[Federal Register: January 10, 2007 (Volume 72, Number 6)]
[Rules and Regulations]
[Page 1152-1173]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10ja07-9]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM06-4-001; Order No. 679-A]
Promoting Transmission Investment Through Pricing Reform
Issued December 22, 2006.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule; order on rehearing.
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SUMMARY: In this order on rehearing, the Federal Energy Regulatory
Commission (Commission) reaffirms its determinations in part and grants
rehearing in part of Promoting Transmission Investment through Pricing
Reform, Order No. 679. Order No. 679 amended Commission regulations to
establish incentive-based (including performance-based) rate treatments
for the transmission of electric energy in interstate commerce by
public utilities for the purpose of benefiting consumers by ensuring
reliability and reducing the cost of delivered power by reducing
transmission congestion.
DATES: Effective Date: This final rule and order on rehearing will be
effective on February 9, 2007.
FOR FURTHER INFORMATION CONTACT:
Jeffrey Hitchings (Technical Information), Office of Energy Markets and
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, 202-502-6042.
Andre Goodson (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888
[[Page 1153]]
First Street, NE., Washington, DC 20426, 202-502-8560.
Tina Ham (Legal Information), Office of the General Counsel, Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426, 202-502-6224.
SUPPLEMENTARY INFORMATION:
Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly,
Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.
Table of Contents
Paragraph
numbers
I. Introduction............................................. 1
II. Background.............................................. 9
III. Discussion............................................. 11
A. Procedural Matters................................... 11
B. Statutory Arguments.................................. 13
1. Rehearing Requests............................... 13
2. Commission Determination......................... 14
C. Nexus Requirement.................................... 16
1. Rehearing Requests............................... 17
2. Commission Determination......................... 20
D. Cost-Benefit Analysis................................ 28
1. Rehearing Requests............................... 29
2. Commission Determination......................... 35
E. Rebuttable Presumptions.............................. 41
1. Rehearing Requests............................... 42
2. Commission Determination......................... 46
F. ROE Sufficient to Attract Investment................. 51
1. Rehearing Requests............................... 52
2. Commission Determination......................... 59
G. Incentives Available to Transcos..................... 71
1. Rehearing Requests............................... 72
2. Commission Determination......................... 76
H. Transmission Organization Incentive.................. 79
1. Rehearing Requests............................... 80
2. Commission Determination......................... 86
I. Hypothetical Capital Structure....................... 91
1. Rehearing Requests............................... 92
2. Commission Determination......................... 93
J. Single-Issue Ratemaking.............................. 94
1. Rehearing Requests............................... 95
2. Commission Determination......................... 97
K. Public Power......................................... 100
1. Rehearing Requests............................... 101
2. Commission Determination......................... 102
L. Other Issues......................................... 103
1. Recovery of Costs of Abandoned Facilities........ 104
2. Prudently Incurred Costs......................... 108
3. Regional Planning................................ 110
4. CWIP............................................. 112
5. Reporting Requirement: FERC-730.................. 117
6. Miscellaneous.................................... 121
IV. Information Collection Statement........................ 137
V. Document Availability.................................... 138
VI. Effective Date.......................................... 141
APPENDIX
Order on Rehearing
I. Introduction
1. On July 20, 2006, the Commission issued a Final Rule in this
proceeding.\1\ In the Final Rule, the Commission amended its
regulations to establish incentive-based (including performance-based)
rate treatments for the transmission of electric energy in interstate
commerce by public utilities. These incentives are intended to benefit
consumers by ensuring reliability and reducing the cost of delivered
power by reducing transmission congestion. We took this action pursuant
to section 1241 of the Energy Policy Act of 2005 (EPAct 2005),\2\ which
added a new section 219 to the Federal Power Act (FPA). The Final Rule
identified ratemaking treatments available under section 219. The Final
Rule did not grant incentives to any particular entity, but rather
required each applicant to demonstrate that it could meet the
requirements of section 219 and the Final Rule.
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\1\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 71 FR 43294 (July 31, 2006), FERC Stats. & Regs. ]
31,222 (2006) (Order No. 679 or Final Rule).
\2\ Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat.
594, 315 and 1283 (2005).
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2. Many entities sought rehearing of the Final Rule.\3\ The
petitioners representing consumer interests argue that the Final Rule
was too permissive in offering rate incentives. We have carefully
reviewed these petitions and grant them in part in this order.
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\3\ The parties who filed the requests for rehearing and/or
clarification are listed in Appendix A.
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3. In doing so, we do not, however, depart from a fundamental
commitment to provide incentives to support the development of
transmission infrastructure. Section 219 was enacted
[[Page 1154]]
because of a long decline in transmission investment that is
threatening reliability and causing billions of dollars in congestion
costs. To reverse this historical trend, section 219 directed the
Commission to ``establish, by rule, incentive-based (including
performance-based) rate treatments'' that: ``Promote reliable and
economically efficient transmission and generation of electricity by
promoting capital investment in the enlargement, improvement,
maintenance, and operation of all facilities for the transmission of
electric energy in interstate commerce, regardless of the ownership of
the facilities; provide a return on equity that attracts new investment
in transmission facilities (including related transmission
technologies); encourage deployment of transmission technologies and
other measures to increase the capacity and efficiency of existing
transmission facilities and improve the operation of the facilities;
and allow recovery of--(A) all prudently incurred costs necessary to
comply with mandatory reliability standards issued pursuant to section
215 and (B) all prudently incurred costs related to transmission
infrastructure development pursuant to section 216.'' \4\ The Final
Rule fulfilled that command by providing a range of rate treatments
that remove impediments to new investment or otherwise attract that
investment.
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\4\ 16 U.S.C.A. 824s(a), (b)(1) (West Supp. 2006).
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4. This order retains those rate treatments, but modifies the way
in which they are applied in three principal respects to address the
concerns of petitioners.
5. First, NARUC argues that we erred in rebuttably presuming that
certain review processes (e.g., state siting approvals and regional
planning processes) satisfy section 219's requirement that a
transmission project ensure reliability or reduce congestion. NARUC
contends that these review processes do not, in all cases, establish
the need for a particular facility. We grant rehearing in part on this
issue. The Commission created the rebuttable presumption because we do
not wish to duplicate the work of state siting authorities, regional
planning processes, or the U.S. Department of Energy (DOE) under EPAct
section 1221. However, we agree with NARUC to the extent that, if
review processes do not include a determination of whether a project
ensures reliability or reduces congestion, no rebuttable presumption
should exist for that project. We will therefore require that each
applicant explain whether any process being relied upon for a
rebuttable presumption includes a determination that the project is
necessary to ensure reliability or reduce congestion. Furthermore, we
clarify that this rebuttable presumption applies only to whether the
project reduces congestion or encourages reliability, not the
additional requirements of the Final Rule. As discussed more fully
elsewhere in this order, we also grant rehearing with respect to the
Final Rule's rebuttable presumption concerning a National Interest
Electric Transmission Corridor (NIETC) designation.
6. Second, the Final Rule required that each applicant demonstrate
a nexus between the incentive being sought and the investment being
made. Several petitioners argue that the nexus test is not sufficiently
rigorous to protect consumers. We grant rehearing in part on this
issue. The Final Rule stated that the nexus test is to be applied
separately to each incentive, rather than to the package of incentives
as a whole. We agree that this approach fails to protect consumers
where an applicant both seeks incentives that reduce the risk of the
project and seeks an enhanced rate of return on equity (ROE) for
increased risk. We will therefore grant in part rehearing and require
applicants to demonstrate that the total package of incentives is
tailored to address the demonstrable risks or challenges faced by the
applicant in undertaking the project.\5\ If some of the incentives in
the package reduce the risks of the project, that fact will be taken
into account in any request for an enhanced ROE.
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\5\ The Commission will apply a rule of reason with respect to
what is sufficient to meet the requirement of ``demonstrable'' risk
or challenge. An applicant may provide specific evidence of a risk
or challenge or a supported explanation of why it faces a particular
risk or challenge.
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7. Third, several petitioners argue that the Final Rule erred in
its treatment of incentive returns on equity. Specifically, they fear
the Commission will routinely grant ROEs at the top end of the zone of
reasonableness. Although the Commission has broad discretion to
establish returns on equity anywhere within the zone of reasonableness,
we must be careful in the manner we exercise this discretion. The
Commission clarifies below that we do not intend to grant incentive
returns ``routinely'' or that, when granted, they will always be at the
``top'' of the zone of reasonableness. Rather, each applicant will,
first, be required to justify a higher ROE under the required nexus
test and, second, to justify where in the zone of reasonableness that
return should lie. Furthermore, we recognize that some investors may
desire up-front certainty regarding ROE before they invest in a
particular project. Because our traditional ratemaking practice
typically determines ROE in a hearing only after an investment is made
and a facility is constructed, it does not provide such up-front
certainty. We therefore clarify that we will entertain requests for a
specific ROE determination in a petition for declaratory order.
8. In this order, the Commission denies in part and grants in part
the requests for rehearing and/or clarification.
II. Background
9. Section 1241 of EPAct 2005 directed the Commission to establish,
no later than one year after enactment of section 219, by rule,
incentive-based (including performance-based) rate treatments for the
transmission of electric energy in interstate commerce by public
utilities for the purpose of benefiting consumers by ensuring
reliability and reducing the cost of delivered power by reducing
transmission congestion.\6\ To that end, the Commission issued a Notice
of Proposed Rulemaking (NOPR) \7\ on November 18, 2005 seeking comment
on the Commission's proposal to comply with section 219. In the NOPR,
the Commission stated that the purpose of this rulemaking is to promote
greater capital investment in new transmission capacity, recognizing
that the need for capital investment in energy infrastructure is a
national problem that requires a national solution. Inadequate
transmission infrastructure results in transmission congestion that
impedes competitive wholesale markets and impairs the reliability of
the electric grid.\8\
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\6\ 16 U.S.C.A. 824s(a) (West Supp. 2006).
\7\ Promoting Transmission Investment Through Pricing Reform,
Notice of Proposed Rulemaking, 70 FR 71409 (Nov. 29, 2005), FERC
Stats. & Regs., Proposed Regs. ] 32,593 (2005).
\8\ Id. P 2.
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10. After considering the comments on the NOPR, the Commission
issued its Final Rule on transmission investment incentives to address
the need for transmission capacity. In the Final Rule, the Commission
provided incentives for transmission infrastructure investment that
will help ensure the reliability of the bulk power transmission system
in the United States and reduce the cost of delivered power to
customers by reducing transmission congestion. The Final Rule
identified specific incentives that the Commission will allow when
justified in the context of individual declaratory orders or section
205 filings
[[Page 1155]]
by public utilities under the FPA.\9\ The Commission stated that the
Final Rule does not grant incentives to any public utility but instead
permits an applicant to tailor its proposed incentives to the type of
transmission investments being made and to demonstrate that its
proposal meets the requirements of section 219. Further, incentives
will be permitted only if the incentive package as a whole results in a
just and reasonable rate.\10\
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\9\ Order No. 679, FERC Stats. & Regs ] 31,222 at P1.
\10\ Id. P. 2. Also, in the Final Rule, the Commission agreed
with comments that new transmission technologies will be adopted
when they are cost effective. The Commission determined that
incentives will be considered for advanced technologies through the
same evaluation process as other technologies. The Commission
declined to make generic determinations regarding the applicability
of incentives to particular technologies. Rather, the Final Rule
determined that to the extent that applicants seek additional
incentives for advanced technologies, the Commission will consider
the propriety of such incentives on a case-by-case basis. Id. P 288-
93, 298-99. The Final Rule required applicants for incentive rate
treatment to provide a technology statement that describes what
advanced technologies have been considered and, if those
technologies are not to be deployed or have not been deployed, an
explanation of why they were not deployed. Id. P 302. No party
sought rehearing concerning the Final Rule's determinations
regarding advanced technologies.
