[Federal Register Volume 75, Number 125 (Wednesday, June 30, 2010)]
[Proposed Rules]
[Pages 37884-37916]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-15735]
[[Page 37883]]
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Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Transmission Planning and Cost Allocation by Transmission Owning and
Operating Public Utilities; Proposed Rule
Federal Register / Vol. 75 , No. 125 / Wednesday, June 30, 2010 /
Proposed Rules
[[Page 37884]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM10-23-000]
Transmission Planning and Cost Allocation by Transmission Owning
and Operating Public Utilities
Issued June 17, 2010.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission is proposing to amend
the transmission planning and cost allocation requirements established
in Order No. 890 to ensure that Commission-jurisdictional services are
provided on a basis that is just, reasonable and not unduly
discriminatory or preferential. With respect to transmission planning,
the proposed rule would provide that local and regional transmission
planning processes account for transmission needs driven by public
policy requirements established by State or Federal laws or
regulations; improve coordination between neighboring transmission
planning regions with respect to interregional facilities; and remove
from Commission-approved tariffs or agreements a right of first refusal
created by those documents that provides an incumbent transmission
provider with an undue advantage over a nonincumbent transmission
developer. Neither incumbent nor nonincumbent transmission facility
developers should, as a result of a Commission-approved tariff or
agreement, receive different treatment in a regional transmission
planning process. Further, both should share similar benefits and
obligations commensurate with that participation, including the right,
consistent with State or local laws or regulations, to construct and
own a facility that it sponsors in a regional transmission planning
process and that is selected for inclusion in the regional transmission
plan. With respect to cost allocation, the proposed rule would
establish a closer link between transmission planning processes and
cost allocation and would require cost allocation methods for
intraregional and interregional transmission facilities to satisfy
newly established cost allocation principles.
DATES: Comments are due August 30, 2010.
ADDRESSES: You may submit comments, identified by docket number by any
of the following methods:
Agency Web Site: http://www.ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
Mail/Hand Delivery: Commenters unable to file comments
electronically must mail or hand deliver an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Office of the
Secretary, 888 First Street, NE., Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document
FOR FURTHER INFORMATION CONTACT:
Russell Profozich, Federal Energy Regulatory Commission, Office of
Energy Policy and Innovation, 888 First Street, NE., Washington, DC
20426, (202) 502-6478.
John Cohen, Federal Energy Regulatory Commission, Office of the General
Counsel, 888 First Street, NE., Washington, DC 20426, (202) 502-8705.
SUPPLEMENTARY INFORMATION:
Notice of Proposed Rulemaking
Table of Contents
Paragraph
Nos.
I. Introduction............................................. 1
II. Background.............................................. 6
A. Order Nos. 888 and 890............................... 6
B. Technical Conferences and Notice of Request for 13
Comments on Transmission Planning and Cost Allocation..
C. Additional Developments Since Issuance of Order No. 25
890....................................................
III. The Need for Reform.................................... 32
IV. Proposed Reforms: Transmission Planning................. 44
A. Participation in the Regional Planning Process....... 45
B. Public Policy Driven Projects........................ 55
C. Opportunities for Undue Discrimination Against 71
Nonincumbent Transmission Developers...................
1. Nonincumbent Transmission Developer Participation 71
in the Transmission Planning Process...............
2. Proposed Reforms Regarding Nonincumbents......... 87
D. Interregional Coordination........................... 102
1. The Need for Interregional Planning Reforms...... 102
2. Proposed Interregional Planning Reforms.......... 114
V. Proposed Reforms: Cost Allocation........................ 121
A. Introduction......................................... 121
1. Order No. 890's Transmission Planning Principle 121
on Cost Allocation for New Transmission Facilities.
