construction project is of
sufficient size to merit making a rate request to the Commission
seeking to include CWIP in rate base or to expense pre-commercial
operations costs. There may be reasons that justify seeking CWIP for
projects with relatively short construction schedules e.g., a project
may take only a few years to build but rates will not go into effect
for a number of additional years because the project can not recover
costs until other projects are built, and therefore CWIP recovery is
justified. We clarify that the Commission's review process under
section 205 will include a review to determine that the applicant does
not double recover these costs. The Final Rule's definition of costs
approved by the Commission to be recoverable as pre-certification costs
in account 183, i.e., preliminary survey and investigation costs,\185\
does not include facility costs and therefore should not raise the
inter-generational issues of concern to TDU Systems.
---------------------------------------------------------------------------

    \185\ See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 122
and n 82.
---------------------------------------------------------------------------

    115. Finally, while CWIP and abandoned plant are characterized as
``incentive-based rate treatments'' in the Final Rule, we clarify that
both of these rate mechanisms have been found previously to be just and
reasonable under the Commission's authority pursuant to section
205.\186\ More importantly, these are rate treatments which may be
needed (and requested) in advance of a project being approved through a
regional planning process or receiving any necessary siting approvals.
To the extent an applicant demonstrates that the incentives sought
(i.e., CWIP and abandoned plant) are tailored to address the
demonstrable risks and challenges of the applicant, we will permit
recovery of such prudently-incurred costs.
---------------------------------------------------------------------------

    \186\ See, e.g., American Electric Power Service Corp., 116 FERC
] 61,059, at P 55 (2006), reh'g pending (allowing recovery of 100
percent CWIP); Allegheny Energy, Inc., 116 FERC ] 61,058, at P 74
(2006), reh'g pending; American Transmission Co., L.L.C., 105 FERC ]
61,388, at P 27 (order establishing hearing and settlement judge
procedures concerning, inter alia, the company's proposal for
recovery of 100 percent CWIP), order dismissing reh'g and approving
settlement, 107 FERC ] 61,117 (2004); Boston Edison Co., 109 FERC ]
61,300 (2004), order on reh'g, 111 FERC ] 61,266 (2005) (recovery of
50 percent CWIP); Southern California Edison Co., 112 FERC ] 61,014,
at P 58-61, reh'g denied, 113 FERC ] 61,143, at P 9-15 (2005)
(granting recovery of 100 percent of prudently incurred abandoned or
cancelled plant costs); New England Power Co., Opinion No. 295, 42
FERC ] 61,016, at 61,068, 61,081-83 (recovery of 50 percent of
prudently incurred cancelled plant costs), order on reh'g, 43 FERC ]
61,285 (1988); Public Service Co. of New Mexico, 75 FERC ] 61,266,
at 61,859 (1996), order approving settlement, 87 FERC ] 61,040
(1999) (50 percent recovery of cancelled plant costs).
---------------------------------------------------------------------------

    116. For example, where an applicant has satisfied our nexus
requirement and has been granted authority to recover CWIP or abandoned
plant, and subsequently the applicant's project is, for example, unable
to obtain state or federal siting authority (and thus no showing is
made with respect to ensuring reliability or reducing the cost of
delivered power by reducing congestion because the applicant was
relying upon those processes) we would not require refunds for the
costs already prudently-incurred by the applicant. To require refunds
in such circumstances would be contrary to our long-standing policy,
which permits recovery of all prudently-incurred costs.\187\
---------------------------------------------------------------------------

    \187\ The Commission ``has applied the `prudence' test to
determine the recoverability of a utility's expenses. Under this
test [a utility] is entitled to recover its costs from consumers if
it acted `prudently' in incurring those costs, or stated conversely,
[a utility] may not recover its costs if those costs were incurred
`imprudently.' '' Connecticut Yankee Atomic Power Co., 108 FERC ]
61,212, at P 42 (2004), quoting Violet v. FERC, 800 F.2d 280, 282
(1st Cir. 1986). See also, e.g., City of New Orleans v. FERC, 67
F.3d 947 (D.C. Cir. 1995) (citing Violet v. FERC)).
---------------------------------------------------------------------------

5. Reporting Requirement: FERC-730
    117. The Final Rule adopted an annual reporting requirement, FERC-
730, for utilities that receive incentive rate treatment for specific
transmission projects. The annual reporting requirement includes
projections and

related information that detail the level of transmission
investment.\188\
---------------------------------------------------------------------------

    \188\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 367-76.
---------------------------------------------------------------------------

    118. TAPS argues that FERC-730's tracking of capital spending is
misdirected by failing to identify how much consumers are spending as
incentive rate treatments and what they are getting in return. TAPS
recommends that the Commission expand FERC-730 to include budgeted
amounts by project on an annual basis, segregation of generation or
distribution investments, a listing of which network service customers
are predominantly paying for the project costs and the expected
differential cost to consumers of each project's approved above-cost
incentives.\189\
---------------------------------------------------------------------------

    \189\ TAPS at 29-31.
---------------------------------------------------------------------------

    119. As the Commission explained in the Final Rule, the purpose of
the FERC-730 reporting requirement is not to provide a quantitative
measure of the consumer benefits that result from transmission
infrastructure investments. In the proceeding approving incentives and
recovery of the costs of incentives in rates, the Commission will
determine whether proposed projects meet the requirements of section
219 and thereby provide consumer benefits and also set metrics to
ensure those benefits are justified on an on-going basis. Therefore no
further quantitative tracking of consumer benefits or expected
differential costs to consumers is necessary. We repeat and affirm the
Final Rule's statement that year-by-year capital spending estimates are
not necessary for each individual project listed since the goal of the
rule is not to ensure the achievement of annual capital spending
targets but rather to ensure the overall projects are completed, and if
not, the reasons for delay.
    120. We will not limit the capital spending information requested
from account numbers 350 through 359 \190\ to only investment in the
transmission function, and exclude transmission investment in the
generation or distribution functions. Capital investment in
transmission facilities that interconnect generation facilities are
ensuring reliability, and therefore are meeting the requirements of
section 219. Accordingly, it is appropriate to include these amounts in
transmission investment. Likewise, capital investment in lower voltage
transmission facilities that are classified as part of the distribution
function also accomplish the reliability and congestion reduction
requirements of section 219 and therefore should be included in the
survey of transmission investment. We see no need to require additional
information on which customers pay for investment projects and the
differential cost impact of the incentives. The purpose of FERC-730 is
restricted to information on progress toward meeting the requirements
of section 219. Customer allocation of cost responsibility is beyond
the scope of that provision, and therefore that information does not
need to be collected.
---------------------------------------------------------------------------

