Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
Agency decision
Ask Donna
What actually matters in this document.
Text
1152
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
the consolidated entities or through the
payment of dividends or any similar
distribution, or an unsecured advance or
loan would be made to a stockholder,
partner, sole proprietor, limited liability
company member, employee or affiliate,
such that the withdrawal, advance or
loan would cause, on a net basis, a
reduction in excess adjusted net capital
(or, if the futures commission merchant
is qualified to use the filing option
available under § 1.10(h), excess net
capital as defined in the rules of the
Securities and Exchange Commission)
of 30 percent or more, notice must be
provided at least two business days
prior to the withdrawal, advance or loan
that would cause the reduction:
Provided, however, That the provisions
of paragraphs (g)(1) and (g)(2) of this
section do not apply to any futures or
securities transaction in the ordinary
course of business between a futures
commission merchant and any affiliate
where the futures commission merchant
makes payment to or on behalf of such
affiliate for such transaction and then
receives payment from such affiliate for
such transaction within two business
days from the date of the transaction.
*
*
*
*
*
■ 3. Section 1.17 is amended by revising
paragraph (d)(1) introductory text;
adding paragraph (d)(1)(ii)(D); revising
paragraph (e) introductory text; and
adding paragraph (g), to read as follows:
§ 1.17 Minimum financial requirements for
futures commission merchants and
introducing brokers.
mstockstill on PROD1PC61 with RULES
*
*
*
*
*
(d) * * *
(1) Equity capital means a satisfactory
subordination agreement entered into by
a partner or stockholder or limited
liability company member which has an
initial term of at least 3 years and has
a remaining term of not less than 12
months if:
*
*
*
*
*
(ii) * * *
(D) In the case of a limited liability
company, the sum of its capital
accounts of limited liability company
members, and unrealized profit and
loss.
*
*
*
*
*
(e) No equity capital of the applicant
or registrant or a subsidiary’s or
affiliate’s equity capital consolidated
pursuant to paragraph (f) of this section,
whether in the form of capital
contributions by partners (including
amounts in the commodities, options
and securities trading accounts of
partners which are treated as equity
capital but excluding amounts in such
trading accounts which are not equity
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
capital and excluding balances in
limited partners’ capital accounts in
excess of their stated capital
contributions), par or stated value of
capital stock, paid-in capital in excess of
par or stated value, retained earnings or
other capital accounts, may be
withdrawn by action of a stockholder or
partner or limited liability company
member or by redemption or repurchase
of shares of stock by any of the
consolidated entities or through the
payment of dividends or any similar
distribution, nor may any unsecured
advance or loan be made to a
stockholder, partner, sole proprietor,
limited liability company member, or
employee if, after giving effect thereto
and to any other such withdrawals,
advances, or loans and any payments of
payment obligations (as defined in
paragraph (h) of this section) under
satisfactory subordination agreements
and any payments of liabilities excluded
pursuant to paragraph (c)(4)(vi) of this
section which are scheduled to occur
within six months following such
withdrawal, advance or loan:
*
*
*
*
*
(g)(1) The Commission may by order
restrict, for a period up to twenty
business days, any withdrawal by a
futures commission merchant of equity
capital, or any unsecured advance or
loan to a stockholder, partner, limited
liability company member, sole
proprietor, employee or affiliate, if:
(i) Such withdrawal, advance or loan
would cause, when aggregated with all
other withdrawals, advances or loans
during a 30 calendar day period from
the futures commission merchant or a
subsidiary or affiliate of the futures
commission merchant consolidated
pursuant to § 1.17(f) (or 17 CFR
240.15c3–1e), a net reduction in excess
adjusted net capital (or, if the futures
commission merchant is qualified to use
the filing option available under
§ 1.10(h), excess net capital as defined
in the rules of the Securities and
Exchange Commission) of 30 percent or
more, and
(ii) The Commission, based on the
facts and information available,
concludes that any such withdrawal,
advance or loan may be detrimental to
the financial integrity of the futures
commission merchant, or may unduly
jeopardize its ability to meet customer
obligations or other liabilities that may
cause a significant impact on the
markets.
(2) The futures commission merchant
may file with the Secretary of the
Commission a written petition to
request rescission of the order issued
under paragraph (g)(1) of this section.
PO 00000
Frm 00018
Fmt 4700
Sfmt 4700
The petition filed by the futures
commission merchant must specify the
facts and circumstances supporting its
request for rescission. The Commission
shall respond in writing to deny the
futures commission merchant’s petition
for rescission, or, if the Commission
determines that the order issued under
paragraph (g)(1) of this section should
not remain in effect, the order shall be
rescinded.