2. October 2009 Notice and Subsequent Comments...... 129
B. Legal Authority and Need for Reform.................. 138
1. The Cost Causation Principle..................... 139
2. Need for Reform.................................. 148
C. Proposed Reforms..................................... 155
1. Intraregional Cost Allocation.................... 164
2. Interregional Cost Allocation.................... 170
VI. Compliance Filings...................................... 179
VII. Information Collection Statement....................... 182
VIII. Environmental Analysis................................ 186
IX. Regulatory Flexibility Act Analysis..................... 187
X. Comment Procedures....................................... 188
XI. Document Availability................................... 192
Regulatory Text
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Appendix A: List of Short Names of Commenters on the Federal
Energy Regulator Commission's Notice of Request for
Comments on Transmission Planning Processes Under Order No.
890--Docket No. AD09-8-000, October 2009
Appendix B: Pro Forma Open Access Transmission Tariff
Attachment K
Notice of Proposed Rulemaking
Issued June 17, 2010.
I. Introduction
1. In this Notice of Proposed Rulemaking (Proposed Rule), the
Federal Energy Regulatory Commission (Commission) is proposing to
reform its electric transmission planning and cost allocation
requirements for public utility transmission providers. The proposed
reforms are intended to correct deficiencies in transmission planning
and cost allocation processes so that the transmission grid can better
support wholesale power markets and thereby ensure that Commission-
jurisdictional services are provided at rates, terms and conditions
that are just and reasonable and not unduly discriminatory or
preferential.
2. This Proposed Rule builds on Order No. 890,\1\ in which the
Commission reformed the pro forma open access transmission tariff
(OATT). Among other changes, Order No. 890 required each public utility
transmission provider to have a coordinated, open, and transparent
regional transmission planning process. Order No. 890 also established
nine transmission planning principles, one of which addressed cost
allocation for new projects.
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\1\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
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3. The Commission acknowledges that significant work has been done
in recent years to enhance regional transmission planning processes.
The reforms proposed herein seek to build on this progress by improving
the effectiveness of regional transmission planning and the efficiency
of resulting transmission development. In formulating this proposal,
the Commission has sought to balance competing interests and identify a
package of reforms that, if implemented, would support the development
of transmission facilities identified by the region as necessary to
satisfy reliability standards, reduce congestion, and enable compliance
with public policy requirements established by State or Federal laws or
regulations. The Commission recognizes that opinions may differ as to
whether the proposal as formulated will best achieve the Commission's
goals. The Commission therefore seeks comment on the reforms proposed
herein and encourages commenters to identify enhancements to the
reforms that could better support the efficient and effective
development of transmission facilities.
4. With respect to transmission planning, the reforms proposed in
this Proposed Rule would provide that: (1) Local and regional
transmission planning processes account for transmission needs driven
by public policy requirements established by State or Federal laws or
regulations; (2) coordination between neighboring transmission planning
regions is improved with respect to facilities that are proposed to be
located in both regions, as well as interregional facilities that could
address transmission needs more efficiently than separate intraregional
facilities; and (3) a right of first refusal that is created by a
document subject to the Commission's jurisdiction and that provides an
incumbent utility with an undue advantage over nonincumbent
transmission project developers is removed from that document. Neither
incumbent nor nonincumbent transmission facility developers should, as
a result of a Commission-approved OATT or agreement, receive different
treatment in a regional transmission planning process. Further, both
should share similar benefits and obligations commensurate with that
participation, including the right, consistent with State or local laws
or regulations, to construct and own a facility that it sponsors in a
regional transmission planning process and that is selected for
inclusion in the regional transmission plan. The Commission
preliminarily finds that these proposed reforms are needed to protect
against unjust and unreasonable rates, terms and conditions and undue
discrimination in the provision of Commission-jurisdictional services.
5. With respect to transmission cost allocation, the Commission is
proposing to require public utility transmission providers to establish
a closer link between cost allocation and regional transmission
planning processes in which the beneficiaries of new transmission
facilities are identified, as well as to establish principles that cost
allocation methods must satisfy. The Commission sees these proposals as
steps that would increase the likelihood that facilities included in
regional transmission plans are actually constructed. For example,
establishing a closer link between transmission planning and cost
allocation processes would diminish the likelihood that a transmission
facility would be included in a regional transmission plan, only to
later encounter cost allocation disputes that inhibit construction of
that facility.