    \190\ 18 CFR part 101.
---------------------------------------------------------------------------

6. Miscellaneous
    121. TDU Systems and APPA/NRECA argue that no incentives should be
approved for projects that already have a binding commitment to build,
including commitments under RTO arrangements, or for which applicants
are obligated to build by statute, regulation or order.\191\
---------------------------------------------------------------------------

    \191\ APPA/NRECA at 4; TAPS at 35.
---------------------------------------------------------------------------

    122. In general, we do not consider that contractual commitments or
mandatory projects, such as section 215 reliability projects,
disqualify a request for incentive-based rate treatment. Provided
applicants are able to demonstrate they meet the requirements of
section 219, including establishing the required nexus between the
requested incentive and the investment, they may qualify for incentive-
based rate treatments. A prior contractual commitment or statute may
have a bearing on our nexus evaluation of individual applications.
    123. EEI requests clarification that an applicant or group of
applicants may propose rate incentives for a group of interrelated
projects rather than for each single project individually, and thereby
reduce the Commission burden.\192\
---------------------------------------------------------------------------

    \192\ EEI at 6.
---------------------------------------------------------------------------

    124. We clarify that applicants may propose incentives as a group,
and note that such a group application process has been used by groups
of transmission owners that are members of RTOs. With this
clarification, we believe that revision of Sec.  35.35(d) is
unnecessary.
    125. TAPS asserts that the Final Rule failed to explicitly provide
that applicants' proposed incentives will be modified when doing so
will advance the customer-benefiting objectives of section 219. For
example, TAPS argues that in order to modify the investment to which
incentives will apply, an applicant may propose an incentive-worthy,
congestion-reducing, new line packaged with mundane existing facility
replacements that have already been committed to and do not advance the
objectives of section 219.\193\ In such a case, TAPS argues that the
Commission should be able to modify the proposal to target incentives
to the new line alone.
---------------------------------------------------------------------------

    \193\ TAPS at 12.
---------------------------------------------------------------------------

    126. We do not consider this rulemaking to be the proper forum to
assess whether a hypothetical application would meet the requirements
of section 219 and Order No. 679. The Commission will determine whether
incentive applications are just and reasonable based on the specific
facts and circumstances of each proposal.
    127. TDU Systems request clarification that metrics are required
because certain statements in the Final Rule imply metrics are
optional.\194\ To the extent the use of metrics determines that a
project does not provide the anticipated benefits, ratepayers should
receive refunds based on the monetary value of the incentive, according
to TDU Systems.
---------------------------------------------------------------------------

    \194\ See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 36
(``an applicant may propose periodic progress assessments * * *'').
---------------------------------------------------------------------------

    128. We clarify that applicants are required to propose metrics in
their incentive applications. However, it is not the Commission's
intention to approve incentive rate treatments ``subject to refund.''
To the extent that a customer has a reason to believe that any rate
that has been approved by the Commission is no longer just, reasonable,
and not unduly discriminatory or preferential, they will need to file
an appropriate complaint under section 206.
    129. TAPS contends that the Commission is not statutorily free to
rule out symmetrical, i.e. performance-based approaches to setting an
appropriate return regardless of whether they are sponsored by
incentive applicants or recommended with appropriate support by
intervenors. TAPS states that section 219 expressly provides that
incentive programs may be performance-based and has long been a
foundation for Commission incentive rate policy.\195\ SMUD asserts that
the Commission failed to explain its departure from the 1992 Policy
Statement that symmetry is an inherent part of all incentive
ratemaking.\196\
---------------------------------------------------------------------------

    \195\ TAPS at 28.
    \196\ SMUD at 9-10.
---------------------------------------------------------------------------

    130. The purpose of this rule is to provide incentive-based rate
treatments that benefit consumers by ensuring reliability and reducing
the cost of delivered power by reducing transmission congestion. The
primary focus of the rule is necessarily on

investment. However, while the Final Rule declined to adopt generic
performance-based ratemaking measures, we did encourage the industry to
work on developing performance-based ratemaking proposals. While we
agree that section 219 does not rule out symmetrical approaches to
return, to the extent applicants or intervenors propose performance-
based rate treatments under section 219, they must justify their
proposals in terms of their capability to attract investment and either
ensure reliability or reduce the cost of delivered power by reducing
congestion.
    131. TAPS asserts that the Commission cannot determine if an
incentive will be non-discriminatory, as required under section 219(d),
unless it ascertains what ratepayer classes are subject to paying for
the incentive. TAPS also claims the Commission needs to consider
whether an incentive request should be conditioned on geographically
broadened cost spreading in order to determine whether the requested
incentives can be better formulated to advance the consumer benefits of
section 219. TAPS further argues that the Commission should state its
willingness to consider in declaratory petition proceedings how costs
will be allocated for the subject facilities and whether altering that
treatment should be part of the incentive program.\197\ TDU Systems
assert that the Commission must require roll-in of new and existing
rates to encourage investment.
---------------------------------------------------------------------------

    \197\ TAPS at 17-18.
---------------------------------------------------------------------------

    132. We repeat the finding in the Final Rule that the section 205
proceedings addressing recovery of the costs of incentive-based rate
treatments are the appropriate forum for determining whether the
resulting rates are just, reasonable and non-discriminatory, and
therefore are the appropriate proceedings to consider cost allocation
and rate design issues.\198\ The primary purpose of the declaratory
petition proceeding is to determine if the proposed incentives meet the
requirements of section 219, and therefore cost allocation and rate
design issues will not be considered. Finally, we consider rate design
issues, such as roll-in of rates to beyond the scope of this
proceeding, and therefore affirm the Final Rule's determination to not
require roll-in of rates.\199\
---------------------------------------------------------------------------

    \198\ E.g., Order No. 679, FERC Stats. & Regs. ] 31,622 at P 81.
    \199\ Id. P 192.
---------------------------------------------------------------------------

    133. Southern Companies assert that the Commission's routine
imposition of a five-month suspension of rates is a disincentive to the
construction of new transmission infrastructure, claiming that delaying
the effective date of a rate change forces the utility to absorb costs
associated with new facilities and reduces the utility ROE.\200\
---------------------------------------------------------------------------