*
*
*
*
*
Issued in Washington, DC, on January 5,
2007 by the Commission.
Eileen Donovan,
Acting Secretary of the Commission.
[FR Doc. E7–173 Filed 1–9–07; 8:45 am]
BILLING CODE 6351–01–P
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.
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
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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:
1153
Before Commissioners: Joseph T.
Kelliher, Chairman; Suedeen G. Kelly,
Marc Spitzer, Philip D. Moeller, and
Jon Wellinghoff.
TABLE OF CONTENTS
Paragraph
numbers
I. Introduction ...........................................................................................................................................................................................
II. Background ...........................................................................................................................................................................................
III. Discussion ...........................................................................................................................................................................................
A. Procedural Matters .......................................................................................................................................................................
B. Statutory Arguments .....................................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
C. Nexus Requirement ......................................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
D. Cost-Benefit Analysis ...................................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
E. Rebuttable Presumptions ..............................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
F. ROE Sufficient to Attract Investment ..........................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
G. Incentives Available to Transcos .................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
H. Transmission Organization Incentive .........................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
I. Hypothetical Capital Structure ......................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
J. Single-Issue Ratemaking ................................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
K. Public Power .................................................................................................................................................................................
1. Rehearing Requests ................................................................................................................................................................
2. Commission Determination ...................................................................................................................................................
L. Other Issues ...................................................................................................................................................................................
1. Recovery of Costs of Abandoned Facilities ..........................................................................................................................
2. Prudently Incurred Costs .......................................................................................................................................................
3. Regional Planning ..................................................................................................................................................................
4. CWIP .......................................................................................................................................................................................
5. Reporting Requirement: FERC–730 .......................................................................................................................................
6. Miscellaneous .........................................................................................................................................................................
IV. Information Collection Statement ......................................................................................................................................................
V. Document Availability ........................................................................................................................................................................
VI. Effective Date ......................................................................................................................................................................................
APPENDIX
Order on Rehearing
mstockstill on PROD1PC61 with RULES
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 performancebased) rate treatments for the
transmission of electric energy in
interstate commerce by public utilities.
These incentives are intended to benefit
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).
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
1
9
11
11
13
13
14
16
17
20
28
29
35
41
42
46
51
52
59
71
72
76
79
80
86
91
92
93
94
95
97
100
101
102
103
104
108
110
112
117
121
137
138
141
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.
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.
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
2 Energy Policy Act of 2005, Pub. L. No. 109–58,
119 Stat. 594, 315 and 1283 (2005).
3 The parties who filed the requests for rehearing
and/or clarification are listed in Appendix A.
PO 00000
Frm 00019
Fmt 4700
Sfmt 4700
E:\FR\FM\10JAR1.SGM
10JAR1
mstockstill on PROD1PC61 with RULES
1154
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
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
4 16 U.S.C.A. 824s(a), (b)(1) (West Supp. 2006).
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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.
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
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.
PO 00000
Frm 00020
Fmt 4700
Sfmt 4700
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
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
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.
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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
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.
9 Order No. 679, FERC Stats. & Regs ¶ 31,222 at
mstockstill on PROD1PC61 with RULES
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.
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).
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
1155
economically or technologically
efficient transmission infrastructure.16
1. Rehearing Requests
Section 219 was enacted against the
13. APPA/NRECA argue that the
backdrop of a long decline in
Commission misinterpreted section 219 transmission investment that is
as requiring greater flexibility in
imposing substantial costs—in
ratemaking practices. According to
congestion and service interruptions—
APPA/NRECA, ‘‘incentives’’ are not
on consumers. If Congress had deemed
necessary to attract capital because,
our existing practices sufficient to
under existing Supreme Court
reverse this trend, there would have
precedent, ‘‘a public utility’s rate of
been little need to enact section 219.
return should also be sufficient to attract Section 219 does not simply ‘‘codify’’
investment in new transmission
our legal authority; it requires us to take
facilities.’’ 13 APPA/NRECA therefore
affirmative action to promote new
conclude that section 219 merely
investment. Although the resulting rates
‘‘codified the longstanding Commission must be just and reasonable, the
and judicial interpretations of FPA
Commission has significant discretion
section 205’s requirement that rates be
under section 205 in making that
just and reasonable.’’ 14
determination and section 219 provides
clear direction that we use that
2. Commission Determination
discretion to promote new
14. We agree with APPA/NRECA that infrastructure, not simply maintain the
section 219 did not modify the
status quo.