II. Background
A. Order Nos. 888 and 890
6. In Order No. 888,\2\ issued in 1996, the Commission found that
it was in the economic interest of transmission providers to deny
transmission service or to offer transmission service on a basis that
is inferior to that which they provide to themselves.\3\ Concluding
that unduly discriminatory and anticompetitive practices existed in the
electric industry and that, absent Commission action, such practices
would increase as competitive pressures in the industry grew, the
Commission in Order No. 888 and the accompanying pro forma OATT
implemented open access to transmission facilities owned, operated, or
controlled by a public utility.
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\2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\3\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,682.
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7. As part of those reforms, Order No. 888 and the pro forma OATT
set forth certain minimum requirements for transmission planning. For
example, the pro forma OATT required a public utility transmission
provider to account for the needs of its network customers in its
transmission planning activities on the same basis as it provides for
its own needs.\4\ The pro forma OATT also required that new facilities
be constructed to meet the service requests of long-term firm point-to-
point
[[Page 37886]]
customers.\5\ While Order No. 888-A went on to encourage utilities to
engage in joint and regional transmission planning with other utilities
and customers, it did not require those actions.\6\
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\4\ See Section 28.2 of the pro forma OATT.
\5\ See Sections 13.5, 15.4, & 27 of the pro forma OATT.
\6\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,311.
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8. In early 2007, the Commission issued Order No. 890 to remedy
flaws in the pro forma OATT that the Commission identified based on the
decade of experience since the issuance of Order No. 888. Among other
things, the Commission found that pro forma OATT obligations related to
transmission planning were insufficient to eliminate opportunities for
undue discrimination in the provision of transmission service. The
Commission stated that particularly in an era of increasing
transmission congestion and the need for significant new transmission
investment, it could not rely on the self-interest of transmission
providers to expand the grid in a not unduly discriminatory manner.
Among other shortcomings in the pro forma OATT, the Commission pointed
to the lack of clear criteria regarding the transmission provider's
planning obligation; the absence of a requirement that the overall
transmission planning process be open to customers, competitors, and
State commissions; and the absence of a requirement that key
assumptions and data underlying transmission plans be made available to
customers.
9. In light of these findings, one of the primary goals of the
reforms undertaken in Order No. 890 was to address the lack of
specificity regarding how customers and other stakeholders should be
treated in the transmission planning process. To remedy the potential
for undue discrimination in transmission planning activities, the
Commission required each public utility transmission provider to
develop a transmission planning process that satisfies nine principles
and to clearly describe that process in a new attachment to its OATT
(Attachment K). The Order No. 890 transmission planning principles are:
(1) Coordination; (2) openness; (3) transparency; (4) information
exchange; (5) comparability; (6) dispute resolution; (7) regional
participation; (8) economic planning studies; and (9) cost allocation
for new projects.\7\
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\7\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 418-601.
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10. The transmission planning reforms adopted in Order No. 890
apply to all public utility transmission providers, including
Commission-approved regional transmission organizations (RTOs) and
independent system operators (ISOs). The Commission also stated that it
expected all non-public utility transmission providers to participate
in the planning processes required by Order No. 890. The Commission
noted that reciprocity dictates that non-public utility transmission
providers that take advantage of open access due to improved planning
should be subject to the same requirements as jurisdictional
transmission providers.\8\ The Commission stated that a coordinated,
open, and transparent regional planning process cannot succeed unless
all transmission owners participate. However, the Commission did not
invoke its authority under FPA section 211A, which allows the
Commission to require an unregulated transmitting utility (i.e., a non-
public utility transmission provider) to provide transmission services
on a comparable and not unduly discriminatory or preferential basis.\9\
The Commission instead stated that if it found on the appropriate
record that non-public utility transmission providers are not
participating in the planning processes required by Order No. 890, then
the Commission may exercise its authority under FPA section 211A on a
case-by-case basis.