    \200\ Southern Companies at 19-20.
---------------------------------------------------------------------------

    134. The Commission addressed this concern in the Final Rule by
stating that we will not revise our suspension policy in this
proceeding. We affirm the Final Rule's finding that utilities should
raise concerns with the Commission's suspension policy in our pre-
filing process.
    135. Energy Financing requests clarification that its proposed
performance-based financing option for transmission investment is not
excluded as an alternative method of achieving the Commission's and
Congress' goal of encouraging more transmission investment, or in the
alternative, it seeks rehearing arguing that alternative financing
methodologies are viable vehicles to increase transmission investment,
in lieu of or in addition to the incentives identified in the Final
Rule.\201\ Energy Financing's proposal concerns how a project is
financed rather than an incentive-based rate treatment. We do not
consider it an alternative to the incentive-based rate treatments
specified in Sec.  35.35. Also, we can not make a determination as to
whether the option will increase transmission investment because Energy
Financing has not provided any information to indicate that its option
is having the purported effect on investment. For these reasons, we
deny rehearing on this issue.
---------------------------------------------------------------------------

    \201\ Energy Financing at 4-5.
---------------------------------------------------------------------------

    136. Finally, the introductory text in Sec.  35.35(d)(1) is revised
to delete redundant language.

IV. Information Collection Statement

    137. Order No. 679 contains information collection requirements for
which the Commission obtained approval from the Office of Management
and Budget (OMB). The OMB Control Number for this collection of
information is 1902-0203. This order denies most rehearing requests,
clarifies the provisions of Order No. 679, and grants rehearing on only
three minor issues. This order does not make substantive modifications
to the Commission's information collection requirements and,
accordingly, OMB approval for this order is not necessary. However, the
Commission will send a copy of this order to OMB for informational
purposes.

V. Document Availability

    138. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's

Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.
    139. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    140. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from our Help line at<PHONE_NUMBER>
or the Public Reference Room at<PHONE_NUMBER> Press 0, TTY (202) 502-
8659. E-Mail the Public Reference Room at
<EMAIL_ADDRESS>

VI. Effective Date

    141. Changes to Order No. 679 made in this order on rehearing will
become effective on February 9, 2007.

List of Subjects in 18 CFR Part 35

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

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends part 35 of
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

0
2. Section 35.35 is amended by:
0
a. Revising the third sentence in paragraph (d) introductory text ,
0
b. Revising paragraph (d)(1) introductory text;
0
c. Revising paragraph (i); and
0
d. Adding a new paragraph (j) to read as follows:

Sec.  35.35  Transmission infrastructure investment.

* * * * *

    (d) Incentive-based rate treatments for transmission infrastructure
investment. * * * The applicant must demonstrate that the facilities
for which it seeks incentives either ensure reliability or reduce the
cost of delivered power by reducing transmission congestion consistent
with the requirements of section 219, that the total package of
incentives is tailored to address the demonstrable risks or challenges
faced by the applicant in undertaking the project, and that resulting
rates are just and reasonable. * * *
    (1) For purposes of this paragraph (d), incentive-based rate
treatment means any of the following:
* * * * *
    (i) Rebuttable presumption. (1) The Commission will apply a
rebuttable presumption that an applicant has demonstrated that its
project is needed to ensure reliability or reduces the cost of
delivered power by reducing congestion for:
    (i) A transmission project that results from a fair and open
regional planning process that considers and evaluates projects for
reliability and/or congestion and is found to be acceptable to the
Commission; or
    (ii) A project that has received construction approval from an
appropriate state commission or state siting authority.
    (2) To the extent these approval processes do not require that a
project ensures reliability or reduce the cost of delivered power by
reducing congestion, the applicant bears the burden of demonstrating
that its project satisfies these criteria.
    (j) Commission authorization to site electric transmission
facilities in interstate commerce. If the Commission pursuant to its
authority under section 216 of the Federal Power Act and its
regulations thereunder has issued one or more permits for the
construction or modification of transmission facilities in a national
interest electric transmission corridor designated by the Secretary,
such facilities shall be deemed to either ensure reliability or reduce
the cost of delivered power by reducing congestion for purposes of
section 219(a).

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

Appendix A

Requests for Rehearing

American Public Power Association and National Rural Electric
Cooperative Association (together, APPA/NRECA)
Coalition of Midwest Transmission Customers, PJM Industrial Customer
Coalition, NEPOOL Industrial Customer Coalition, Southeast
Electricity Consumers Association, and Southwest Industrial Customer
Coalition (collectively, Industrial Consumers).
Connecticut Department of Public Utility Control, the Massachusetts
Municipal Wholesale Electric Company, the Connecticut Municipal
Electric Energy Cooperative, the New Hampshire Electric Cooperative,
the Maine Public Utility Commission, and the New England Conference
of Public Utility Commissioners (collectively, New England
Commissions).
Edison Electric Institute (EEI).
Energy Financing, Inc. (Energy Financing).
Midwest ISO Transmission Owners (MISO TOs).
National Association of Regulatory Utility Commissioners (NARUC).
New England Consumer-Owned Entities (NECOE).
Public Utilities Commission of the State of California (California
Commission).
Sacramento Municipal Utility District (SMUD).
Southern California Edison Company (SoCal Edison).
Southern Company Services, Inc., on behalf of Alabama Power Company,
Georgia Power Company, Gulf Power Company, and Mississippi Power
Company (collectively, Southern Companies).
Transmission Access Policy Study Group (TAPS).
Transmission Dependent Utility Systems (TDU Systems).
Xcel Energy Services, Inc. (Xcel).