requirement that rates be just and
15. While section 219 requires us to
reasonable under section 205, but
do more than maintain the status quo
disagree that it did no more than restate for transmission pricing, we recognize
that longstanding principle. Section 219 that our traditional ratemaking authority
makes very clear that the Commission
also requires us to establish a return on
‘‘shall establish, by rule, incentive-based a public utility’s assets that is
‘‘reasonably sufficient to assure
(including performance-based) rate
confidence in the financial soundness of
treatments’’ and that these rate
the utility and should be adequate to
treatments ‘‘shall * * * promote
maintain and support its credit and
reliable and economically efficient
enable it to raise money necessary for
transmission and generation of
the proper discharge of its public
electricity by promoting capital
duties’’ 17 and ‘‘should be sufficient to
investment in the enlargement,
assure confidence in the financial
improvement, maintenance, and
integrity of the enterprise, so as to
operation of all facilities for the
maintain its credit and to attract
transmission of electric energy in
capital.’’ 18 Thus, a base-level ROE
interstate commerce, regardless of the
sufficient to promote capital investment
ownership of the facilities; provide a
in transmission facilities historically has
return on equity that attracts new
not been considered an ‘‘incentive,’’ but
investment in transmission facilities
a requirement of establishing a just and
(including related transmission
technologies); encourage deployment of reasonable rate.19 In this regard, we
transmission technologies and other
16 See id. at 824s(a) and (b)(3).
measures to increase the capacity and
17 Bluefield Waterworks & Improvement Co. v.
efficiency of existing transmission
Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 693
facilities and improve the operation of
(1923).
18 FPC v. Hope Natural Gas Co., 320 U.S. 591, 603
the facilities and allow recovery of—(A)
all prudently incurred costs necessary to (1944).
19 In contrast to a base-level ROE that reflects the
comply with mandatory reliability
financial and regulatory risks of an investment, an
standards issued pursuant to section
‘‘incentive’’ has been more typically associated with
215 and (B) all prudently incurred costs specific basis point additions to a base ROE to
satisfy discrete policy objectives. See, e.g., Western
related to transmission infrastructure
Area Power, 99 FERC ¶ 61,306, reh’g denied, 100
development pursuant to section
FERC ¶ 61,331 (2002) (Western), aff’d sub nom.
216.’’ 15 These words do far more than
Public Utilities Commission of the State of
‘‘codify’’ the just and reasonable
California v. FERC, 367 F.3d 925 (D.C. Cir. 2004);
Michigan Electric Transmission Co., LLC, 105 FERC
standard; they command the
¶ 61,214 (2003) (METC); American Transmission
Commission to use its discretion under
Company, L.L.C., 105 FERC ¶ 61,388 (2003)
section 205 to promote capital
(American Transmission); ITC Holdings Corp., 102
investment. Furthermore, Congress in
FERC ¶ 61,182, reh’g denied, 104 FERC ¶ 61,033
(2003) (ITC Holdings); Regional Transmission
section 219 even highlighted the
Organizations, Order No. 2000, 65 FR 809 (Jan. 6,
importance of investment in
B. Statutory Arguments
13 APPA/NRECA at 12.
14 Id. at 12–13.
15 16 U.S.C.A. 824s(a), (b)(1)–(4) (West Supp.
2006).
PO 00000
Frm 00021
Fmt 4700
Sfmt 4700
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)
E:\FR\FM\10JAR1.SGM
Continued
10JAR1
1156
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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 baselevel 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
mstockstill on PROD1PC61 with RULES
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
(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).
22 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at
P 2, 26.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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 noncost 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
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
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 incentiveincreased 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
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
23 Id. P 26, 48.
24 Industrial Consumers at 3–7.
30 APPA/NRECA at 22.
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.
29 5 U.S.C. 556 (2000).
PO 00000
Frm 00022
Fmt 4700
Sfmt 4700
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.
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).
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
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:
mstockstill on PROD1PC61 with RULES
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
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.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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]
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
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
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
41 Id. P 25.
42 Id. P 27.
43 See infra P 52.
44 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at
P 48.
PO 00000
Frm 00023
Fmt 4700
Sfmt 4700
1157
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.
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
E:\FR\FM\10JAR1.SGM
10JAR1
1158
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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 § 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.
mstockstill on PROD1PC61 with RULES
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
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).
46 APPA/NRECA at 26; TDU Systems at 11.
47 APPA/NRECA at 26–27.
48 TDU Systems at 12.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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.
30. TDU Systems and APPA/NRECA
also argue that elimination of the costbenefit 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
49 Id. at 15; APPA/NRECA at 27.
50 APPA/NRECA at 29, citing Farmers Union, 734
F.2d at 1502.
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.