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\8\ Id. P 441.
\9\ FPA section 211A(b) provides, in pertinent part, that ``the
Commission may, by rule or order, require an unregulated
transmitting utility to provide transmission services--(1) at rates
that are comparable to those that the unregulated transmitting
utility charges itself; and (2) on terms and conditions (not
relating to rates) that are comparable to those under which the
unregulated transmitting utility provides transmission services to
itself and that are not unduly discriminatory or preferential.'' 16
U.S.C. 824j (2006).
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11. On December 7, 2007, pursuant to Order No. 890, most public
utility transmission providers and several non-public utility
transmission providers submitted compliance filings that describe their
proposed transmission planning processes.\10\ The Commission addressed
these filings in a series of orders that were issued throughout 2008.
Generally, the Commission accepted the compliance filings to be
effective December 7, 2007, subject to further compliance filings as
necessary for the proposed transmission planning processes to satisfy
the nine transmission planning principles. The Commission issued
additional orders on Order No. 890 transmission planning compliance
filings in the spring and summer of 2009.
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\10\ A small number of transmission providers were granted
extensions.
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12. As a result of these compliance filings, RTOs and ISOs have
enhanced their regional transmission planning processes, making them
more open, transparent, and inclusive. Regions of the country outside
of RTO and ISO regions have also made significant strides with respect
to transmission planning by working together to enhance existing, or
create new, regional transmission planning processes.\11\ These
improvements to transmission planning processes have given customers
and other stakeholders the opportunity to participate in the
identification of regional needs and corresponding solutions, thereby
facilitating the development of more efficient and effective
transmission expansion plans.
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\11\ The regional transmission planning processes that public
utility transmission providers in regions outside of RTOs and ISOs
have relied on to comply with certain requirements of Order No. 890
are the North Carolina Transmission Planning Collaborative,
Southeast Inter-Regional Participation Process, SERC Reliability
Corporation, ReliabilityFirst Corporation, Mid-Continent Area Power
Pool, Florida Reliability Coordination Council, WestConnect,
ColumbiaGrid, and Northern Tier Transmission Group.
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B. Technical Conferences and Notice of Request for Comments on
Transmission Planning and Cost Allocation
13. In several of the above-noted orders issued in 2008 and early
2009 on filings submitted to comply with the Order No. 890 transmission
planning requirements, the Commission stated that it would continue to
monitor implementation of these transmission planning processes. The
Commission also announced its intention to convene regional technical
conferences in 2009.
14. Consistent with the Commission's announcement, Commission staff
in September 2009 convened three regional technical conferences in
Philadelphia, Atlanta, and Phoenix, respectively. The focus of the
technical conferences was to: (1) Determine the progress and benefits
realized by each transmission provider's transmission planning process,
obtain customer and other stakeholder input, and discuss any areas that
may need improvement; (2) examine whether existing transmission
planning processes adequately consider needs and solutions on a
regional or interconnection-wide basis to ensure adequate and reliable
supplies at just and reasonable rates; and (3) explore whether existing
processes are sufficient to meet emerging challenges to the
transmission system, such as the development of interregional
transmission facilities and the integration of large amounts of
location-constrained generation. Issues discussed
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at the technical conferences included the effectiveness of the current
transmission planning processes, the development of regional and
interregional transmission plans, and the effectiveness of existing
cost allocation methods used by transmission providers and alternatives
to those methods.
15. Following these technical conferences, the Commission in
October 2009 issued a Notice of Request for Comments.\12\ The October
2009 Notice presented numerous questions with respect to enhancing
regional transmission planning processes and allocating the cost of
transmission.