[FR Doc. E6-22693 Filed 1-9-07; 8:45 am]

BILLING CODE 6717-01-P


securities' pool and determining the cash flows available to the asset-
backed security in each scenario. A number of commercially available
options can be used to perform this analysis. Value at risk can be a
good indicator of manipulation risk since low value at risk indicates
that the majority of the cash flows are sufficiently assured. The price
of the asset-backed security in this case is more certain and is less
subject to manipulation risk.
    However, value at risk is by construction estimated for a specified
time period and thus only accounts for the potential losses during such
period, while losses may also occur after this time period. In this
case the price of the asset-backed security may depend on issue-
specific factors and be prone to manipulation despite the estimated
value at risk over the specified time period being low. This may allow
securities with high manipulation risk to rely on the exception.
    One of the commenters proposed as an alternative to use probability
of default-based standard for asset-backed securities calculated using
prices and credit spreads.\308\ However, probability of default is
typically not used for these securities due to the complexity of their
structure and corresponding complexity of the calculations. Further,
another commenter supported proposed Form SF-3 standard to use for the
asset-backed securities due to its uniformity and simplicity.\309\
---------------------------------------------------------------------------

    \308\ See IILF Letter, at 6.
    \309\ See SIFMA Letter 1, at 11.
---------------------------------------------------------------------------

7. Alternatives for Rule 102 Exception
    The Commission also considered and proposed eliminating, without
replacing, the Investment Grade Exception in Rule 102. Disruption to
the trading market may be limited because distribution participants
will still be able to rely on the exception from Rule 101 if they meet
the requirements of the proposed rules. However, one of the commenters
pointed out that eliminating the exception from Rule 102 may affect
issuer-affiliated broker-dealers that do not act as an underwriter and
may need to rely on the Rule 102 exception.\310\ Eliminating the
exception from Rule 102 may increase issuance costs or deter market
participants from issuing such securities. Therefore, elimination of
the exception from Rule 102 was not the best option in comparison to
the alternative selected.
---------------------------------------------------------------------------

    \310\ See SIFMA Letter 1, at 12.
---------------------------------------------------------------------------

8. Alternative for the Record Preservation Requirement
    The Commission considered not adding the record preservation
requirement. The option of not adding the record preservation
requirement for broker-dealers was suggested by one of the commenters
due to the additional burdens it creates for the broker-dealers.\311\
However, the record preservation requirement may help ensure an
estimate of the probability of default is produced for all the
distribution participants to rely upon to determine eligibility of the
issue for the exception. The record preservation requirement also helps
address concerns about the existence of some subjectivity involved in
the selection of a particular structural credit risk model and data
sample specifics by the lead managers, and the possibility of lead
managers selecting these specifics so as to generate a probability of
default estimate below the threshold level. The potential consequences
of not including a record preservation requirement, therefore, could be
that issues with high manipulation risk are allowed to rely on the
exceptions from Regulation M. It is also intended to aid the Commission
staff in examinations of the broker-dealers in evaluation of the
specific model and data used to determine the probability of default of
the issue in addition to exception eligibility.
---------------------------------------------------------------------------

    \311\ See SIFMA Letter 1, at 11.
---------------------------------------------------------------------------

VI. Paperwork Reduction Act

    Certain provisions of the final amendments contain ``collection of
information'' requirements within the meaning of the Paperwork
Reduction Act of 1995 (``PRA'').\312\ The hours and costs associated
with determining whether a Nonconvertible Security qualifies for the
new exception in Rule 101(c)(2)(i) and preserving the corresponding
records under Rule 17a-4(b)(17) constitute PRA burdens.
---------------------------------------------------------------------------

    \312\ 44 U.S.C. 3501 et seq. The burdens associated with the
information collection requirements are referred to as ``PRA
burdens.''
---------------------------------------------------------------------------

    In accordance with the PRA, the Commission is submitting the final
amendments to the rules to the Office of Management and Budget
(``OMB'') for review.\313\ The Commission published a notice requesting
comment on these collections of information requirements in the
Proposal and submitted these requirements to the OMB for review in
accordance with the PRA. An agency may not conduct or sponsor, and a
person is not required to respond to, a collection of information
unless it displays a currently valid control number. The titles and
control numbers for these collections of information are as follows:
---------------------------------------------------------------------------

    \313\ See 44 U.S.C. 3507; 5 CFR 1320.11.

------------------------------------------------------------------------
                                                            OMB control
              Rule                        Title                 no.
------------------------------------------------------------------------
Rule 101.......................  Rule 101, 17 CFR              3235-0464
                                  242.101 (Activities by
                                  Distribution
                                  Participants).
Rule 17a-4.....................  Records to be Preserved       3235-0806
                                  by Certain Brokers and
                                  Dealers.
------------------------------------------------------------------------

    These PRA burdens are distinct from the existing OMB-approved
collection of information burden estimates under Rules 101, 102, and
17a-4 because the Commission has not estimated that respondents incur
PRA burdens when determining whether a security qualifies for the
Investment Grade Exception, nor did Rule 17a-4 include a recordkeeping
requirement in connection with reliance on the Investment Grade
Exception.\314\
---------------------------------------------------------------------------

    \314\ In the Proposal, the Commission proposed to eliminate the
Investment Grade Exception under Rule 102 of Regulation M, without
proposing an alternative standard in its place. However, as
discussed above, in Part II.C, the Commission is adopting an
exception that is based on an issuer's probability of default in
both Rule 102 and Rule 101.
---------------------------------------------------------------------------

    The Commission did not receive any comments on the Proposal's PRA
analysis. While one commenter did reference the potential burden of the

proposed amendments generally,\315\ no commenters specifically
addressed the Commission's estimates of burdens and costs in the
Proposal's PRA analysis. In addition, the Commission's estimates of the
collection of information for the amendments, as adopted, have been
updated from the estimates included in the Proposal, as appropriate,
with the updated estimates based on the modifications in the adopted
rule and based on more recent data.
---------------------------------------------------------------------------

    \315\ SIFMA Letter 1, at 5.
---------------------------------------------------------------------------

    The Commission is adopting in Rules 101 and 102 the proposed
exception that is based on an issuer's probability of default, as
described above in Parts II.A and B, to replace the Investment Grade
Exceptions. The Commission is also adopting a corresponding record
preservation requirement in Rule 17a-4(b), which requires broker-
dealers to preserve the written probability of default determination,
relied upon pursuant to the new exception in Rule 101(c)(2)(i) or Rule
102(d)(2)(i), as applicable.
    As discussed above, Regulation M is designed to preserve the
integrity of the securities trading market as an independent pricing
mechanism by prohibiting activities that could artificially influence
the market for an offered security. Subject to exceptions, Rule 101
prohibits distribution participants and their affiliated
purchasers,\316\ and Rule 102 prohibits issuers, selling security
holders, and their affiliated purchasers, from directly or indirectly
bidding for, purchasing, or attempting to induce another person to bid
for or purchase a covered security during a restricted period.\317\
Rule 17a-4 requires a broker-dealer to preserve certain records if it
makes or receives them.\318\
---------------------------------------------------------------------------