PO 00000
Frm 00024
Fmt 4700
Sfmt 4700
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.
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
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
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 costbenefit test for incentive rates. SMUD
states that, while the Commission
recognized the non-cost-based nature of
incentive ratemaking in the 1992 Policy
53 Order No. 2000, supra note 19.
54 Industrial Consumers at 7–8.
55 Id.
56 Id. at 10.
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
34. TAPS asserts that the
Commission’s authority to award abovecost 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.
mstockstill on PROD1PC61 with RULES
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
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).
58 TAPS at 9, citing CPUC v. FERC, 367 F.3d at
929.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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.
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 costbenefit 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 noncost factors applies equally in the
development of incentive ratetreatments.61
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
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.
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’’).
PO 00000
Frm 00025
Fmt 4700
Sfmt 4700
1159
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
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
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.
E:\FR\FM\10JAR1.SGM
10JAR1
1160
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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
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
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
mstockstill on PROD1PC61 with RULES
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.
69 Id. at 7; TAPS at 6; APPA/NRECA at 37–39;
TDU Systems at 25–27.
70 APPA/NRECA at 38.
71 NARUC at 7.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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 threepart 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
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,
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.
PO 00000
Frm 00026
Fmt 4700
Sfmt 4700
we grant rehearing and are modifying
§ 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
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
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 prerequisites 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.
78 Section 216(b)(4). See also Regulations for
Filing Applications for Permits to Site Interstate
Electric Transmission Facilities, Order No. 689, 71
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
F. ROE Sufficient To Attract Investment
mstockstill on PROD1PC61 with RULES
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
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’’).
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.
80 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at
P 91.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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 nonroutine 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
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
1161
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.
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 self87 TDU Systems at 27–29.
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.
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).
PO 00000
Frm 00027
Fmt 4700
Sfmt 4700
88 APPA/NRECA at 9, 47.
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).
E:\FR\FM\10JAR1.SGM
10JAR1
1162
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
escalating spiral with the highest proxy
result reflecting an investor expectation
that the proxy itself will garner abovecost incentive profits.91
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
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 constantgrowth DCF model often produces
divergent and meaningless results.95
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
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
mstockstill on PROD1PC61 with RULES
91 Id. at 22.
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.
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.
96 Id. at 18.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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 HydroElectric 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
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.
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.
PO 00000
Frm 00028
Fmt 4700
Sfmt 4700
determine whether an ROE incentive
will produce justifiable benefits.
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
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
mstockstill on PROD1PC61 with RULES
small effect on the overall range of
reasonableness, it will appropriately
reflect the substantial risks associated
with constructing new transmission, as
discussed above.104
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
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 decisionmaking. 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 longterm 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
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.
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.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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 HydroElectric proceeding because they have
been addressed in a recent Commission
order and are now pending on
rehearing.106
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.
106 Bangor Hydro-Electric Co., Opinion No. 489,
117 FERC ¶ 61,129 (2006).
PO 00000
Frm 00029
Fmt 4700
Sfmt 4700
1163
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 upfront 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
107 Section 35.35(b)(1) defines Transcos as standalone 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.
E:\FR\FM\10JAR1.SGM
10JAR1
1164
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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
mstockstill on PROD1PC61 with RULES
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
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.
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
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.
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.
112 Southern Companies at 16–17.
113 Id. at 17, citing Order No. 679, FERC Stats. &
Regs. ¶ 31,222 at P 225.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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 loadserving 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
2. Commission Determination
76. We affirm the finding in the Final
Rule that the Commission will not limit
an applicant’s ability to seek incentivebased rate treatments based on corporate
structure or ownership.120 The
Commission will evaluate these
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 standalone 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.
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.
120 See Order No. 679, FERC Stats. & Regs.
¶ 31,222 at P 4.
PO 00000
Frm 00030
Fmt 4700
Sfmt 4700
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.
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.
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.
121 Id. P 222–23.
122 See id. P 202.
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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 Commissionapproved 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.
1. Rehearing Requests
mstockstill on PROD1PC61 with RULES
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
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.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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/
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.
130 California Commission at 16.
131 Id. P 17–18; TDU Systems at 43.
PO 00000
Frm 00031
Fmt 4700
Sfmt 4700
1165
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
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
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
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.
135 TDU Systems at 41–42.
136 Id. at 42–43.
137 SMUD at 7.
E:\FR\FM\10JAR1.SGM
10JAR1
1166
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
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.
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 incentivebased 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
138 MISO TOs at 2–3.
mstockstill on PROD1PC61 with RULES
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).
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
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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
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).