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\12\ Federal Energy Regulatory Commission, Transmission Planning
Processes Under Order No. 890; Notice of Request for Comments;
Docket No. AD09-8-000, October 8, 2009 (October 2009 Notice).
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16. In response to the October 2009 Notice, the Commission received
107 initial comments and 45 reply comments.\13\ Many of these comments
are discussed in greater detail later in this Proposed Rule, in the
context of the Commission's proposals on specific issues.
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\13\ See Appendix A for a list of the commenters and their
abbreviated names.
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17. In general, some commenters oppose additional Commission action
at this time with respect to transmission planning. Among these
commenters, some argue that existing transmission planning processes
are adequate to achieve the Commission's stated goals.\14\ Some of
these commenters highlight work already underway in their own
transmission planning regions, arguing that no Commission action is
needed at least in those regions. Other commenters argue that existing
processes are new or are being revised and should be given time to
mature before additional changes are proposed. Many of these commenters
state that if the Commission chooses to act, it should do so in a
manner that does not disrupt existing transmission planning processes.
Some commenters that oppose Commission action on transmission planning
at this time state that it is important to maintain what they describe
as a ``bottom-up'' approach to transmission planning, in which regional
transmission planning is based on transmission planning conducted by
the individual transmission-owning utilities in a transmission planning
region.\15\
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\14\ E.g., Dominion, Large Public Power Council, Midwest ISO,
New York PSC, Northern Tier Transmission Group, and WECC.
\15\ E.g., Ohio Commission, PPL, Southern Companies, and WECC.
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18. Many other commenters support additional Commission action on
transmission planning at this time.\16\ These commenters offer a wide
range of views on why and how the planning process should be improved.
Although these commenters express diverse views, there appears to be a
consensus among those supporting action that the Commission should--at
a minimum--provide guidance about planning for large, interregional
transmission projects.
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\16\ E.g., American Transmission, CAlifornians for Renewable
Energy, Dayton Power and Light, E.ON, LS Power, NRG, Pioneer
Transmission, San Diego Gas & Electric, and Transmission Access
Policy Study Group.
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19. Many commenters that support Commission action on transmission
planning raise issues related to the procedural characteristics or
geographic scope of existing transmission planning processes. Some
commenters contend that the Order No. 890 transmission planning
principles should be extended to support interregional coordination,
while others argue that additional planning principles are necessary to
ensure the effectiveness of transmission planning processes. Some
commenters suggest that the type of ``bottom-up'' transmission planning
described above is insufficient,\17\ and other commenters advocate
changes such as establishing a regional or interconnection-wide
planning coordinator.\18\ A few commenters suggest that the Commission
add to the OATT a pro forma seams agreement that includes joint
collaborative planning and cost allocation across planning regions.\19\
Still other commenters support changes to transmission planning
processes, but caution against adopting a one-size-fits-all or an
interconnectionwide approach.\20\
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\17\ E.g., Calvin Daniels (commenting as an individual).
\18\ E.g., AEP.
\19\ E.g., Midwest ISO Transmission Owners, National Rural
Electric Coops, and SPP.
\20\ E.g., Pacific Gas and Electric and Transmission Agency of
Northern California.
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20. Other commenters that support Commission action on transmission
planning argue that some existing transmission planning processes
provide an incumbent transmission owner with an unfair advantage over
merchant and independent transmission project developers, such as by
providing an incumbent transmission owner with a right of first refusal
\21\ to construct a transmission facility that is included in a
regional transmission plan and meets certain other criteria.\22\ These
commenters argue that such practices discourage other, merchant and
independent transmission developers' \23\ participation in the
transmission planning process and present a significant barrier to
transmission investment. Other commenters state that projects proposed
by merchant and independent transmission project developers need to be
included fully in regional transmission planning processes on the same
basis as other projects.\24\
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\21\ A right of first refusal is defined, for the purposes of
this proposed rulemaking, as the right of an incumbent transmission
owner to construct, own, and propose cost recovery for any new
transmission project that is: (1) Located within its service
territory; and (2) approved for inclusion in a transmission plan
developed through the Order No. 890 planning process.