    \316\ 17 CFR 242.101.
    \317\ 17 CFR 242.102.
    \318\ 17 CFR 240.17a-4.
---------------------------------------------------------------------------

    In accordance with the requirements of section 939A(b), the
Commission is adopting amendments to Rules 101 and 102 of Regulation M
that remove the Investment Grade Exceptions and add, in their place,
new exceptions for Nonconvertible Securities for which the issuer's
probability of default, estimated as of the sixth business day
immediately preceding the determination of the offering price and over
the horizon of 12 full calendar months from such day, is 0.055% or
less, as determined and documented, in writing, by the distribution
participant acting as the lead manager (or in a similar capacity) of a
distribution, as derived from a structural credit risk model.\319\ The
Commission is also adopting Rule 17a-4(b)(17), which requires broker-
dealers to preserve the written probability of default determination,
relied upon pursuant to the new exception in Rule 101(c)(2)(i) or Rule
102(d)(2)(i), as applicable, for a period of not less than three years,
the first two years in an easily accessible place.\320\
---------------------------------------------------------------------------

    \319\ 17 CFR 242.101(c)(2)(i), as amended, 242.102(d)(2)(i), as
amended.
    \320\ 17 CFR 240.17a-4(b)(17), as amended.
---------------------------------------------------------------------------

    The Commission is also adopting identical new exceptions in Rules
101(c)(2)(ii) and 102(d)(2)(ii) for asset-backed securities that are
offered pursuant to an effective shelf registration statement filed on
Form SF-3.\321\ The discussion of estimates that follows is limited to
the new information collection requirements that result from the final
amendments related to the probability of default determinations in Rule
101(c)(2)(i), as amended, as well as the record preservation thereof in
reliance on the new exceptions provided in Rule 101(c)(2)(i) or Rule
102(d)(2)(i) pursuant to Rule 17a-4(b)(17). The Commission is not
estimating that the new exception for asset-backed securities that are
offered pursuant to an effective shelf registration statement filed on
Form SF-3 in Rules 101(c)(2)(ii) and 102(d)(2)(ii) will increase or
decrease the existing approved information collections because whether
an asset-backed security is offered pursuant to an effective shelf
registration statement filed on Form SF-3 is an objective, observable
fact that would not incur any PRA burden.
---------------------------------------------------------------------------

    \321\ 17 CFR 242.101(c)(2)(ii), as amended, 242.102(d)(2)(ii),
as amended.
---------------------------------------------------------------------------

A. Respondents

    The respondents under the amended rules are lead managers who
choose to make a probability of default determination in order to rely
on the exception for Nonconvertible Securities and other broker-dealers
who use the lead manager's probability of default determination in
relying on an exception for Nonconvertible Securities. As noted in Part
V.A.1, there were 201 lead managing underwriters and 100 other non-lead
manager broker-dealers of Nonconvertible Securities in 2021.\322\ The
Commission assumes that, on balance, these numbers will remain
consistent given the capital, expertise, and relationships needed to
serve as the lead underwriter of a Nonconvertible Securities offering.
The Commission, therefore, is estimating that 301 respondents will be
subject to PRA burdens under the amendments. The respondents under the
amendments to Rule 101(c)(2)(i) are lead managers who make probability
of default determinations. The Commission, therefore, is estimating
that 201 respondents will be subject to PRA burdens under Rule
101(c)(2)(i), as amended. The respondents under the amendments to Rule
17a-4(b)(17) are broker-dealers who rely on the new exception in Rule
101(c)(2)(i) or Rule 102(d)(2)(i). The Commission, therefore, is
estimating that 301 respondents will be subject to PRA burdens under
new Rule 17a-4(b)(17).\323\
---------------------------------------------------------------------------

    \322\ See supra Part V.A.1.
    \323\ [201 lead manager broker-dealers] + [100 non-lead manager
broker-dealers] = 301 respondents under new Rule 17a-4(b)(17).
---------------------------------------------------------------------------

B. Use of Information

    The information collected under the amendments ensures that the
Nonconvertible Securities that are least likely to be subject to the
type of manipulation that Regulation M seeks to address are excepted
from Rules 101 and 102. Further, the Commission believes that the
information contained in the records required to be preserved pursuant
to Rule 17a-4(b)(17) will facilitate the Commission in conducting
examinations of broker-dealers who rely on the new exceptions in Rule
101(c)(2)(i) or Rule 102(d)(2)(i).

C. Collection of Information

    As discussed below, the Commission believes that respondents will
incur PRA burdens under the amendments to Rule 101(c)(2)(i) because
distribution participants who are acting as the lead manager (or in a
similar capacity) of a distribution and make a probability of default
determination are required for each distribution of Nonconvertible
Securities to determine the subject issuer's probability of default in
order to rely on the exception. These respondents may also incur PRA
burdens in their probability of default determinations. Respondents who
are broker-dealers and rely on the new exception in Rule 101(c)(2)(i)
or Rule 102(d)(2)(i) will incur PRA burdens under the requirements set
forth in new Rule 17a-4(b)(17) because they are required to preserve
records of the written probability of default determination.
1. Burden and Cost Estimates Related to the Rule 101 Amendments
    Rule 101(c)(2)(i), as amended, permits lead managers to gather the
data serving as the inputs and then perform the analysis necessary to
calculate the probability of default of the issuer

whose securities are the subject of the distribution to meet the
conditions of the exception.\324\ This requirement will result in
respondents incurring a PRA recordkeeping burden. This process will
likely be highly automated, and that respondents will initially comply
with this requirement by reprograming systems to create a means to
calculate electronically the probability of default based on manually
gathered and entered inputs for financial modeling. The respondents who
make probability of default determinations will be broker-dealers
serving as lead managers and are likely to have experience in using
their own proprietary version of a publicly available structural credit
risk model. Accordingly, the initial configuration of systems will be
handled internally and take 3 hours per respondent. The Commission also
assumes that broker-dealers serving as lead managers already have the
software and systems in place required to make the calculations.\325\
The Commission therefore estimates that the total industry-wide initial
burden for configuring systems to make and probability of default
estimates is 603 hours.\326\
---------------------------------------------------------------------------