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
PO 00000
Frm 00032
Fmt 4700
Sfmt 4700
support the identification and
construction of transmission needed to
ensure reliability and to reduce
congestion.
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
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 § 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
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.
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).
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
project financing.147 To encourage the
development of new transmission
investment, the Commission noted that
it will evaluate each proposal on a caseby-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
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
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
mstockstill on PROD1PC61 with RULES
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.
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).
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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 longstanding 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
151 Order No. 679, FERC Stats. & Regs. ¶ 31,222
at P 191.
152 Id. P 192.
153 Id.
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
PO 00000
Frm 00033
Fmt 4700
Sfmt 4700
1167
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
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 singleissue 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
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
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.
156 156 Xcel at 4–5.
157 Id. at 5.
E:\FR\FM\10JAR1.SGM
10JAR1
1168
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
mstockstill on PROD1PC61 with RULES
transmission investment and we
specifically committed that the
Commission would consider the need to
combine or reconcile any projectspecific 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 existingsystem rate issues.160
99. Based on the precedent cited
above, we disagree with the conclusion
that acceptance of single-issue rate
filings would represent a dramatic shift
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-ofservice. 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).
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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
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
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.
163 TAPS at 22.
PO 00000
Frm 00034
Fmt 4700
Sfmt 4700
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 nontransmission 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 coinvestors, including public and
consumer-owned utilities and where coinvestors were sought but not permitted
to participate, the proponent of an
incentive should be required to explain
why this was the case.167
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
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.
168 Order No. 679, FERC Stats. & Regs. ¶ 31,222
at P 354.
E:\FR\FM\10JAR1.SGM
10JAR1
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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.
mstockstill on PROD1PC61 with RULES
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 prudentlyincurred 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
169 See OATT Reform NOPR, supra note 63.
170 TDU Systems at 38.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
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.
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.
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 overrecovery 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
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).
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.
174 TDU Systems at 38.
PO 00000
Frm 00035
Fmt 4700
Sfmt 4700
1169
into account in establishing an
appropriate equity return for the project.
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.
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
175 MISO TOs at 4–5.
176 Industrial Consumers at 11.
177 NARUC at 6; TAPS at 7.
E:\FR\FM\10JAR1.SGM
10JAR1
1170
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
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
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.
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
178 TDU Systems at 9–10.
mstockstill on PROD1PC61 with RULES
179 APPA/NRECA at 16–19.
113. TDU Systems assert that the
Commission should only allow 100
percent recovery CWIP and precommercial 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 precommercial 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
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.
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
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).
182 Order No. 679, FERC Stats. & Regs. ¶ 31,222
at P 115–22.
VerDate Aug<31>2005
14:45 Jan 09, 2007
Jkt 211001
183 TDU Systems at 9–10.
184 Id. at 37.
185 See Order No. 679, FERC Stats. & Regs.
¶ 31,222 at P 122 and n 82.
186 See, e.g., American Electric Power Service
Corp., 116 FERC ¶ 61,059, at P 55 (2006), reh’g
PO 00000
Frm 00036
Fmt 4700
Sfmt 4700
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 prudentlyincurred costs.
116. For example, where an applicant
has satisfied our nexus requirement and
has been granted authority to recover
CWIP or abandoned plant, and
subsequently the applicant’s project is,
for example, unable to obtain state or
federal siting authority (and thus no
showing is made with respect to
ensuring reliability or reducing the cost
of delivered power by reducing
congestion because the applicant was
relying upon those processes) we would
not require refunds for the costs already
prudently-incurred by the applicant. To
require refunds in such circumstances
would be contrary to our long-standing
policy, which permits recovery of all
prudently-incurred costs.187
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
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).
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)).
E:\FR\FM\10JAR1.SGM
10JAR1
mstockstill on PROD1PC61 with RULES
Federal Register / Vol. 72, No. 6 / Wednesday, January 10, 2007 / Rules and Regulations
related information that detail the level
of transmission investment.188
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
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
188 Order No. 679, FERC Stats. & Regs. ¶ 31,222
at P 367–76.
189 TAPS at 29–31.
190 18 CFR part 101.
VerDate Aug<31>2005
14:45 Jan 09, 2007
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.
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
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
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 § 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 incentiveworthy, congestion-reducing, new line
packaged with mundane existing facility
replacements that have already been
committed to and do not advance the
191 APPA/NRECA at 4; TAPS at 35.
192 EEI at 6.
Jkt 211001
PO 00000
Frm 00037
Fmt 4700
Sfmt 4700
1171
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.
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.
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. performancebased 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
This text is long and has been trimmed here. Open the source document for the complete record.
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.