\22\ E.g., AWEA, EPSA, LS Power, and Transmission Dependent
Utility Systems.
\23\ Merchant transmission projects are defined as those for
which the costs of constructing the proposed transmission facilities
will be recovered through negotiated rates instead of cost-based
rates. For purposes of this proposed rulemaking, an incumbent
transmission developer is an entity that develops a project within
its own service territory. We note that a transmission owner that
proposes a project outside of its own service territory is not
considered an incumbent for purposes of that project.
\24\ E.g., Allegheny Companies, AEP, CAlifornians for Renewable
Energy, Delaware Municipal and Southwestern Electric, E.ON Climate &
Renewables North America, Great River Energy, Sun Flower and Mid-
Kansas, National Nuclear Security Administration Service Center,
Organization of MISO States, and Transmission Agency of Northern
California.
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21. Still other commenters that support Commission action on
transmission planning express concern that current transmission
planning processes do not adequately assess all of the potential
benefits associated with transmission project proposals.\25\ Some of
these commenters state that more attention needs to be devoted to
analyzing the benefits associated with economic-based projects and
incorporating such projects into regional transmission plans.\26\ PJM
states that generic planning principles are needed to deal with the
various social, environmental and economic impacts of regional
transmission projects. In addition, several commenters recommend that
the Commission incorporate State and Federal public policy objectives
into the transmission planning process,\27\ noting, for example, that
doing so could facilitate cost-effective achievement of those
objectives. Commenters also
[[Page 37888]]
recommend that the Commission provide for flexibility so that each
transmission planning region could determine which resources it would
use to fulfill these public policy objectives.\28\
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\25\ E.g., AEP, AWEA, Baltimore Gas and Electric, Energy Future
Coalition, Exelon, Green Energy Express, ITC Holdings, MidAmerican,
National Audubon Society, et al., NextEra, and Public Interest
Organizations & Renewable Energy Groups.
\26\ E.g., MidAmerican and Old Dominion.
\27\ E.g., AWEA, Baltimore Gas and Electric, Exelon, Eastern PJM
Governors, The Brattle Group, ITC Holdings, LS Power, National
Audubon Society, et al., National Grid, NextEra, Old Dominion, PJM,
Public Interest Organizations & Renewable Energy Groups, Renewable
Energy Systems Americas, and Trans-Elect.
\28\ E.g., Consolidated Edison, et al.
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22. The Commission's questions in the October 2009 Notice with
respect to allocating the cost of transmission also drew wide-ranging
responses. For example, some commenters express concern that the lack
of a link between transmission planning and cost allocation procedures
may unnecessarily block or delay needed projects.\29\ Other commenters
support establishing a generic cost allocation method as a backstop
that would apply when parties or transmission planning regions cannot
agree on a cost allocation method.\30\
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\29\ E.g., ITC Holdings, AEP, American Transmission, Green
Energy Express, and WIRES.
\30\ E.g., American Transmission; National Grid; and NEPOOL
Participants.
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23. Some commenters indicate that the Commission should provide
more detailed guidelines or principles for allocating the costs of new
transmission facilities.\31\ These commenters generally agree that
those who share in the benefits of transmission facilities should be
responsible for their costs. However, there is not a consensus on how
this principle should be implemented, what benefits should be
considered for purposes of cost allocation, or how to determine who is
a beneficiary.
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\31\ E.g., APPA, Green Energy Express, ITC Holdings, NEPOOL
Participants, NextEra, Ohio Commission, Solar Energy Industries, and
Transmission Access Policy Study Group.