    \324\ The Commission recognizes that some respondents may choose
to utilize the probability of default estimates that are calculated
and made available by a third-party vendor rather than make the
determination themselves. In the Proposal, the Commission noted that
the Commission's burden estimates for the adopted amendments to Rule
101 are based on respondents gathering the required data and
calculating the probability of default, internally, without the use
of third-party vendors, because the Commission lacks granular
information from which to base an estimate of the proportion of
respondents that would use vendors. The Commission requested comment
on the extent to which respondents may use third-party vendors, as
well as the costs and time burdens of using such services. See
Proposal, 87 FR 18326 n.129. However, the Commission did not receive
comments in response to this request. For purposes of estimating the
PRA burdens under the final rules as amended, the Commission
continues to assume that all respondents will make the probability
of default determination internally with data they have gathered,
rather than use third party vendors. As discussed above, in Part
II.A.1, there may be distributions with more than one distribution
participant acting as the lead manager (or in a similar capacity),
but only one of the distribution participants acting as the lead
manager would be permitted to make the probability of default
determination for the particular distribution. See supra note 91.
Therefore, for purposes of the PRA estimations in this release, only
one lead manager on any distribution for purposes of these
calculations is assumed.
    \325\ Further, respondents who choose to utilize probability of
default estimates that are calculated and made available by a third-
party vendor will already have access to the vendor's software and
systems containing these estimates, typically as part of an existing
subscription, so they will not need to procure further services or
subscriptions from these vendors to access any such determinations.
However, as noted above, for purposes of estimating these PRA
burdens, the Commission assumes all respondents would make their own
calculations and not use third party vendors. This assumption is
being made to provide an estimate reflecting for the more costly of
the two approaches.
    \326\ [201 lead managers] x [3 hours] = 603 hours. The Proposal
included 237 respondents, which was taken from available data from
2020. The number included herein reflects the number from the
available data from 2021, as discussed above, in Part V.A.1. In
addition, under the Proposal, the 237 figure included non-lead
manager broker-dealers who would have been eligible, under the
proposed Rule 101(c)(2)(i), to make probability of default
determinations in order to meet the Nonconvertible Securities
exception's conditions.
---------------------------------------------------------------------------

    An issuer's probability of default is forward-looking and changes
over time, so the Commission believes that respondents will manually
gather the inputs required to calculate an issuer's probability of
default each time it participates in a distribution of Nonconvertible
Securities. There were 33,798 offerings of Nonconvertible Securities in
2021.\327\ Because financial modeling generally, and the probability of
default calculation more specifically, is well-known by industry
participants, the Commission believes that respondents have employees
who are familiar with how to gather the required model inputs. The
Commission, therefore, estimates that it will take lead-manager
respondents roughly one hour per distribution of Nonconvertible
Securities to determine and document, in writing, the probability of
default determinations. Accordingly, the Commission estimates that
calculating the probability of default pursuant to Rule 101(c)(2)(i),
as amended, will result in an aggregate annual ongoing industry-wide
burden of 33,798 hours. The Commission estimates that the total PRA
burden resulting from the final amendments to Rule 101 is 34,401 hours
in the first year \328\ and 33,798 hours thereafter.
---------------------------------------------------------------------------

    \327\ This number was obtained from Mergent, a financial data
provider.
    \328\ [603 hours (initial burden)] + [33,798 hours (ongoing
annual burden)] = 34,401 hours.
---------------------------------------------------------------------------

    The Commission does not believe that the amendments to Rule
101(c)(2)(ii) excepting asset-backed securities that are offered
pursuant to an effective shelf registration statement filed on Form SF-
3 will result in respondents incurring PRA burdens because whether an
asset-backed security has an effective shelf registration statement
filed on Form SF-3 is an objective, observable fact.\329\ Further,
there is no corresponding record preservation requirement for
respondents documenting reliance on the exception for asset-backed
securities under Rule 101(c)(2)(ii), as amended.
---------------------------------------------------------------------------

    \329\ See 17 CFR 239.45.
---------------------------------------------------------------------------

2. Burden and Cost Estimates Related to the Rule 17a-4 Amendments
    New Rule 17a-4(b)(17) requires broker-dealers to preserve the
written probability of default determination, relied upon pursuant to
the new exception in Rule 101(c)(2)(i) or Rule 102(d)(2)(i), as
applicable, for a period of not less than three years, the first two
years in an easily accessible place.
    The Commission estimates that this record preservation requirement
imposes an initial burden of 25 hours per respondent for updating the
applicable policies and systems required to account for preserving the
records made pursuant to Rule 101(c)(2)(i), as amended. Accordingly,
the Commission estimates that the total industry-wide initial burden
for this requirement is 7,525 hours.\330\ The Commission also estimates
that respondents will incur an ongoing annual burden of 10 hours per
firm for maintaining such records, as well as to make additional
updates to the applicable record preservation policies and systems to
account for preserving the records pursuant to new Rule 17a-4(b)(17),
resulting in a total ongoing industry-wide burden of 3,010 hours.\331\
The Commission, therefore, estimates that the total PRA burden
resulting from the amendment to Rule 17a-4 is 10,535 hours in the first
year \332\ and 3,010 hours per year thereafter.
---------------------------------------------------------------------------

    \330\ [301 respondents] x [25 hours] = 7,525 hours.
    \331\ [301 respondents] x [10 hours] = 3,010 hours.
    \332\ [7,525 hours (initial burden)] + [3,010 hours (ongoing
annual burden)] = 10,535 hours.

                                                PRA Summary Table
----------------------------------------------------------------------------------------------------------------
                                                                                Ongoing annual
                                                                  Initial burden   burden hours/     Total PRA
            Industry-wide burden due to amendments to                  hours        year (after    burden hours
                                                                                first year)    in first year
----------------------------------------------------------------------------------------------------------------
Rule 101........................................................             603          33,798          34,401

Rule 17a-4......................................................           7,525           3,010          10,535
----------------------------------------------------------------------------------------------------------------

D. Collection of Information Is Mandatory

    The information collections for making probability of default
determinations under the amendments to Rule 101 are mandatory for
reliance on exceptions in Rule 101(c)(2)(i) or Rule 102(d)(2)(i). In
addition, the information collections involving the preservation of
written probability of default determinations under the amendments to
Rule 17a-4 are mandatory if a broker-dealer relies on the new exception
in Rule 101(c)(2)(i) or Rule 102(d)(2)(i).