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III. Discussion
A. Procedural Matters
11. In response to the Final Rule, a number of parties submitted
timely requests for rehearing and/or clarification. On August 22, 2006,
the Attorney General of the State of Connecticut (Connecticut AG) filed
a request for rehearing out of time, seeking to support and join in all
aspects the New England Commissions' request for rehearing. On
September 21, 2006, International Transmission Company (International
Transmission) filed an answer to SoCal Edison's request for rehearing.
12. Pursuant to Rule 713(b) of the Commission's Rules of Practice
and Procedure, 18 CFR 385.713(b) (2006), we will deny the request for
rehearing of the Connecticut Attorney General because it was filed more
than 30 days after issuance of the Final Rule.\11\ Rule 713(d) of the
Commission's Rules of Practice and Procedure \12\ prohibits an answer
to a request for rehearing. Therefore, we deny International
Transmission's answer to SoCal Edison's request for rehearing.
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\11\ We note, however, that the Connecticut Attorney General
supports New England Commissions' request for rehearing, which we
address in this order.
\12\ 18 CFR 385.713(d) (2006).
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B. Statutory Arguments
1. Rehearing Requests
13. APPA/NRECA argue that the Commission misinterpreted section 219
as requiring greater flexibility in ratemaking practices. According to
APPA/NRECA, ``incentives'' are not necessary to attract capital
because, under existing Supreme Court precedent, ``a public utility's
rate of return should also be sufficient to attract investment in new
transmission facilities.'' \13\ APPA/NRECA therefore conclude that
section 219 merely ``codified the longstanding Commission and judicial
interpretations of FPA section 205's requirement that rates be just and
reasonable.'' \14\
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\13\ APPA/NRECA at 12.
\14\ Id. at 12-13.
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2. Commission Determination
14. We agree with APPA/NRECA that section 219 did not modify the
requirement that rates be just and reasonable under section 205, but
disagree that it did no more than restate that longstanding principle.
Section 219 makes very clear that the Commission ``shall establish, by
rule, incentive-based (including performance-based) rate treatments''
and that these rate treatments ``shall * * * promote reliable and
economically efficient transmission and generation of electricity by
promoting capital investment in the enlargement, improvement,
maintenance, and operation of all facilities for the transmission of
electric energy in interstate commerce, regardless of the ownership of
the facilities; provide a return on equity that attracts new investment
in transmission facilities (including related transmission
technologies); encourage deployment of transmission technologies and
other measures to increase the capacity and efficiency of existing
transmission facilities and improve the operation of the facilities and
allow recovery of--(A) all prudently incurred costs necessary to comply
with mandatory reliability standards issued pursuant to section 215 and
(B) all prudently incurred costs related to transmission infrastructure
development pursuant to section 216.'' \15\ These words do far more
than ``codify'' the just and reasonable standard; they command the
Commission to use its discretion under section 205 to promote capital
investment. Furthermore, Congress in section 219 even highlighted the
importance of investment in economically or technologically efficient
transmission infrastructure.\16\ Section 219 was enacted against the
backdrop of a long decline in transmission investment that is imposing
substantial costs--in congestion and service interruptions--on
consumers. If Congress had deemed our existing practices sufficient to
reverse this trend, there would have been little need to enact section
219. Section 219 does not simply ``codify'' our legal authority; it
requires us to take affirmative action to promote new investment.
Although the resulting rates must be just and reasonable, the
Commission has significant discretion under section 205 in making that
determination and section 219 provides clear direction that we use that
discretion to promote new infrastructure, not simply maintain the
status quo.
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\15\ 16 U.S.C.A. 824s(a), (b)(1)-(4) (West Supp. 2006).
\16\ See id. at 824s(a) and (b)(3).
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15. While section 219 requires us to do more than maintain the
status quo for transmission pricing, we recognize that our traditional
ratemaking authority also requires us to establish a return on a public
utility's assets that is ``reasonably sufficient to assure confidence
in the financial soundness of the utility and should be adequate to
maintain and support its credit and enable it to raise money necessary
for the proper discharge of its public duties'' \17\ and ``should be
sufficient to assure confidence in the financial integrity of the
enterprise, so as to maintain its credit and to attract capital.'' \18\
Thus, a base-level ROE sufficient to promote capital investment in
transmission facilities historically has not been considered an
``incentive,'' but a requirement of establishing a just and reasonable
rate.\19\ In this regard, we
[[Page 1156]]
recognize that our responsibilities under section 205 and our
responsibilities under section 219 overlap in significant ways. We
recognize that it may be difficult to meaningfully distinguish between
an ROE that appropriately reflects a utility's risk and ability to
attract capital and an ``incentive'' ROE to attract new investment.
Notwithstanding this difficult distinction, consistent with Congress'
direction in section 219, we are obligated to establish ROEs for public
utilities that both reflect the financial and regulatory risks
attendant to a particular project and that are sufficient to actively
promote capital investment. We will do so within the zone of
reasonableness, including above the midpoint where appropriate, to
accomplish these regulatory responsibilities.\20\ This end-result ROE,
whether characterized as an incentive pursuant to section 219 or as a
base-level ROE consistent with the just and reasonable standard of
section 205, will take into consideration financial and regulatory
risks attendant to the project and thereby satisfy Congress' direction
that the Commission ``provide a return on equity that attracts new
investment in transmission facilities * * *.'' \21\
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\17\ Bluefield Waterworks & Improvement Co. v. Pub. Serv. Comm'n
of W. Va., 262 U.S. 679, 693 (1923).
\18\ FPC v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944).
\19\ In contrast to a base-level ROE that reflects the financial
and regulatory risks of an investment, an ``incentive'' has been
more typically associated with specific basis point additions to a
base ROE to satisfy discrete policy objectives. See, e.g., Western
Area Power, 99 FERC ] 61,306, reh'g denied, 100 FERC ] 61,331 (2002)
(Western), aff'd sub nom. Public Utilities Commission of the State
of California v. FERC, 367 F.3d 925 (D.C. Cir. 2004); Michigan
Electric Transmission Co., LLC, 105 FERC ] 61,214 (2003) (METC);
American Transmission Company, L.L.C., 105 FERC ] 61,388 (2003)
(American Transmission); ITC Holdings Corp., 102 FERC ] 61,182,
reh'g denied, 104 FERC ] 61,033 (2003) (ITC Holdings); Regional
Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6,
2000), FERC Stats. & Regs. ] 31,089 (1999), order on reh'g, Order
No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & Regs. ] 31,092
(2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish County,
Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001) (Order No. 2000).
Section 219 addresses both situations. In addition to requiring the
Commission to establish, by rule, incentive rate treatments to
promote transmission investment generally, section 219 also requires
the Commission to establish incentive-based rates to encourage
transmission technologies and other measures to increase the
capacity and efficiency of existing transmission facilities. Thus,
Congress intended for us to establish an ROE sufficient to reflect
financial and regulatory risks and also to consider discrete ROE
incentives for, among other things, participation in transmission
organizations, projects with particular benefits to reliability or
reducing congestion, new technologies and efficiency enhancements.
\20\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 93.
\21\ 16 U.S.C.A. 824s(b)(2) (West Supp. 2006).
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C. Nexus Requirement
16. In the Final Rule, the Commission stated that the applicant
must demonstrate that: (1) 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; (2) there is a nexus between the incentive sought and the
investment being made; and (3) the resulting rates are just and
reasonable.\22\ The Commission stated that an applicant is not required
to show that, but for the incentives, the expansion would not occur
because Congress did not require such a showing. Nevertheless, the
Commission maintained that it will require applicants to show some
nexus between the incentives being requested and the investment being
made, i.e., to demonstrate that the incentives are rationally related
to the investments being proposed.\23\
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\22\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 2, 26.
\23\ Id. P 26, 48.
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3. Rehearing Requests
17. Industrial Consumers oppose allowing applicants to request
multiple incentives, arguing that the Commission erred by determining
that section 219 does not require applicants to demonstrate a
relationship between an incentive proposal and transmission
investment.\24\ According to Industrial Consumers, the just and
reasonable requirements of section 219(d) require that incentive rates
must be based on a showing that there is a relationship between
increased rates and the attraction of new capital.\25\ They assert that
customers should not be forced to pay for incentives unless those
incentives are actually necessary to deliver additional transmission
capacity. Therefore, Industrial Consumers claim that contrary to the
Commission's conclusion, section 219 does not authorize the Commission
to depart from judicial precedent on just and reasonable incentive
rates.\26\ Further, to the extent that the Commission relies on non-
cost factors in determining just and reasonable incentive rates, the
Commission must specify the nature of the relevant non-cost factors and
offer a reasoned explanation of how the factors justify the resulting
rates.\27\ Industrial Consumers contend that the reasoned explanation
must calibrate the relationship between increased rates and the
attraction of new capital, ensure that the increase is in fact needed,
and is no more than needed to accomplish the objective.\28\
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\24\ Industrial Consumers at 3-7.
\25\ Id. at 4, citing Farmers Union Cent. Exch. v. FERC, 734
F.2d 1486, 1503 (D.C. Cir. 1984) (Farmers Union).
\26\ Id. at 5.
\27\ Id. at 6-7
\28\ Id.
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18. APPA/NRECA also argue that applicants must demonstrate a need
for the incentive rate treatments and make a showing sufficient for the
Commission to find that a particular incentive rate treatment ``is in
fact needed and no more than is needed'' under the FPA and the
Administrative Procedure Act.\29\ APPA/NRECA consider the nexus
requirement to be inadequate because it fails to require applicants to
show that a particular rate treatment is actually a lawful incentive
under sections 205 and 219 of the FPA.\30\ They assert that under the
nexus requirement, an applicant could show a sufficient rational
relationship merely by claiming that granting the incentive rate
treatment will make the investment more profitable and thus more
attractive to investors.\31\ TDU Systems repeat these points and claim
that the nexus requirement will have no effect on the granting or
denying of incentive applications unless the Commission provides
concrete examples of categories of asserted relationships between
proposed incentives and facilities that will not satisfy the nexus
requirement. They also do not consider the nexus requirement to be a
reasonable substitute for a cost-benefit analysis.\32\
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\29\ 5 U.S.C. 556 (2000).
\30\ APPA/NRECA at 22.
\31\ Id. at 23, citing Order No. 679, FERC Stats. & Regs. ]
31,222 at P 91, 117, and 133.
\32\ TDU Systems at 19-20.
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19. Likewise, TAPS argues that the nexus requirement is unduly
vague because it fails to clearly require a causal connection between
the incentive and consumer benefits. TAPS asserts that the nexus
requirement should test whether a requested incentive would reasonably
be expected to cause either a net decrease in delivered power costs
even after considering incentive-increased transmission costs, or,
where the expected net effect on delivered power costs is an increase,
reliability gains that make that increase worthwhile.\33\ To remedy the
alleged deficiencies of the nexus requirement, TAPS proposes that the
nexus requirement be revised to provide: ``That the incentive sought is
designed to result in those facilities being invested in, completed,
and placed into service.'' \34\ TAPS also recommends that the rule be
amended to explicitly retain a reasonable calculation test, so that the
Commission can determine which incentives return net consumer benefits
and will be able to verify the accuracy of its prediction that granting
incentives will spur increased investment.\35\
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\33\ TAPS at 8-9.
\34\ Id. at 11.
\35\ Id. at 16, citing City of Charlottesville v. FERC, 661 F.2d
945, 955 (D.C. Cir. 1981).
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3. Commission Determination
20. Petitioners raise two related objections to the nexus
requirement: (i) That it is too vague and therefore will be too easy to
satisfy, and (ii) because it is not sufficiently rigorous, a different
standard should be adopted. We address each in turn.