E. Confidentiality of Responses to Collection of Information

    The Commission would not typically receive confidential information
as a result of these collections of information. To the extent that the
Commission receives--through its examination and oversight program,
through an investigation, or by some other means--records or
disclosures from a distribution participant regarding the probability
of default determination, such information would be kept confidential,
subject to the provisions of applicable law.

F. Retention Period for Record Preservation Requirement

    Pursuant to new Rule 17a-4(b)(17), a broker-dealer is required to
preserve the written probability of default determination, relied upon
pursuant to the new exception in Rule 101(c)(2)(i) or Rule
102(d)(2)(i), as applicable, for a period of not less than three years,
the first two years in an easily accessible place.

VII. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act (``RFA'') \333\ requires Federal
agencies, in promulgating rules, to consider the impact of those rules
on ``small entities,'' \334\ a term that includes ``small businesses.''
\335\ Section 603(a) \336\ of the Administrative Procedure Act,\337\ as
amended by the section 604(a) of the RFA requires the Commission to
undertake a final regulatory flexibility analysis of rules it is
adopting, unless the Commission certifies that the rules would not have
a significant impact on a substantial number of small entities.\338\
---------------------------------------------------------------------------

    \333\ 5 U.S.C. 601 et seq.
    \334\ 5 U.S.C. 605(b).
    \335\ Although section 601(b) of the RFA defines the term
``small business,'' the statute permits agencies to formulate their
own definitions. The Commission has adopted definitions for the term
``small business'' for the purposes of Commission rulemaking in
accordance with the RFA. Those definitions, as relevant to this
rulemaking, are set forth in 17 CFR 240.0-10 (``Rule 0-10''). Rule
0-10 also provides that the Commission may, if warranted by the
circumstances, use a different definition for particular
rulemakings. See 17 CFR 240.0-10.
    \336\ 5 U.S.C. 603(a).
    \337\ 5 U.S.C. 551 et seq.
    \338\ 5 U.S.C. 605(b).
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    Small entities include broker-dealers with total capital (net worth
plus subordinated liabilities) of less than $500,000 on the date in the
prior fiscal year as of which its audited financial statements were
prepared pursuant to Rule 17a-5(d) under the Exchange Act,\339\ or, if
not required to file such statements, a broker-dealer who had total
capital (net worth plus subordinated liabilities) of less than $500,000
on the last day of the preceding fiscal year (or in the time it has
been in business, if shorter), and is not affiliated with any person
(other than a natural person) who is not a small business or small
organization.\340\ A small business or small organization, for purposes
of ``issuers'' or ``person'' other than an investment company, is
defined as a person who, on the last day of its most recent fiscal
year, had total assets of $5 million or less.\341\ In the Proposal, the
Commission certified, pursuant to section 605(b) of the RFA, that the
proposed amendments to Rules 101 and 102 would not have a significant
economic impact on a substantial number of small entities.\342\ The
Commission requested but did not receive any comments on the
certification as it related to the entities impacted by Rule 101 or
Rule 102 of Regulation M, or by Rule 17a-4 under the Exchange Act.
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    \339\ See 17 CFR 240.17a-5(d).
    \340\ See 17 CFR 240.0-10(c).
    \341\ 17 CFR 242.0-10(a).
    \342\ See Proposal, 87 FR 18337.
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    Based on the Commission's analysis of the existing information
relating to broker-dealers who are subject to Rules 101, 102,\343\ and
17a-4, it is unlikely that any broker-dealer categorized as a ``small
business'' or ``small organization'' under Rule 0-10 could serve as an
underwriter or other distribution participant, as they would almost
certainly have insufficient capital to participate in underwriting
activities. In addition, the Commission continues to believe that none
of the various persons affected by the amendments would qualify as a
small entity under the Rule 0-10 definition as it is unlikely that any
issuer of that size had investment grade securities that were eligible
for the Investment Grade Exception. Accordingly, the Commission
believes it is unlikely that, in the future, a small entity may become
impacted by the amendments because broker-dealers who enter this market
are likely to have at least $500,000 in total capital, as described
above, or to be affiliated with a person who is not a small business or
small organization as defined under Rule 0-10, and because issuers of
securities that are eligible for the new exceptions provided in Rules
101(c)(2) and 102(d)(2) are likely to have total assets greater than $5
million.
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    \343\ As discussed above, in Part II.B, broker-dealers who are
affiliated with the issuer and do not meet the definition of
``distribution participant'' under Rule 100(b) of Regulation M may
be covered persons under Rule 102. Even if those broker-dealers had
net capital over $500,000, they would not be small entities under
Rule 0-10 because they are affiliated with an issuer (of investment
grade securities) that is not a small entity.
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    For the foregoing reasons, the Commission certifies, pursuant to
section 605(b) of Title 5 of the U.S. Code, that the amendments to
Rules 100, 101, 102, and 17a-4 will not have a significant economic
impact on a substantial number of small entities.

Statutory Authority

    The final amendments contained in this release are being adopted
under the authority set forth in sections 939 and 939A of the Dodd-
Frank Act and

sections 3(b), 15, 23(a), and 36 of the Exchange Act.

List of Subjects in 17 CFR Parts 240 and 242

    Broker-dealers, Fraud, Issuers, Reporting and recordkeeping
requirements, Securities.

Text of Rule Amendments

    For the reasons set out in the preamble, the Commission is amending
title 17, chapter II of the Code of Federal Regulations as follows:

PART 240--GENERAL RULES AND REGULATIONS, SECURITIES EXCHANGE ACT OF
1934

0
1. The authority citation for part 240 continues to read, in part, as
follows:

    Authority:  15 U.S.C. 77c, 77d, 77g, 77j, 77s, 77z-2, 77z-3,
77eee, 77ggg, 77nnn, 77sss, 77ttt, 78c, 78c-3, 78c-5, 78d, 78e, 78f,
78g, 78i, 78j, 78j-1, 78j-4, 78k, 78k-1, 78l, 78m, 78n, 78n-1, 78o,
78o-4, 78o-10, 78p, 78q, 78q-1, 78s, 78u-5, 78w, 78x, 78dd, 78ll,
78mm, 80a-20, 80a-23, 80a-29, 80a-37, 80b-3, 80b-4, 80b-11, 7201 et
seq., and 8302; 7 U.S.C. 2(c)(2)(E); 12 U.S.C. 5221(e)(3); 18 U.S.C.
1350; and Pub. L. 111-203, 939A, 124 Stat. 1376 (2010); and Pub. L.
112-106, sec. 503 and 602, 126 Stat. 326 (2012), unless otherwise
noted.
* * * * *
    Section 240.17a-4 also issued under secs. 2, 17, 23(a), 48 Stat.
897, as amended; 15 U.S.C. 78a, 78d-1, 78d-2; sec. 14, Pub. L. 94-
29, 89 Stat. 137 (15 U.S.C. 78a); sec. 18, Pub. L. 94-29, 89 Stat.
155 (15 U.S.C. 78w);
* * * * *

0
2. Amend Sec.  240.17a-4 by adding paragraph (b)(17) to read as
follows:

Sec.  240.17a-4  Records to be preserved by certain exchange members,
brokers and dealers.