21. The required nexus test requires an applicant to demonstrate
that the
[[Page 1157]]
incentives being requested are `` tailored to the risks and challenges
faced'' by the project.\36\ By this we mean that the incentive(s)
sought must be tailored to address the demonstrable risks and
challenges faced by the applicant in undertaking the project.\37\ The
required nexus test therefore satisfies the Industrial Consumers
request that there be a relationship between the rate treatments sought
and the attraction of new capital.\38\ It also satisfies TAPS' request
that ``the incentive sought is designed to result in'' new facilities
being constructed.\39\ We disagree with TAPS and APPA/NRECA, however,
that the test is designed to be lenient or that it will necessarily be
satisfied in every case. As we indicated in the Final Rule, ``[n]ot
every incentive will be available for every new investment. Rather,
each applicant must demonstrate that there is a nexus between the
incentive sought and the investment being made.'' \40\ In evaluating
whether the applicant has satisfied the required nexus test, the
Commission will examine the total package of incentives being sought,
the inter-relationship between any incentives, and how any requested
incentives address the risks and challenges faced by the project.
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\36\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 26.
\37\ We also note that the Commission retains its discretion to
provide policy-based incentives. As the courts have said, even prior
to our new authority in section 219, the Commission's incentive rate
determinations ``involve matters of rate design * * * [and] policy
judgments [that go to] the core of [the Commission's] regulatory
responsibilities.'' Maine Public Utilities Commission v. FERC, 454
F.3d 278, 288 (D.C. Cir. 2006). See also Permian Basin Area Rate
Cases, 390 U.S. 747 (1968) (Permian).
\38\ Industrial Consumers at 4.
\39\ TAPS at 11.
\40\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 26.
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22. TDU Systems complain that we did not provide ``concrete
examples'' of showings that would either satisfy or fail the nexus
test. Although that was not the purpose of the Final Rule--the purpose
was to enunciate the criteria to be applied in individual cases--we did
provide certain illustrations. For example, we emphasized the need for
incentives for new transmission projects that can integrate new
generation and load and thereby improve reliability and reduce
congestion:
New transmission is needed to connect new generation sources and
to reduce congestion. However, because there is a competitive market
for new generation facilities, these new generation resources may be
constructed anywhere in a region that is economic with respect to
fuel sources or other siting considerations (e.g., proximity to wind
currents), not simply on a ``local'' basis within each utility's
service territory. To integrate this new generation into the
regional power grid, new regional high voltage transmission
facilities will often be necessary and, importantly, no single
utility will be ``obligated'' to build such facilities. Indeed, many
of these projects may be too large for a single load serving entity
to finance. Thus, for the Nation to be able to integrate the next
generation of resources, we must encourage investors to take the
risks associated with constructing large new transmission projects
that can integrate new generation and otherwise reduce congestion
and increase reliability.[\41\]
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\41\ Id. P 25.
We also emphasized that ``this does not mean that every new
transmission investment should receive a higher return than otherwise
would be the case. For example, routine investments to meet existing
reliability standards may not always * * *, qualify for an incentive-
based ROE.'' \42\
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\42\ Id. P 27.
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23. The Commission reaffirms that the most compelling case for
incentives are new projects that present special risks or challenges,
not routine investments made in the ordinary course of expanding the
system to provide safe and reliable transmission service. We therefore
reject the arguments of EEI and Southern Companies that such routine
investments should be treated the same, for purposes of applying the
required nexus test, as new projects that present special risks or
challenges.\43\
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\43\ See infra P 52.
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24. We also believe that the guidance provided in the Final Rule is
sufficient. The purpose of the Final Rule was to establish criteria to
be applied in individual cases, not to provide an exhaustive list of
situations where incentives will be granted or denied. The decision
whether to grant or deny incentives to a particular project is
appropriately the subject of an individual rate application (or
declaratory order) where the Commission can evaluate whether the
applicants have fully supported any incentive rate treatments being
sought.
25. We now turn to the alternative tests advocated by petitioners,
discussing the ``but for'' test in this section and the ``cost-
benefit'' test in the following section. The Final Rule rejected a
``but for'' test as inconsistent with Congressional intent in enacting
section 219.\44\ We reaffirm that finding here. In doing so, we
emphasize that both the required nexus test and the ``but for'' test
share one thing in common: Their common objective is to ensure that
incentives are not provided in circumstances where they do not
materially affect investment decisions. They differ sharply, however,
in the means by which they seek to achieve that objective. The ``but
for'' test requires an applicant to show that a facility would not be
constructed unless the incentive is granted. We reject that test
because it erects an evidentiary hurdle that could only, in very rare
cases, be satisfied. There are many impediments to investing in new
transmission, including siting concerns, financing challenges, rate
recovery concerns, etc. It is therefore unreasonable to expect or
require an applicant to show that a facility could not be constructed
``but for'' the removal of a single impediment--e.g., increased cash
flow through 100 percent construction work-in-progress (CWIP) or an
enhanced ROE. This test could rarely, if ever, be satisfied,
particularly given that incentives are ordinarily sought before
investment decisions are made and, hence, before any siting impediments
are even confronted.
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\44\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 48.
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26. The Commission therefore reaffirms its rejection of the ``but
for'' test as the appropriate test for applying section 219. It would
erect a barrier that is nearly impossible to meet and is thereby
fundamentally incompatible with Congressional intent in enacting
section 219. In enacting EPAct 2005, Congress plainly understood that
there are many impediments to new transmission investment. Congress
therefore took a variety of actions to address that problem, including
giving the Commission backstop siting authority, requiring that
entities have long-term transmission rights to support new investment
and, in section 219, providing appropriate rate incentives. We decline
to render section 219 essentially an empty letter by requiring the
demonstration of a negative--that absent an incentive rate treatment,
under no circumstance would a transmission project possibly be built.
This would be directly contrary to the intent of Congress to encourage
the construction of needed transmission.
27. We will grant rehearing, however, in one respect. The Final
Rule states that the nexus test is to be applied separately to each
incentive, rather than to the package of incentives as a whole. We
agree that this approach fails to protect consumers where an applicant
seeks incentives that both reduce the risk of the project and offer an
enhanced ROE for increased risk. Even though the applicant no longer
has to apply the nexus requirement separately to each incentive, the
applicant will be required to demonstrate that the total package of
incentives is tailored to address the
[[Page 1158]]
demonstrable risks or challenges faced by the applicant. In presenting
a package to the Commission, applicants must provide sufficient
explanation and support to allow the Commission to evaluate each
element of the package and the interrelationship of all elements of the
package. If some of the incentives would reduce the risks of the
project, that fact will be taken into account in any request for an
enhanced ROE. We are revising Sec. 35.35(d) to reflect this
clarification.
D. Cost-Benefit Analysis
28. In the Final Rule, the Commission adopted the proposal in the
NOPR not to require applicants for incentive-based rate treatments to
provide cost-benefit analyses. The Commission noted that courts have
recognized that the Commission may consider non-cost factors in its
ratemaking decisions.\45\ Therefore, the Commission stated that it may
consider non-cost factors as well as cost factors and that it will
consider the justness and reasonableness of any proposal for incentive
rate treatment in individual proceedings.
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\45\ Id. P 65, citing Permian, 390 U.S. 747, 815 (1968); Pub.
Utils. Comm'n of Cal. v. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004)
(CPUC v. FERC); Maine Pub. Utils. Comm'n. v. FERC, 454 F.3d 278,
slip op. at 19 (D.C. Cir. 2006) (Maine PUC v. FERC).
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1. Rehearing Requests
29. TDU Systems and APPA/NRECA contend that the Final Rule's
failure to require that incentive rates be justified by a cost-benefit
analysis is inconsistent with sections 205 and 219 of the FPA. They
assert that the Commission needs the information in the cost-benefit
analysis to determine whether a particular incentive rate is just and
reasonable, i.e. whether its cost is outweighed by the benefits
customers will receive.\46\ APPA/NRECA also contend that the Commission
has no basis for concluding that a particular incentive provides
consumers with a net benefit, as required under section 219(a), without
a cost-benefit analysis.\47\ TDU Systems also point out that the
Commission and affected customers must have the information necessary
to distinguish between proposed projects that would benefit customers a
great deal and proposed projects that would benefit customers minimally
if at all.\48\ Further, in considering non-cost factors, these parties
argue that the Commission cannot make a reasoned decision about the
appropriateness of non-cost factors in approving an incentive rate
without first knowing the costs and benefits of the incentive rate.\49\
They assert that intervenors also need this information to evaluate the
impact of the rate proposal on them and to understand how much the
applicant is relying on non-cost considerations. Moreover, APPA/NRECA
contend, if the applicant is not required to present any evidence that
consumers obtain net benefits from an increase in their transmission
rates, the Commission cannot strike a fair balance between the
financial interests of the regulated company and the relevant public
interests, both existing and foreseeable.\50\ Further, TDU Systems and
APPA/NRECA state that the plain language of section 219 demonstrates
that Congress' intent is to promote only efficient investment,
investment that benefits consumers. They assert that Congress'
unqualified adoption in section 219(d) of the statutory just and
reasonable standard demands a cost-benefit analysis.
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\46\ APPA/NRECA at 26; TDU Systems at 11.
\47\ APPA/NRECA at 26-27.
\48\ TDU Systems at 12.
\49\ Id. at 15; APPA/NRECA at 27.
\50\ APPA/NRECA at 29, citing Farmers Union, 734 F.2d at 1502.
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30. TDU Systems and APPA/NRECA also argue that elimination of the
cost-benefit analysis will be harmful to customers because of the two-
stage application procedure.\51\ They assert that applicants should be
required to provide the Commission and customers with all relevant
facts concerning costs and benefits at the petition for declaratory
order stage, where the applicant's right to the incentive will be
decided, because the Final Rule precludes relitigation of these issues
in the later section 205 proceeding.\52\ They state that the interested
parties must have the information needed to raise specific issues as to
whether the likely customer benefits of the project justify the likely
costs of the incentives to be awarded. They also argue that without a
rigorous cost-benefit analysis at the initial stage, the benefits that
formed the Commission's initial approval would be so amorphous that
there would be little objective data for the Commission to assess in
its periodic progress assessments. Allowing recipients of incentives to
fix the term of their incentive-rate awards in the absence of a
rigorous initial cost-benefit analysis would serve only to perpetuate
the contravention of the statutory just and reasonable standard,
according to APPA/NRECA. TDU Systems agree, stating that they can
perceive no justification for allowing incentive awardees to define the
duration of their own awards in the absence of a rigorous initial cost-
benefit analysis.
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\51\ Under the Commission's two-stage application procedure, an
applicant can petition for a declaratory order seeking an incentive-
based rate treatment for its project. After the Commission issues
the declaratory order, the applicant must seek to put the rates into
effect through a separate single-issue or comprehensive section 205
filing. See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 76-78.
\52\ TDU Systems at 12-14; APPA/NRECA at 29-30.
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31. Industrial Consumers argue that the Commission impermissibly
departed from Order No. 2000,\53\ without a reasoned explanation, by
eliminating the cost-benefit analysis. They assert that the Commission
wrongly concluded that the cost-benefit analysis is not necessary
because customers will be protected by the Commission's review of
applications pursuant sections 205, 206, and 219 of the FPA, which
require that all rates be just and reasonable and not unduly
discriminatory or preferential.\54\ They state that in Order No. 2000,
the Commission required applicants for innovative transmission rate
treatments to demonstrate how the investment in the transmission system
benefits consumers and to provide a cost-benefit analysis, including
rate impacts. Such a disconnect with Commission precedent reflects an
absence of reasoned decision making.\55\
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\53\ Order No. 2000, supra note 19.
\54\ Industrial Consumers at 7-8.
\55\ Id.
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32. Further, Industrial Consumers contend that, to successfully
balance the competing interests of providing incentives to encourage
transmission investment and its statutory responsibility of protecting
customers from excessive rates, the Commission must narrowly tailor
incentives that require a close calibration between the increased rates
and a corresponding level of benefits. Without such a close calibration
between the proposed incentive rates and the anticipated benefit, the
Commission risks thwarting the just and reasonable requirements of the
FPA. Thus, according to Industrial Consumers, applicants for incentive
treatment must be required to demonstrate that incentives will actually
yield a positive return in the form of otherwise unachievable
reliability improvements and reduced congestion costs.\56 \
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\56\ Id. at 10.
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33. SMUD contends that the nexus requirement is not sufficient to
justify eliminating the cost-benefit analysis required under Order No.
2000. It asserts that there is no connection between the lawfulness of
non-cost factors and the elimination of the cost-benefit test for
incentive rates. SMUD states that, while the Commission recognized the
non-cost-based nature of incentive ratemaking in the 1992 Policy
[[Page 1159]]
Statement, the Commission, nonetheless concluded that benefits to
consumers must be quantifiable, and SMUD asserts that nothing in
section 219 alters the requirement for a cost-benefit test.\57\
Further, SMUD contends that the nexus test results in a lower burden of
proof for applicants without explaining why a cost-benefit test is no
longer necessary. SMUD requests the Commission to clarify that the
incentives for new construction to reduce congestion will be capped so
that the delivered cost of power to the consumer is lower than what it
was before the facilities were constructed, thereby ensuring that
consumers will not pay incentive rates for congestion-reducing
construction unless the result is a lower cost of delivered power. SMUD
also requests clarification that incentives for reliability upgrades
will not reward the construction of more transmission capacity than is
reasonably necessary to meet new reliability standards, thereby
ensuring that incentive payments for reliability improvements will not
be awarded for more than what is needed to ensure reliability.
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\57\ SMUD at 2, citing Incentive Ratemaking for Interstate
Natural Gas Pipelines, Oil Pipelines, and Electric Utilities: Policy
Statement on Incentive Regulation, 61 FERC ] 61,168 at 61,590 (1992)
(1992 Policy Statement).
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34. TAPS asserts that the Commission's authority to award above-
cost incentives has always turned on whether the incentive's cost is
outweighed by the benefits customers will receive.\58\ TAPS advocates
that the Final Rule be amended to explicitly retain a reasonable
calculation test that analyzes which incentives spur increased
investment, and require the Commission to use this test to replace the
cost-benefit requirement.
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\58\ TAPS at 9, citing CPUC v. FERC, 367 F.3d at 929.
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2. Commission Determination
35. The Commission reaffirms the decision not to adopt a ``cost-
benefit'' analysis for four principal reasons.
36. First, the arguments in favor of a cost-benefit analysis start
from the premise that our traditional approach to setting transmission
rates is fully sufficient to attract new transmission investment in all
cases. This premise cannot be squared with section 219. As discussed
above, section 219 was enacted to counteract a long decline in
transmission investment. Its provisions are mandatory, not permissive,
and they proceed from the premise that the Commission must use its full
discretion under section 205 to ``promot[e] capital investment.'' It
did not, as noted above, simply codify the status quo; it required the
Commission to pass a new rule adopting incentive-based rate treatments.
37. These facts readily distinguish the Final Rule from prior
instances where the Commission required a cost-benefit analysis.\59\
None of those policies was adopted in response to a Congressional
directive to use the Commission's discretion under section 205 to
address a national problem--the decline in transmission investment that
is threatening reliability and imposing billions of dollars in
congestion costs on consumers.
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\59\ Order No. 2000 required as a condition for any innovative
transmission rate treatment that the applicant demonstrate ``a cost-
benefit analysis, including rate impacts.'' 18 CFR 35.34(e)(ii)
(2006). The Commission notes that in the 6 years since Order No.
2000 was issued, we have not received a single application seeking
any of the innovative rate treatments that were provided for in that
order. We believe that the requirement of a cost benefit analysis
was perceived as an insurmountable hurdle which inhibited the
utilities from seeking innovative rate treatments. Accordingly, in
developing incentive rate treatments under section 219, the
Commission expressly deleted the requirement for a cost-benefit
analysis.
---------------------------------------------------------------------------
38. Second, petitioners fail to recognize that applicants will be
required to show that all rates are just and reasonable under section
205. For example, any ROE will remain within the range of reasonable
returns. Further, many of the incentives described in the Final Rule
only change the timing of cost recovery (e.g., 100 percent CWIP), not
the level of cost recovery. Others reduce the risks of investment
(e.g., abandoned plant recovery), rather than changing the cost levels.
We reiterate that each of the incentives adopted by the Final Rule is
fully consistent with our responsibility to ensure that rates are just
and reasonable under section 205.
39. Third, those advocating a cost-benefit analysis fail to
recognize that the courts have held that the Commission may consider
non-cost factors in setting rates.\60\ Our authority to consider non-
cost factors applies equally in the development of incentive rate-
treatments.\61\
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\60\ See Permian, 390 U.S. 747 at 791-2; CPUC v. FERC, 367 F.3d
925 at 929.
\61\ Maine PUC v. FERC, 454 F.3d at 289 (``particularly in view
of the [Commission's] authority to consider non-cost factors in
setting rates, the State Commissions' position on calibration
demands too much'').
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40. Finally, although the Commission is rejecting a cost-benefit
analysis for the reasons stated above, applicants will nonetheless be
required, as discussed above, to demonstrate the required nexus between
the incentive being sought and the investment being made. This
requirement will ensure that incentives are granted only where the
incentives are tailored to address the demonstrable risks or challenges
faced by the applicant.
E. Rebuttable Presumptions
41. In the Final Rule, the Commission adopted a set of processes
that, if an applicant satisfies them, its project will be afforded a
rebuttable presumption that it qualifies for transmission incentives.
First, it created a rebuttable presumption that an applicant has met
the requirements of section 219 if that project 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.\62\ Second, the Commission stated that regional planning
processes can provide an efficient and comprehensive forum for
evaluating transmission investments' qualifications under section 219
by looking at a variety of options across a large geographic footprint.
For example, such a process has the ability to determine whether a
given project is needed, whether it is the better solution, and whether
it is the most cost-effective option among other alternatives.\63\ The
Commission also adopted a rebuttable presumption that an applicant has
met the requirements of section 219 if a proposed project is located in
a NIETC or has received construction approval from an appropriate state
commission, agency or state siting authority.\64\ The Commission also
stated that ``other applicants not meeting these criteria may
nonetheless demonstrate that their project is needed to maintain
reliability or reduce congestion by presenting [to the Commission] a
factual record that would support such a finding.'' \65\
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\62\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 58.
\63\ Id. The Commission noted that the value of regional
planning was expressly recognized when it proposed to amend the pro
forma Open Access Transmission Tariff of jurisdictional public
utilities to require regional planning to ensure that transmission
is planned and constructed on a nondiscriminatory basis to support
reliable and economic service to all eligible customers in the
region. See Preventing Undue Discrimination and Preference in
Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,536
(June 6, 2006), FERC Stats & Regs., Preambles ] 32,603 at P 36
(2006) (OATT Reform NOPR).
\64\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 58.
\65\ Id. P 57.
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1. Rehearing Requests
42. NARUC and TAPS contend that the Final Rule's rebuttable
presumption is not consistent with the statutory requirements of
section 219. They state that there was no showing in the Final Rule
that assessments in the regional planning processes satisfy the
[[Page 1160]]
requirements of section 219 and there is no basis to assume that the
criteria employed in regional planning processes utilize the criteria
set out in section 219.\66 \Therefore, they argue that it cannot be
reasonably presumed that every project that is subject to regional
planning will benefit customers by ensuring reliability and reducing
the cost of delivered power by reducing transmission congestion. NARUC
further contends that incentives for using regional planning processes
are inappropriate in view of the Commission's proposal in the OATT
Reform NOPR to require all jurisdictional public utilities to engage in
regional planning.\67\ Under such a mandatory requirement, all projects
will effectively qualify for the rebuttable presumption because all
projects will, presumably, be included in approved regional plans.\68 \
---------------------------------------------------------------------------
\66\ NARUC at 5-6; TAPS at 7-8.
\67\ See OATT Reform NOPR, FERC Stats & Regs., Preambles ]
32,603 at P 36.
\68\ NARUC at 6.
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43. APPA/NRECA, NARUC, TDU Systems, and TAPS argue that the
rebuttable presumption for state approvals should be deleted because
there is no legal or logical basis to presume that projects falling
into this category will ensure reliability or reduce the cost of
delivered power.\69\ They assert that the criteria applied by the state
may not resemble the criteria that the Commission is required to apply
under section 219 of the FPA. They argue that state commissions are
mainly concerned with protecting retail customers in their respective
states and state authorities apply state laws to construction-permit
applications. Accordingly, states are not focused on public utility
wholesale customers who may be in other states, or ensuring reliability
or reducing transmission congestion. Therefore, APPA/NRECA assert that
the Commission cannot delegate its responsibilities under section 219
to state authorities that may of necessity have a very different
mission.\70\
---------------------------------------------------------------------------
\69\ Id. at 7; TAPS at 6; APPA/NRECA at 37-39; TDU Systems at
25-27.
\70\ APPA/NRECA at 38.
---------------------------------------------------------------------------
44. NARUC also claims that projects receiving a designation as
projects in NIETC should not receive a rebuttable presumption because
such a designation, alone, cannot assure that the statutory
prerequisites of section 219 have been satisfied when the criteria for
NIETC designation do not mirror those set out for incentives under the
statute.\71\
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\71\ NARUC at 7.
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45. Additionally, NARUC, APPA/NRECA, and TDU Systems claim that the
scope of the rebuttable presumption is ambiguous and needs to be
clarified. They state that it is not clear to which part of the three-
part showing that the rebuttable presumption applies to.\72\ They state
that the rebuttable presumption should only apply to the first part
(ensure reliability or reduce the cost of delivered power by reducing
transmission congestion) of the three-part showing because the only way
an applicant can appropriately satisfy the statutory requirements of
FPA section 219 is to demonstrate on the record that the project either
ensures reliability or reduces the cost of delivered power and that the
rates satisfy sections 205 and 206 of the FPA. Therefore, the applicant
must still demonstrate with factual evidence that there is a nexus
between the incentive sought and the investment being made and that the
resulting rates are just and reasonable.\73\ APPA/NRECA also request
the Commission to clarify that this interpretation applies to both
section 205 filings and petitions for declaratory order.\74\ TAPS
contends that the rebuttable presumptions conflict with the
Commission's intended limitations on the receipt of incentives, such as
routine investments, which may be included in a regional plan and
required to receive state siting approval prior to construction, but
may not always qualify for an incentive-based ROE.\75\
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\72\ Under section 35.35(d) of the regulatory text, an applicant
for incentive rates is required to make a three-part showing that:
(1) 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; (2) there is a nexus between the incentive sought and the
investment being made; and (3) resulting rates are just and
reasonable. 18 CFR 35.35(d) (2006).
\73\ APPA/NRECA at 35-36; NARUC at 7-8; TDU Systems at 24-25.
\74\ APPA/NRECA at 36.
\75\ TAPS at 8, citing Order No. 679, FERC Stats. & Regs. ]
31,222 at P 94.
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2. Commission Determination
46. We will grant rehearing and clarification in part. The
Commission created the rebuttable presumption for the purpose of
avoiding duplication in determining whether a project maintains
reliability or reduces congestion. We do not wish to repeat the work of
state siting authorities, regional planning processes, or the DOE in
evaluating these issues. However, we agree with NARUC that if such
processes do not in fact include such a determination, a rebuttable
presumption would not be appropriate. Accordingly, we grant rehearing
and are modifying Sec. 35.35 in three ways.