* * * * *
    (b) * * *
    (17) The written probability of default determination, relied upon
by such broker or dealer, pursuant to Sec.  242.101(c)(2)(i) or Sec.
242.102(d)(2)(i) of this chapter (Rule 101 or Rule 102 of Regulation
M), as applicable.
* * * * *

PART 242--REGULATIONS M, SHO, ATS, AC, NMS, AND SBSR AND CUSTOMER
MARGIN REQUIREMENTS FOR SECURITY FUTURES

0
3. The authority citation for part 242 continues to read as follows:

    Authority: 15 U.S.C. 77g, 77q(a), 77s(a), 78b, 78c, 78g(c)(2),
78i(a), 78j, 78k-1(c), 78l, 78m, 78n, 78o(b), 78o(c), 78o(g),
78q(a), 78q(b), 78q(h), 78w(a), 78dd-1, 78mm, 80a-23, 80a-29, and
80a-37.

0
4. Amend Sec.  242.100 in paragraph (b) by adding in alphabetical order
a definition for ``Structural credit risk model'' to read as follows:

Sec.  242.100  Preliminary note; definitions.

* * * * *
    (b) * * *
    Structural credit risk model means any commercially or publicly
available model that calculates, based on an issuer's balance sheet,
the probability that the value of the issuer will fall below the
threshold at which the issuer would fail to make scheduled debt
payments, at or by the expiration of a defined period.
* * * * *

0
5. Amend Sec.  242.101 by revising paragraph (c)(2) to read as follows:

Sec.  242.101  Activities by distribution participants.

* * * * *
    (c) * * *
    (2) Certain nonconvertible and asset-backed securities. (i)
Nonconvertible debt securities and nonconvertible preferred securities
of issuers for which the probability of default, estimated as of the
sixth business day immediately preceding the determination of the
offering price and over the horizon of 12 full calendar months from
such day, is 0.055% or less, as determined and documented, in writing,
by the distribution participant acting as the lead manager (or in a
similar capacity) of a distribution, as derived from a structural
credit risk model; or
    (ii) Asset-backed securities that are offered pursuant to an
effective shelf registration statement filed on Form SF-3 (Sec.  239.45
of this chapter); or
* * * * *

0
6. Amend Sec.  242.102 by revising paragraph (d)(2) to read as follows:

Sec.  242.102  Activities by issuers and selling security holders
during a distribution.

* * * * *
    (d) * * *
    (2) Certain nonconvertible and asset-backed securities. (i)
Nonconvertible debt securities and nonconvertible preferred securities
of issuers for which the probability of default, estimated as of the
sixth business day immediately preceding the determination of the
offering price and over the horizon of 12 full calendar months from
such day, is 0.055% or less, as determined and documented, in writing,
by the distribution participant acting as the lead manager (or in a
similar capacity) of a distribution, as derived from a structural
credit risk model, pursuant to Sec.  242.101(c)(2)(i); or
    (ii) Asset-backed securities that are offered pursuant to an
effective shelf registration statement filed on Form SF-3 (Sec.  239.45
of this chapter); or
* * * * *

    By the Commission.

    Dated: June 7, 2023.
Vanessa A. Countryman,
Secretary.
[FR Doc. 2023-12591 Filed 6-16-23; 8:45 am]
BILLING CODE 8011-01-P


[Federal Register Volume 77, Number 28 (Friday, February 10, 2012)]
[Notices]
[Page 7142]
[FR Doc No: 2012-3163]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 2309-019]

Jersey Central Power and Light Company, PSEG Fossil, LLC; Notice
of Availability of Environmental Assessment

    In accordance with the National Environmental Policy Act of 1969
and the Federal Energy Regulatory Commission's regulations, 18 CFR part
380, the Office of Energy Projects has reviewed the application for a
new license for the 364.5-megawatt (MW) Yards Creek Pumped Storage
Hydroelectric Project located on Yards Creek, in the townships of
Hardwick and Blairstown, Warren County, New Jersey and has prepared an
environmental assessment (EA). In the EA, Commission staff analyzes the
potential environmental effects of licensing the project and conclude
that issuing a license for the project, with appropriate environmental
measures, would not constitute a major federal action significantly
affecting the quality of the human environment.
    A copy of the EA is on file with the Commission and is available
for public inspection. The EA may also be viewed on the Commission's
Web site at http://www.ferc.gov using the ``eLibrary'' link. Enter the
docket number excluding the last three digits in the docket number
field to access the document. For assistance, contact FERC Online
Support at<EMAIL_ADDRESS>or toll-free at<PHONE_NUMBER>,
or for TTY,<PHONE_NUMBER>.
    You may also register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filings and issuances
related to this or other pending projects. For assistance, contact FERC
Online Support.
    Comments on the EA should be filed within 30 days from the issuance
date of this notice, and should be addressed to the Secretary, Federal
Energy Regulatory Commission, 888 First Street NE., Room 1-A,
Washington, DC 20426. Please affix ``Yards Creek Pumped Storage
Hydroelectric Project No. 2309-019'' to all comments. Comments may be
filed electronically via Internet in lieu of paper. The Commission
strongly encourages electronic filings. See 18 CFR 385.2001(a)(1)(iii)
and the instructions on the Commission's Web site under the ``eFiling''
link. Although the Commission strongly encourages electronic filings,
documents may also be paper-filed. To paper-file, mail an original and
seven copies to: Kimberly D. Bose, Secretary, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426. For further
information contact Allyson Conner at<PHONE_NUMBER>.

    Dated: February 6, 2012.
Kimberly D. Bose,
Secretary.
[FR Doc. 2012-3163 Filed 2-9-12; 8:45 am]
BILLING CODE 6717-01-P