47. First, we agree with NARUC that the NIETC process will not
necessarily determine that every transmission project within a
designated corridor will meet the section 219(a) requirements, nor is
DOE required to make such a determination. However, we do not believe
it is necessary to retain this particular rebuttable presumption in our
regulations because any project which is proposed in a NIETC will of
necessity have to go through a state or federal siting process. If an
applicant's proposed project is within a NIETC, we expect that it will
be sited in most instances by the appropriate state siting authority
and the applicant will be able to rely on the state siting rebuttable
presumption for meeting the requirements of section 219(a). In those
cases where projects within a NIETC are sited by this Commission
pursuant to our new authority in section 216, an applicant may rely on
our findings in our siting process for meeting the requirements of
section 219(a).\76\ Thus, applicants with projects in a NIETC have an
opportunity to rely upon the appropriate siting processes to meet the
requirement that a project ensure reliability or reduce the cost of
delivered power by reducing transmission congestion, and we need not
include the NIETC process as a rebuttable presumption.\77 \
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\76\ As stated in section 216, the Commission may exercise its
new siting authority if inter alia it finds that the construction or
modification of the facilities ``significantly reduce transmission
congestion in interstate commerce and protects or benefits
consumers.'' Since the Commission is required to find that a project
reduces transmission congestion before it can authorize the siting
of a transmission facility within a NIETC, such facilities
necessarily satisfy the requirement of section 219(a) and these
regulations.
\77\ While DOE is not required to determine whether all projects
within a NIETC meet the pre-requisites of section 219, we anticipate
that DOE is likely to consider whether transmission projects within
these corridors ensure reliability or reduce the cost of delivered
power by reducing transmission congestion. Thus, an applicant that
does not rely upon a rebuttable presumption for meeting the pre-
requisites of section 219 may nonetheless use the findings made by
the DOE. Accordingly, the Commission will give due weight to the
DOE's determinations concerning the ability of transmission projects
within a NIETC to ensure reliability or reduce the cost of delivered
power by reducing transmission congestion.
---------------------------------------------------------------------------
48. We are amending our regulations to provide that an applicant
that obtains Commission authorization under section 216 to site
electric transmission facilities in interstate commerce shall be deemed
to satisfy the requirements of section 219(a).\78\
---------------------------------------------------------------------------
\78\ Section 216(b)(4). See also Regulations for Filing
Applications for Permits to Site Interstate Electric Transmission
Facilities, Order No. 689, 71 FR 69,440 at P 41 (Dec. 1, 2006)
(``The Commission will review the proposed project and determine if
it reduces the transmission congestion identified in DOE's study and
if it will protect or benefit consumers. It will investigate and
determine the impact the proposed facility will have on the existing
transmission grid and the reliability of the system'').
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[[Page 1161]]
49. Second, we will modify our regulations to require each
applicant seeking to invoke the rebuttable presumption to explain in
its filing how the applicable process (regional planning or state
approval) in fact considered whether the project ensures reliability or
reduce congestion. We continue to believe that, these approval
processes will, in all likelihood, examine whether the project
maintains reliability or reduces congestion. But in instances where
this is not the case the applicant will bear the full burden of
demonstrating such facts.
50. Third, we also clarify that the rebuttable presumption applies
only to the requirement that an applicant demonstrate, that a project
is needed to ensure reliability or to reduce congestion. It does not
apply to any other requirement in 18 CFR 35.35, such as the
requirement, that the applicant demonstrate the required nexus between
the incentive sought and the investment being made \79\ and that the
resulting rates are just and reasonable in either the petition for
declaratory order or section 205 filing. We will modify our regulations
accordingly.
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\79\ We note that the Final Rule's statement regarding routine
investment cited by TAPS, applies to the nexus demonstration, and
therefore there is no conflict between the rebuttable presumption
and that statement.
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F. ROE Sufficient To Attract Investment
51. In the Final Rule, the Commission adopted the NOPR's proposal
to allow, when justified, an incentive-based ROE to all public
utilities (i.e., traditional public utilities and Transcos) for new
investments in transmission facilities that benefit consumers by
ensuring reliability or reducing the cost of delivered power by
reducing congestion.\80\ By including this provision in the Final Rule,
the Commission stated that it satisfied the requirement of section 219
to provide an ROE that attracts new investment in transmission
facilities (including related transmission technologies). The
Commission stated that it will provide ROEs at the upper end of the
zone of reasonableness for transmission investments that meet the
requirements of section 219. Further, the Commission clarified that it
will continue to use the DCF analysis for ROE determinations.\81\ The
Commission also noted that not every investment that increases
reliability or reduces congestion will qualify for an incentive-based
ROE. For example, routine investments may continue to be assessed under
traditional ROE determinations because there is an obligation to
construct them and high assurance of recovery of the related costs.\82\
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\80\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 91.
\81\ This analysis, undertaken in individual rate applications,
assesses representative proxy companies and the impact of other
factors, including risk, on the zone of reasonableness for ROE. Id.
P 92.
\82\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 94.
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1. Rehearing Requests
52. EEI and Southern Companies take exception to the statement in
the Final Rule that ``routine investments made to comply with existing
reliability standards may not always qualify for an incentive-based
ROE.'' \83\ They argue that the statement discriminates against
projects or upgrades that may be proposed to address reliability
concerns, and therefore the statement should be deleted.\84\ Southern
Companies emphasize that the statutory requirement under 219 makes no
distinction between routine or non-routine status; therefore,
regardless of status, an investment that promotes reliability should be
entitled to incentive rate treatment. In that respect, Southern
Companies request the Commission to confirm that all reliability-
related investments qualify for incentive-based ROEs.\85\ Furthermore,
Southern Companies request the Commission to clarify that a single
incentive-based ROE should apply to all, not just new, transmission
investment.\86\
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\83\ Id.
\84\ EEI at 11; Southern Companies at 3.
\85\ Southern Companies at 4.
\86\ 86 Southern Companies argue that section 219(b)(2) should
be read to require the Commission to re-examine its ratemaking
methods and revise it current ROE policies for all transmission
investment, and that the base ROE must be sufficient to attract new
investment. It contends that Congress did not state that the
Commission shall provide a return on equity for new investment in
transmission. Instead, section 219(b)(2) states that the Commission
shall ``provide a return on equity that attracts new investment in
transmission.'' See Id. at 5 (emphasis provided by commenter).
---------------------------------------------------------------------------
53. TDU Systems contend that the Commission should reconsider its
commitment to grant incentive applicants an ROE at the upper end of the
zone of reasonableness. Specifically, TDU Systems claim that the
Commission may have difficulty handling all the rate filings that seek
extremely high ROEs because of the two-stage process. They contend that
the Commission is placing too much reliance on its ability to protect
consumer interests in the second stage, section 205 review, and
recommends that the Commission relieve some of the pressures by giving
incentive applicants a more specific message that the incentives have
limits.\87\ APPA/NRECA also assert that the Commission has not
explained why such an increase in allowed ROEs is, or could be, either
necessary to attract capital or otherwise just and reasonable and that
the rule does not balance investor and consumer interests in setting
incentive ROEs.\88\ Accordingly, these parties assert that the
Commission should permit incentives only if the package as a whole
results in a just and reasonable rate. In so doing, they argue, the
Commission should disavow any intent to allow ROEs near the top of the
zone of reasonableness and ensure that companies in the proxy group
with ROEs at the top of the zone of reasonableness do not become the
basis for determining the zone, particularly to the extent incentive
ROEs become the base case in future DCF analyses.
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\87\ TDU Systems at 27-29.
\88\ APPA/NRECA at 9, 47.
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54. Similarly, TAPS argues that the Commission must be prepared to
apply a much stricter scrutiny to the composition of the proxy group
that determines the range of the zone of reasonableness to the extent
the Commission continues to declare in favor of rates set at the top of
a range that has not yet been established.\89\ Also, TAPS recommends
that the Commission modify its methodology for proxy results by first
averaging the two results per proxy company so that there is one,
average result per proxy company, as it does in gas cases,\90\ thereby
providing a more defensible basis for just and reasonable returns. TAPS
requests the Commission to clarify that it will ensure that the top of
the range does not become a self-
[[Page 1162]]
escalating spiral with the highest proxy result reflecting an investor
expectation that the proxy itself will garner above-cost incentive
profits.\91\
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\89\ TAPS explains that many transmission owners will request
rates at the high end of the zone of reasonableness and that the
main restraint on transmission rates will be the ceiling that is set
by the placement of the top of the zone of reasonableness. The zone
has been defined by taking a sample group that includes a large
number of proxy companies and calculating two data points per proxy.
Each pair of points represents the extreme values for each company.
The zone of reasonableness is often characterized as reaching up to
the higher data point for the most extreme company in the proxy set.
Thus, when the top of the range sets the return, it becomes critical
to ensure that every company included in the proxy group very
closely resembles the utility whose return is being capped, i.e.,
its capital structure, business risk, financial risk, and associated
capital costs. See TAPS at 18-22.
\90\ Id. at 21, citing High Island Offshore System, L.L.C., 110
FERC ] 61,043, at P 148 (2005).
\91\ Id. at 22.
---------------------------------------------------------------------------
55. Southern Companies consider the Commission's continued reliance
on DCF analysis in the Final Rule to be contrary to Congressional
intent and policy.\92\
---------------------------------------------------------------------------
\92\ According to Southern Companies, section 219's requirement
that the Commission provide ROEs that are sufficient to attract new
transmission investment is evidence of Congress' conclusion that the
Commission's current ROE methodology is not producing adequate
results. Therefore, the Commission should construe section 219(b)(2)
as a mandate from Congress to re-examine its traditional ratemaking
policies. Southern Companies at 5-6.
---------------------------------------------------------------------------
Accordingly, Southern Companies request the Commission to clarify
that it will allow the use of additional ROE estimation methodologies
\93\ because these methodologies will better ensure that an entity is
ensured a reasonable rate of return. Southern Companies assert that
failure to consider the results of more than one methodology, although
there are other sound methods, constitutes arbitrary and capricious
decision making.\94\ Furthermore, Southern Companies consider the Final
Rule's refusal to recognize the flaws in the current DCF analysis to be
arbitrary and capricious and its finding that the DCF analysis yields
just and reasonable results to be in error, particularly in light of
the fact that the DCF analysis drives a utility's stock price to its
book value while market values exceed book values by approximately 2.47
to 1 as of December 31, 2005 and the constant-growth DCF model often
produces divergent and meaningless results.\95\
---------------------------------------------------------------------------
\93\ Such methodologies include the risk premium approach, the
capital asset pricing model and the comparable earnings approach.
Id. at 7.
\94\ They state that using multiple methodologies recognizes
that no single approach can accurately predict an appropriate ROE
level so as to satisfy the constitutional and statutory
requirements. Id. at 8.
\95\ Id. at 11.
---------------------------------------------------------------------------
56. Southern Companies also argue that ROE adders should be
provided to all new transmission construction. They assert that section
219 directs the Commission to promote investment of all facilities and
therefore the Commission's determination in the Final Rule that it will
not create specific ROE adders is contrary to EPAct 2005 and requiring
applicants to go through a rate case prior to receiving any incentives
would unnecessarily impede Congress' stated goal of encouraging new
transmission investment.\96\
---------------------------------------------------------------------------
\96\ Id. at 18.
---------------------------------------------------------------------------
57. The California Commission claims that the Commission did not
engage in reasoned decision making in the Final Rule because it failed
to consider risk assessment and did not address its arguments about the
relative low risk of transmission investment.\97\ It argues that the
Commission failed to explain why transmission entities should be
eligible for a higher ROE given the low risk associated with
transmission investments. The California Commission states that
transmission businesses have a low financial risk because they generate
a steady revenue stream as a regulated monopoly. Also, among the three
functions of an integrated utility's electricity business, i.e.
generation, distribution, and transmission, the transmission business
carries the lowest risk.\98\ Further, the California Commission argues
that the Commission did not consider the effect the multiple incentives
created by the Final Rule will have on lowering the risk, such as 100
percent recovery of CWIP before a transmission project is used and
useful. Accordingly, it contends that above-average ROEs for
transmission are not needed to effect new transmission facilities.\99\
---------------------------------------------------------------------------
\97\ California Commission at 7-10.
\98\ Id. at 8.
\99\ The California Commission states that even without the high
ROE incentive, California IOUs have planned and constructed numerous
transmission facilities in the last 10 years. Id. at 9.
---------------------------------------------------------------------------
58. New England Commissions argue that the Commission arbitrarily,
capriciously, and without a reasonable factual foundation, determined
that ROE incentives encourage investment and make transmission projects
attractive.\100\ They state that the New England ROE proceeding in
Bangor Hydro-Electric \101\ demonstrated that an enhanced ROE will not
change transmission owners' performance in any material respect, but
will merely give them an unjust and unreasonable windfall. Accordingly,
New England Commissions assert that the Commission's finding that
transmission incentives are necessary is not supported by the record in
this rulemaking or in the Bangor Hydro-Electric proceeding.\102\
According to the New England Commissions, it is contrary to the
directive in section 219(d) that rates be just and reasonable to
dispense with any showing of need before awarding ROE incentives.\103\
New England Commissions requests the Commission to clarify that it will
judge the justness and reasonableness of ROE adders in New England
based on the record in Bangor Hydro-Electric proceeding and specify in
the rule that only a case-by-case evaluation can determine whether an
ROE incentive will produce justifiable benefits.
---------------------------------------------------------------------------
\100\ New England Commissions at 5.
\101\ Bangor Hydro-Electric Co., 106 FERC ] 61,280 (2004).
\102\ New England Commissions at 6-10.
\103\ Id. at 12.
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2. Commission Determination
59. We will grant rehearing and clarification in part on certain
issues and deny rehearing on all other issues.
60. We reject the argument of investor-owned utilities that ROE
incentives be applied without regard to the nature of the facility
being constructed or the risks associated with it. Specifically, the
Commission reaffirms that the most compelling case for incentive ROEs
are new projects that present special risks or challenges, not routine
investments made in the ordinary course. We therefore reject the
arguments of EEI and Southern Companies that such routine investments
should be treated the same, for purposes of applying the nexus test, as
new projects that present special risks or challenges. Although we will
consider applications for ROE incentives for all projects, we reiterate
that not all projects will be able to meet the nexus requirement. EEI
and Southern Companies have provided no compelling reason why a routine
investment made in the ordinary course should, as a general matter,
receive an incentive ROE.
61. We also reject the argument that incentive ROEs should apply to
existing transmission rate base that has already been built. The
purpose of section 219 is to attract investment in transmission.
Southern Companies have not provided any evidence that higher ROEs for
transmission rate base that has already been built are necessary to
ensure reliability or to reduce congestion; nor have they shown why
such ROEs are necessary to attract new investment in transmission.
62. We also reject the contentions of certain customer groups that
incentive ROEs will ``destabilize'' the DCF methodology. First, as
indicated above, all ROEs approved pursuant to section 219 will be
within the range of reasonableness, as determined consistent with our
precedents. Second, any incentive ROEs granted under 219 should have a
minimal effect, if any, on the overall range of reasonableness derived
from the appropriate proxy group. The DCF methodology uses proxy groups
of entire companies, not individual transmission projects. In other
words, the ``cash flows'' being measured in the DCF method are the cash
flows of entire companies. These cash flows should not be significantly
affected by an incentive return for any particular transmission project
for one company within the proxy group. Moreover, to the extent there
is any
[[Page 1163]]
small effect on the overall range of reasonableness, it will
appropriately reflect the substantial risks associated with
constructing new transmission, as discussed above.\104\
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\104\ The Commission retains the discretion to adjust ROEs if we
find that the results of a DCF analysis do not accurately reflect
the risk of the applicant and its ability to attract capital.
---------------------------------------------------------------------------
63. We also reject requests to cease our utilization of the DCF
method. Inasmuch as the DCF method yields just and reasonable rates, as
the Commission has recognized in numerous proceedings, we see no basis
to require other methods for the evaluation of incentive applications.
As we stated in the Final Rule, the Commission will consider on a case-
by-case basis whether the application of the traditional DCF analysis
should be modified.\105\
---------------------------------------------------------------------------
\105\ We agree with TAPS that averaging each company's low and
high DCF return would result in a single average DCF result for each
electric company, making it like the single DCF return for gas and
oil pipelines, from which a median return on equity for the group
can be calculated. While this is an acceptable method, we will not
require use of that method in the Commission's DCF analysis because
that issue is beyond the scope of this proceeding and is more
appropriately addressed in the individual application proceedings.
---------------------------------------------------------------------------
64. We also do not consider the process for approving incentive
ROEs, i.e., setting a zone of reasonableness and a DCF analysis
requirement, to be an unnecessary impediment to encouraging
transmission investment. Generic adders, as recommended by Southern
Companies, would still require the Commission to make a determination
that the proposed ROEs are just and reasonable, and its findings would
have to be based on reasoned decision-making. Therefore, the Commission
necessarily would be required to establish a zone of reasonableness and
a justification for the approved ROEs.
65. Responding to the California Commission, the Final Rule
explained the basis for its decision to provide an incentive ROE, based
on the need to attract investment in the context of long-term industry
underinvestment and the need to re-evaluate the balance of investor and
ratepayer interests, and therefore has provided the reasons for its
decisions. The Commission is not, in this rule, setting the incentive
ROE, but rather leaves that determination to future proceedings that
will authorize a unique ROE appropriate to the facts and circumstances
of each applicant. It is in those proceedings that the California
Commission can raise its concerns regarding comparative returns within
the energy industry and the specific characteristics of California
utilities. However, we agree with the California Commission that
utilities should consider the effect that certain incentives (e.g. CWIP
in rate base, recovery of abandoned plant) may have on risk and that
return on equity in the upper end of the zone of reasonableness may not
be appropriate when combined with incentive rate treatments that lower
overall risk.
66. We do not address the issues raised by New England Commission
with respect to the Bangor Hydro-Electric proceeding because they have
been addressed in a recent Commission order and are now pending on
rehearing.\106\
---------------------------------------------------------------------------
\106\ Bangor Hydro-Electric Co., Opinion No. 489, 117 FERC ]
61,129 (2006).
---------------------------------------------------------------------------
67. We will, however, grant clarification in part. Several
petitioners express the fear that the Commission will routinely grant
ROEs at the top end of the zone of reasonableness. Although the
Commission has broad discretion to establish returns on equity anywhere
within the zone of reasonableness, we must be careful in the manner in
which we exercise this discretion. The Commission clarifies that we do
not intend to grant incentive returns ``routinely'' or that, when
granted, they will always be at the ``top'' of the zone of
reasonableness. Rather, each applicant will, first, be required to
justify a higher ROE under the revised nexus test and, second, to
justify where in the zone of reasonableness that return should lie. In
some instances, where the risks or challenges faced by a new investment
are substantial, we may grant an ROE at the top end of the zone of
reasonableness. However, we have no expectation of doing so in all
cases or even routinely.
68. We also provide clarification on the timing of an ROE
determination. In most instances, an ROE determination occurs in a
hearing that considers the justness and reasonableness of the costs of
the investment for purposes of setting rates under section 205. In that
hearing, the overall range of reasonableness would be established, as
well as a determination of where within that range the ROE should be
set. If the Commission granted a request for an incentive ROE at the
upper end of that range in a petition for declaratory order, the
hearing would establish where in the upper end the ROE would fall--
whether at the top end or at a different point in the upper end of the
range. The Commission would then review any determination by an
administrative law judge on that issue.
69. We recognize, however, that our hearing procedures for
determining ROE can create uncertainty for investors. Under traditional
ratemaking processes, the rates for a particular project, including the
ROE for that project, are determined only after an investment decision
is made and the facility is constructed. This may provide a
disincentive to new investments that are sensitive to our ROE
determinations. Although our processes are designed to provide a just
and reasonable return, we recognize that there can be significant
uncertainty as to the ultimate return because of the uncertainties
associated with administrative determinations (e.g., selection of the
proxy group, changes in growth rates, etc.) This can itself constitute
a substantial disincentive to new investment.
70. Recognizing this, we will clarify the approach adopted in the
Final Rule. We will continue to allow applicants to request, in a
petition for declaratory order, an ROE that is at the upper end of the
zone of reasonableness and, in such instances, the ultimate ROE will be
determined in the hearing process. However, if an applicant desires up-
front certainty of the ROE it will receive, we clarify that we also
will consider requests for declaratory orders that set the ROE for a
particular project, and that include the appropriate support for the
ROE, including, for example, a DCF analysis. An applicant seeking to
use this process will have to meet the required nexus requirement, such
as by showing that an up-front ROE determination is important for its
investment decision. An applicant seeking such an up-front ROE
determination also may request an ROE at the upper end of the zone of
reasonableness; however, the fact that an up-front ROE determination is
itself an incentive that tends to reduce risk will be taken into
account in considering any such request.
G. Incentives Available to Transcos
71. In the Final Rule, the Commission approved incentive-based rate
treatments applicable to Transcos to encourage Transco formation and
attract investment.\107\ Specifically, the Commission approved an ROE
that encourages Transco formation and is sufficient to attract
investment and an adjustment to book value of transmission assets being
sold to a Transco to remove the disincentive associated with the impact
of accelerated depreciation on federal
[[Page 1164]]
capital gains tax liabilities.\108\ The Commission noted that its
decision to approve such incentives for Transcos is based on the
``proven and encouraging track record of Transco investment'' in
transmission facilities.\109\
---------------------------------------------------------------------------
\107\ Section 35.35(b)(1) defines Transcos as stand-alone
transmission companies approved by the Commission that sell
transmission services at wholesale and/or on an unbundled retail
basis, regardless of whether they are affiliated with another public
utility.
\108\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 222-224.
The incentive ROE does not preclude a Transco from applying for
other incentives, including hypothetical capital structure,
allowance for deferred income taxes (ADIT), acquisition premiums,
formula rates or deferred cost recovery. Id. P 221.
\109\ See id. P 221-23.
---------------------------------------------------------------------------
1. Rehearing Requests
72. EEI argues that applicants seeking transmission incentives
should be treated equally, without regard to their form of business. It
argues that the incentives applicable to stand-alone transmission
companies should be expanded to apply to all transmitting
utilities.\110\ EEI also urges the Commission to recognize that all
forms of transmission business models can effectively provide
transmission facilities and to reiterate that it will evaluate each
applicant's proposed incentives, in particular the upper range of
reasonable ROEs, without regard to the applicant's form of business and
without bias as between forms of business.\111 \
---------------------------------------------------------------------------
\110\ EEI at 5, 7-9.
\111\ Id. at 5. EEI claims that section 219(b) provides that the
rule shall promote transmission investment ``regardless of the
ownership of facilities'' and the Commission noted in the Final Rule
that it will not limit incentives based on corporate structure or
ownership. Id. at 7, citing Order No. 679, FERC Stats. & Regs. ]
31,222 at P 4, 225.
---------------------------------------------------------------------------
73. Southern Companies contend that additional incentives for
Transcos are not justified on grounds that the Transcos have a good
record of transmission investment.\112\ They state that vertically-
integrated utilities like Southern Companies have consistently invested
significantly in transmission maintenance and expansion. Southern
Companies also claim that special ROE incentives solely for Transcos
would be discriminatory by favoring one corporate structure over
another to the extent both business structures have similar
transmission investment records \113\ and the requirements of section
219 to promote investment regardless of the ownership of the
facilities.
---------------------------------------------------------------------------
\112\ Southern Companies at 16-17.
\113\ Id. at 17, citing Order No. 679, FERC Stats. & Regs. ]
31,222 at P 225.
---------------------------------------------------------------------------
74. APPA/NRECA assert that because the Commission's definition of
Transcos includes affiliated Transcos under the control of one or more
parent public utilities, granting incentive rate treatment greater than
that afforded to public utilities would constitute a financial
windfall.\114\ They argue that such affiliated Transcos should not be
eligible for special incentive rate treatment because such a payment
would neither induce new construction nor provide any new benefit to
the customer paying the incentive rate.\115\
---------------------------------------------------------------------------
\114\ APPA/NRECA at 31, 34-35. In the Final Rule, the Commission
stated that the definition of Transco does not exclude affiliated
Transcos with active ownership by market participants, or stand-
alone transmission companies that own transmission and distribution
facilities. The Commission said that it would consider the
eligibility of such arrangements based on a showing of how the
specific characteristics of a proposed Transco affect its ability
and propensity to increase transmission investment and lead to
increased transmission investment similar to Transcos the Commission
already approved. See Order No. 679, FERC Stats. & Regs. ] 31,222 at
P 202.
\115\ APPA/NRECA at 31.
---------------------------------------------------------------------------
75. Furthermore, TDU Systems oppose passive ownership interests in
Transcos and contend that, if authorized, passive ownership interests
should only be authorized upon a showing that the option of investment
in the Transco is open to all load-serving entities (LSEs) in the
region up to their load ratio shares.\116\ They also argue that the
Commission must rigorously scrutinize and monitor relationships among
the passive owners to deter the potential for abuse. TDU Systems also
contend that the Commission should clarify that Transcos may only
receive incentive rates if there are no interests within the Transco
competing with transmission for capital. They recommend that the
Commission condition the granting of incentives by imposing limits on
business investments in other industries to avoid the dilution of
capital funding from competing sources within the company.\117\ They
also claim that incentives for new investment in transmission
infrastructure should not be necessary because, as the Commission noted
in the Final Rule, such incentives are inherent in the corporate
business model to encourage investment.\118\ Therefore, encouraging
additional incentives provides no incremental benefit to
consumers.\119\
---------------------------------------------------------------------------
\116\ TDU Systems at 39.
\117\ Id. at 40.
\118\ See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 204.
\119\ TDU Systems at 41.
---------------------------------------------------------------------------
2. Commission Determination
76. We affirm the finding in the Final Rule that the Commission
will not limit an applicant's ability to seek incentive-based rate
treatments based on corporate structure or ownership.\120\ The
Commission will evaluate these applications to determine if incentive
treatment is justified based on their demonstrations that the projects
meet the requirements of section 219 and this rule. Certain types of
incentives, such as the ADIT incentive may be more appropriate where
transmission is being spun off or otherwise transferred to a new
corporate entity, such as a Transco. But we see no basis for the claim
that the Transco incentives are unduly discriminatory or contrary to
the goals of section 219.
---------------------------------------------------------------------------
\120\ See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 4.
---------------------------------------------------------------------------
77. The Final Rule described at great length the very significant
transmission investment that has been undertaken by Transcos, to
date.\121\ There is no reason to repeat those examples again here, but
we disagree with comments that suggest that Transcos do not have a good
record of transmission investment. Furthermore, their singular focus on
transmission investment by transmission-only companies, the elimination
of competition for capital between generation and transmission
investments, and the access to capital markets have all been cited in
support of the value of the Transco business model for getting new
transmission built. For all of these reasons, the Commission adopted
incentive-based rate treatments applicable to Transcos that would both
encourage Transco formation and attract investment.
---------------------------------------------------------------------------
\121\ Id. P 222-23.
---------------------------------------------------------------------------
78. As we stated in the Final Rule, the Commission will consider
concerns regarding affiliated Transcos in specific applications for
incentive treatment.\122\ We believe the Final Rule fulfills the
requirements of section 219 by determining eligibility for Transco
status and incentive-based rate treatment based on a showing of how the
specific characteristics of a proposed Transco affect its ability and
propensity to increase transmission investment in individual case
proceedings. Therefore, we do not consider this proceeding to be the
appropriate forum for adopting preconditions related to other issues,
such as affiliation or passive ownership. Inasmuch as Transcos are
subject to the Commission's market behavior rules, their activities
will be monitored for any potential market abuse. Therefore, we affirm
the availability of ROE incentives to Transcos. As stated in the Final
Rule, we expect that the incentive ROE will be used for additional
capital spending, and thereby provide consumer benefits, as
demonstrated by the negative cash flow profiles of Transcos and their
future capital spending plans.
---------------------------------------------------------------------------
\122\ See id. P 202.
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[[Page 1165]]
H. Transmission Organization Incentive
79. In the Final Rule, the Commission stated that it will
authorize, when justified, an incentive-based rate treatment for public
utilities that join and/or continue to be a member of an ISO, RTO, or
other Commission-approved Transmission Organization.\123\ Applicants
for the incentive-based rate treatment must make a filing with the
Commission under section 205 of the FPA. For purposes of section
35.35(e), an incentive-based rate treatment means an ROE that is higher
than the ROE the Commission might otherwise allow if the public utility
were not a member of a Commission-approved Transmission Organization.
The Commission stated that it will not create a generic adder for such
membership, but instead will consider appropriate ROE incentives on a
case-by-case basis. The Commission also stated that transmitting
utilities or electric utilities that join a Transmission Organization
would be eligible to apply to recover prudently-incurred costs
associated with joining the Transmission Organization, either through
rates charged by transmitting utilities or electric utilities or
through transmission rates charged by the Transmission Organization
that provides services to such utilities.\124\ Furthermore, the
Commission stated that based on its interpretation of section 219,
eligibility for this incentive flows to an entity that ``joins'' a
Transmission Organization and is not tied to when the entity joined.
Therefore, the Commission clarified that entities that have already
joined, and that remain members of, an RTO, ISO, or other Commission-
approved Transmission Organization, are eligible to receive this
incentive.\125\ However, as the Commission noted, any public utility
receiving an incentive ROE for joining a Transmission Organization but
withdraws from such organization is no longer eligible for the ROE
incentive.
---------------------------------------------------------------------------
\123\ Id. P 326. Transmission Organization is defined as ``a
Regional Transmission Organization, Independent System Operator,
independent transmission provider, or other transmission
organization finally approved by the Commission for the operation of
transmission facilities.'' Id. P 328.
\124\ Id. P 329.
\125\ Id. P 331.
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1. Rehearing Requests
80. Petitioners contend that public utilities should not be
eligible for the Transmission Organization incentive if the public
utilities are already members because the payment would neither induce
new construction nor provide any new benefit to the customer paying the
incentive rate.\126\ They argue that the Final Rule's determination
that incentives may go to entities that are already members of a
Transmission Organization is contrary to court and Commission precedent
interpreting incentive rates as forward-looking inducements, not a
reward for past behavior.\127\ The California Commission claims that
the Final Rule's interpretation of section 219 exceeds the Commission's
authority by creating an incentive that is broader than specified in
the FPA.\128\ Furthermore, TDU Systems assert that many public
utilities have already joined ISO or RTOs without ROE incentives and
have benefited from such membership. Those public utilities that have
not joined have chosen not to do so because their business interests
would not be advanced by a reduction in transmission barriers and
constraints. Therefore, they argue that ``recalcitrant utilities''
should not be awarded windfall profits for holding out on participating
in Transmission Organizations because such action would only amount to
rewarding the exercise of market power.\129\
---------------------------------------------------------------------------
\126\ TDU Systems at 43; APPA/NRECA at 31-32, citing Southern
California Edison Company, 114 FERC ] 61,018, at P 16 (2005) (``The
rationale for this incentive is to encourage transmission owners to
turn over the operational control of their transmission facilities
to a regional transmission organization; therefore, it does not
apply to transmission owners who have already done so, as they need
no inducement to take such action'') (Southern California Edison).
\127\ E.g., APPA/NRECA at 32; SMUD at 3-7; TDU Systems at 43.
The California Commission argues that the courts have not permitted
ROE adders for past conduct. California Commission at 18-19, citing
Maine PUC v. FERC, 454 F.3d 278 (2006) and Allegheny Power Systems
Operating Co., 111 FERC ] 61,308 (2005).
\128\ California Commission at 14-15.
\129\ TDU Systems at 42.
---------------------------------------------------------------------------
81. Furthermore, the California Commission states that an incentive
for utilities that have already joined a Transmission Organization and
are planning to build transmission facilities provides no balancing of
the consumer interests and represents an unjust windfall.\130\ By
continuing its membership in an ISO/RTO, a transmission company will
not incur any additional risks and will still remain a monopoly. The
California Commission and TDU Systems argue that the Commission did not
provide any evidence that current RTO/ISO members may leave a
Transmission Organization without the incentive of higher ROEs and
therefore such a conclusion constitutes unreasonable, unlawful decision
making.\131\ APPA/NRECA assert that if a member leaves the Transmission
Organization, the Commission can simply deny that utility a rate
incentive.\132\ Further, SMUD notes that there is no assurance that
members will be permitted to leave since such a decision is subject to
Commission review, and expresses concern that extending incentives to
existing members of a Transmission Organization for not leaving may
discourage parties legitimately dissatisfied with the Transmission
Organization's performance and thereby make these organizations less
accountable.\133\ Finally, APPA/NRECA argue that the Commission's
statement that it would be unduly discriminatory not to award all
members of a Transmission Organization an incentive ROE has no basis
because nothing in the FPA forbids different rates if these
arrangements are necessary to carry out the provisions of the FPA and
to serve the regulatory purposes contemplated by Congress.\134\
---------------------------------------------------------------------------
\130\ California Commission at 16.
\131\ Id. P 17-18; TDU Systems at 43.
\132\ APPA/NRECA assert that the Commission rejected such a
remedy without a reasoned explanation in the Final Rule. APPA/NRECA
at 32.
\133\ SMUD at 3-7.
\134\ APPA/NRECA at 33.
---------------------------------------------------------------------------
82. TDU Systems request clarification that the Commission will not
consider single company entities as Transmission Organizations. They
state that to ensure new transmission investment serves regional
markets, a ``collaborative [and] open regional planning process'' is
necessary. Therefore, TDU Systems claim that only entities that provide
for, or participate in, regional planning that spans a number of public
utility transmission systems should be eligible for incentives.\135\
---------------------------------------------------------------------------
\135\ TDU Systems at 41-42.
---------------------------------------------------------------------------
83. TDU Systems recommend a reduction, i.e. negative 50 basis point
penalty, in the authorized ROE for public utilities that withdraw from
Transmission Organizations within the first five to ten years of
participation to recognize the costs paid by consumers in anticipation
of long-term savings. TDU Systems also argue that the incentive should
not be allowed for public utilities ordered to join Transmission
Organizations by statute, merger conditions or other regulatory
requirements because there is no nexus between the incentive rates and
demonstrated consumer benefits.\136\ Finally, SMUD argues that the
Final Rule offered no explanation for providing an incentive for
utilities that are required to join Transmission Organizations as a
merger condition.\137\
---------------------------------------------------------------------------
\136\ Id. at 42-43.
\137\ SMUD at 7.
---------------------------------------------------------------------------
[[Page 1166]]
84. MISO TOs state that the Final Rule was unclear on the mechanics
of requesting incentives by RTO members and request clarification that
transmission owners may seek this incentive without opening up a
Commission-accepted ROE or additional rates or formulas.\138\
Specifically, they state that the Commission did not clarify that such
a single-issue filing will not open up the already Commission-accepted
ROE.
---------------------------------------------------------------------------
\138\ MISO TOs at 2-3.
---------------------------------------------------------------------------
85. Finally, APPA/NRECA argues that the Final Rule does not comply
with section 219(c) to provide incentives to each transmitting utility
or electric utility that joins a Transmission Organization because it
disregards incentives to non-jurisdictional utilities.\139\ The
Commission reasoning that it does not have jurisdiction to provide
incentives for non-public utilities joining Transmission Organizations
is unjustified when it has asserted jurisdiction in other
proceedings.\140\ APPA/NRECA recommend the Commission to consider
incentives for non-public utilities such as assurances that these
entities will fully recover all their costs of joining and
participating in the Transmission Organization.
---------------------------------------------------------------------------
\139\ APPA/NRECA at 53-54.
\140\ Id. P 54, citing City of Vernon, California and CAISO,
Opinion No. 479, 111 FERC ] 61,092, reh'g granted in part and denied
in part, 112 FERC ] 61,207 (2005), reh'g denied, 115 FERC ] 61,297
(2006).
---------------------------------------------------------------------------
2. Commission Determination
86. We affirm the finding in the Final Rule that the incentive
applies to all utilities joining transmission organizations,
irrespective of the date they join, based on a reading of section 219
in its entirety. Section 219 specifically provides that ``the
Commission shall * * * provide for incentives to each transmitting
utility or electric utility that joins a Transmission Organization.''
The stated purpose of section 219 is to provide incentive-based rate
treatments that benefit consumers by ensuring reliability and reducing
the cost of delivered power. We consider an inducement for utilities to
join, and remain in, Transmission Organizations to be entirely
consistent with those purposes. The consumer benefits, including
reliability and cost benefits, provided by Transmission Organizations
are well documented,\141\ and the best way to ensure those benefits are
spread to as many consumers as possible is to provide an incentive that
is widely available to member utilities of Transmission Organizations
and is effective for the entire duration of a utility's membership in
the Transmission Organization. To limit the incentive to only utilities
yet to join Transmission Organizations offers no inducement to stay in
these organizations for members with the option to withdraw, and hence
risks reducing Transmission Organization membership and its attendant
benefits to consumers. Because the incentive is applicable to utilities
that join Transmission Organizations and is consistent with the
requirements of section 219 of the FPA, the incentive complies with
EPAct 2005 and the FPA.\142\
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\141\ In Order No. 2000, in which the Commission's goal was to
promote efficiency in wholesale electricity markets and to ensure
that electricity consumers pay the lowest price possible for
reliable service, the Commission stated that:
These benefits [of RTOs] will include: Increased efficiency
through regional transmission pricing and the elimination of rate
pancaking; improved congestion management; more accurate estimates
of ATC; more effective management of parallel path flows; more
efficient planning for transmission and generation investments;
increased coordination among state regulatory agencies; reduced
transaction costs; facilitation of the success of state retail
access programs; facilitation of the development of environmentally
preferred generation in states with retail access programs; improved
grid reliability; and fewer opportunities for discriminatory
transmission practices. All of these improvements to the
efficiencies in the transmission grid will help improve power market
performance, which will ultimately result in lower prices to the
Nation's electricity consumers.
Order No. 2000, FERC Stats. & Regs. ] 31,089 at 31,024.
\142\ In light of our determination here, we reverse the policy
adopted in our decision in Southern California Edison. Our decision
in Southern California Edison failed to recognize that incentives
are equally important in inducing utilities to join and remain in
Transmission Organizations. Southern California Edison Co., 114 FERC
] 61,018, at P 16 (2005).
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87. We consider the claim of APPA/NRECA that the incentive is
inappropriate because it does not induce construction to be misplaced.
Section 219(c), applicable to the Transmission Organization incentive,
is separate from the construction incentives in subsection (b), and
therefore was not intended to directly encourage construction.\143\
However, we note that regional transmission organizations provide a
platform for regional planning and cost allocation associated with
transmission expansion and planning \144\ and therefore can help
support the identification and construction of transmission needed to
ensure reliability and to reduce congestion.
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\143\ We note that a more accurate interpretation of section
219(c) must recognize that an important component of section 219(c)
is ensuring cost recovery, and therefore this section differs from
the rest of section 219 that only address incentive-based rate
treatments. We note that the Midwest ISO tariff provisions governing
pass-through of transmission costs are consistent with this section,
and this section would provide the basis for approval of pass-
through of costs in other ISOs.
\144\ PJM Interconnection, L.L.C., 117 FERC ] 61,218 (2006);
Midwest Independent Transmission System Operator, Inc., 114 FERC ]
61,106 (2006), order denying reh'g, 117 FERC ] 61,241, (2006);
Midwest Independent Transmission System Operator, Inc., et al., 113
FERC ] 61,194 (2005); Midwest Independent Transmission System
Operator, Inc., 109 FERC ] 61,168, order granting clarification, 109
FERC ] 61,243 (2004), reh'g pending.
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88. We will not specify a particular method for establishing the
appropriate ROE for entities that join and/or continue to be a member
of an ISO, RTO, or other Commission-approved Transmission Organization
in this generic proceeding. For example, the mechanics of setting an
incentive ROE is an issue best addressed in a proceeding evaluating the
Transmission Organization incentive for transmission owners that belong
to the particular Transmission Organization. We recognize that the
issue was remanded to the Commission with respect to Midwest ISO.\145\
In the order on remand, the Commission observed that Midwest ISO or the
MISO TOs can make a filing under section 205 to include an incentive
adder.\146\
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\145\ Midwest Independent Transmission System Operator, Inc.,
100 FERC ] 61,292 (2002), order on reh'g, 102 FERC ] 61,143 (2003),
order on remand, 106 FERC ] 61,302 (2004), aff'd in part and
reversed in part, 397 F.3d 1004 (D.C. Cir. 2005).
\146\ Midwest Independent Transmission System Operator, Inc.,
111 FERC ] 61,355, at P 5 (2005).
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89. We affirm the Final Rule finding that this incentive applies to
public utilities, as required by section 219, and therefore does not
apply to non-public utilities and that non-public utilities may be
permitted incentive-based rate treatments under section 211(a) of the
FPA.
90. We will not make determinations on acceptable Transmission
Organization structures and affiliations in this proceeding. The
Commission will consider applications to form Transmission
Organizations, based on the requirements of Sec. 35.35(b), and make
its determinations on the facts and circumstances of each filing.
I. Hypothetical Capital Structure
91. In the Final Rule, the Commission found that hypothetical
capital structures can be an effective tool available to public
utilities to foster transmission investment in appropriate
circumstances. The Commission stated that it has allowed the use of
hypothetical structures to improve access to capital markets for
transmission investment and for specific projects when shown to be
necessary for
[[Page 1167]]
project financing.\147\ To encourage the development of new
transmission investment, the Commission noted that it will evaluate
each proposal on a case-by-case basis and will not prescribe specific
criteria or set target debt/equity ratios for evaluating hypothetical
capital structures. As with other incentives, the applicant is required
to demonstrate the required nexus between its proposed incentive and
the facts of its particular case.\148\
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\147\ The Commission noted that American Transmission and Trans-
Elect are examples of the use of hypothetical capital structure to
foster the development of transmission investment. Order No. 679,
FERC Stats. & Regs. ] 31,222 at P 131.
\148\ Id. P 133.
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1. Rehearing Requests
92. The California Commission considers the hypothetical capital
structure incentive-based rate treatment unnecessary for regulated
utilities. According to the California Commission, when a company
increases its actual debt ratio to a level higher than its optimal
capital structure, the company will expose itself to financial risks at
the expense of ratepayers, or will unnecessarily increase ratepayer
costs. The California Commission also faults the Commission for not
mandating the degree of rigorous scrutiny necessary for all cases
before they are approved.\149\ TDU Systems urge the Commission to
adhere to Allegheny Power precedent that rejected hypothetical capital
structures unless the utility's actual capital structure was so far out
of line with the market-driven capital structures of representative
proxy companies so as to be anomalous.\150\
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\149\ California Commission at 11-14.
\150\ TDU Systems at 35-36, citing Allegheny Power Co. 103 FERC
] 63,001, at P 28 (2003), aff'd, 106 FERC ] 61,241, at P 27 (2004)
(Allegheny Power).
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2. Commission Determination
93. We repeat our finding in the Final Rule that hypothetical
capital structures can be an appropriate ratemaking tool for fostering
new transmission in certain relatively narrow circumstances.
Historically, those circumstances have been somewhat unique, such as
consortiums that require a special capital structure or projects that
need project financing. As with other incentive ratemaking treatments,
the Commission will require any applicant to demonstrate the required
nexus between the need for a hypothetical capital structure and the
proposed investment project. We would not normally expect traditional
regulated utilities to propose incentives based on hypothetical capital
structures (as was suggested by the California Commission) and we note
that the Commission and state commissions have the ability to prevent
any regulated company from increasing its debt ratio to a level that
unnecessarily exposes wholesale or retail customers to unnecessary
risk.
J. Single-Issue Ratemaking
94. The Commission concluded in the Final Rule that single-issue
ratemaking can provide a significant incentive for new investment in
transmission infrastructure because it can provide 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.\151\ The Commission stated that single-
issue ratemaking applicants are only required to address cost and rate
issues associated with the investment in the section 205 proceeding to
approve rates. The applicant, however, is still required to fully
develop and support any transmission rate design to recover the costs
of a particular transmission system facility or upgrade, including cost
allocation and rate design.\152\ Further, the Commission noted that
each application will be evaluated by balancing the need for new
infrastructure, and the importance of permitting single-issue
ratemaking in support of that infrastructure, with the concerns over
whether a specific mechanism is required to re-open existing rates or
whether the traditional complaint processes are sufficient for that
purpose.\153\
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\151\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 191.
\152\ Id. P 192.
\153\ Id.
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1. Rehearing Requests
95. Petitioners claim that single-issue ratemaking, as described in
the Final Rule fails to balance shareholders' and consumers' interests
and permits transmission owners to earn an unjust and unreasonable
return on their overall transmission assets. They also assert that the
Commission ignored its long-standing policy of rejecting single-issue
ratemaking based on precedent that shows that single-issue ratemaking
can lead to transmission providers earning super-normal returns while
using single-issue rate filings to shield that fact from Commission
scrutiny.\154\ They argue that the Final Rule allows public utilities
to increase their transmission rates on a piecemeal basis without
providing procedures, short of section 206 complaints, to ensure that
the public utility's steadily increasing rates do not become unlawful.
They also contend that the Commission failed to consider reasonable
alternatives such as a mandatory full transmission rate case every
three years or allowing utilities to use formula rates that ensure a
balance between risks borne by shareholders and ratepayers.\155\
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\154\ APPA/NRECA argue that, if a public utility has experienced
load growth but has not invested in new transmission facilities, the
public utility will have a strong disincentive not to file a section
205 rate case, because it will be earning a high rate of return on
its highly depreciated rate base. They further assert that it has
been their members' general experience that when public utility
transmission providers believe they are undercollecting their
transmission revenue requirements, they are quick to address the
situation through a section 205 filing. APPA/NRECA at 41.
\155\ Id. at 40-43; TDU Systems at 21-23.
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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
[[Page 1168]]
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\
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\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).
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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
[[Page 1169]]
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.
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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.
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\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).
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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.
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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
[[Page 1170]]
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.
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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\
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\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.
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\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).
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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\
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\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)).
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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
[[Page 1171]]
related information that detail the level of transmission
investment.\188\
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\188\ Order No. 679, FERC Stats. & Regs. ] 31,222 at P 367-76.
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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\
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\189\ TAPS at 29-31.
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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.
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\190\ 18 CFR part 101.
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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\
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\191\ APPA/NRECA at 4; TAPS at 35.
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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\
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\192\ EEI at 6.
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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.
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\193\ TAPS at 12.
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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.
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\194\ See Order No. 679, FERC Stats. & Regs. ] 31,222 at P 36
(``an applicant may propose periodic progress assessments * * *'').
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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\
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\195\ TAPS at 28.
\196\ SMUD at 9-10.
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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
[[Page 1172]]
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.
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\197\ TAPS at 17-18.
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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\
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\198\ E.g., Order No. 679, FERC Stats. & Regs. ] 31,622 at P 81.
\199\ Id. P 192.
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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\
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\200\ Southern Companies at 19-20.
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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.
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\201\ Energy Financing at 4-5.
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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 (202) 502-8222
or the Public Reference Room at (202) 502-8371 Press 0, TTY (202) 502-
8659. E-Mail the Public Reference Room at
public.referenceroom@ferc.gov.
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.
* * * * *
[[Page 1173]]
(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