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24. Some commenters urge the Commission to avoid rushing to a one-
size-fits-all approach to determining beneficiaries of transmission
projects, due to the varying nature of projects and benefits.\32\
Others express the view that it is difficult to quantify certain
benefits that they consider relevant, such as carbon emission
reduction, integration of renewable generation, or the most efficient
use of existing rights-of-way.\33\ Other commenters suggest that there
are ways to factor difficult to quantify benefits into the planning
process such that they are adequately considered.\34\
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\32\ E.g., APPA, Bonneville, California ISO, ColumbiaGrid,
Consolidated Edison, et al., Dayton Power and Light, EEI, Entergy,
Midwest ISO, Southern Companies.
\33\ E.g., California ISO, Electricity Consumers Resource
Council, MidAmerican, National Grid.
\34\ E.g., AWEA, Energy Future Coalition, Entergy, Exelon, ITC
Holdings, Integrys, et al.
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C. Additional Developments Since Issuance of Order No. 890
25. Other developments with important implications for transmission
planning have occurred amid the above-noted Order No. 890 compliance
efforts on transmission planning and as the Commission gathered
information through the technical conferences and the October 2009
Notice discussed above.
26. For example, in February 2009, Congress enacted the American
Recovery and Reinvestment Act (ARRA), which provided $80 million for
the U.S. Department of Energy (DOE), in coordination with the
Commission, to support the development of interconnection-based
transmission plans for the Eastern, Western, and Texas
interconnections. In seeking applications for use of those funds, DOE
described the initiative as intended to: (1) Improve coordination
between electric industry participants and states on the regional,
interregional, and interconnection-wide levels with regard to long-term
electricity policy and planning; (2) provide better quality information
for industry planners and State and Federal policymakers and
regulators, including a portfolio of potential future supply scenarios
and their corresponding transmission requirements; (3) increase
awareness of required long-term transmission investments under various
scenarios, which may encourage parties to resolve cost allocation and
siting issues; and (4) facilitate and accelerate development of
renewable or other low-carbon generation resources.\35\
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\35\ Department of Energy, Recovery Act--Resource Assessment and
Interconnection-Level Transmission Analysis and Planning Funding
Opportunity Announcement, at 5-6 (June 15, 2009).
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27. In December 2009, DOE announced award selections for much of
this ARRA funding. In each interconnection, applicants awarded funds
under what DOE defined as Topic A are responsible for conducting
interconnection-level analysis and transmission planning. Applicants
awarded funds under Topic B are to facilitate greater cooperation among
states and stakeholders within each interconnection to guide the
analyses and planning performed under Topic A.\36\ Broad participation
in sessions to date related to this initiative suggest that the
availability of Federal funds to pursue these goals has increased
awareness of the potential for greater coordination among regions in
transmission planning.
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\36\ Id. at 4-8.
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28. DOE has also been involved in the development of several recent
reports that may have implications for transmission planning. In its
2008 report, 20% Wind Energy by 2030, DOE concludes that
``[s]ignificant expansion of the transmission grid will be required
under any future electric industry scenario. Expanded transmission will
increase reliability, reduce costly congestion and line losses, and
supply access to low-cost remote resources, including renewables.''
\37\
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\37\ Department of Energy, 20% Wind Energy by 2030, at 93 (July
2008).
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29. Similarly, in its 2009 report, Keeping the Lights On in a New
World, the DOE Electricity Advisory Committee concluded that expanding
and strengthening the nation's transmission infrastructure is becoming
increasingly important for two reasons: ``First, increasing
transmission capability will help ensure a reliable electric supply and
provide greater access to economically priced power. Second, the growth
in renewable energy development, stimulated in part by State-adopted
renewable portfolio standards (RPS) and the possibility of a national
RPS, will require significant new transmission to bring these
resources, which are often remotely located, to consumer load
centers.'' \38\
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\38\ Electricity Advisory Committee, Keeping the Lights On in a
New World, at 45 (Jan. 2009). The Electricity Advisory Committee was
formed to provide advice to DOE in implementing the Energy Policy
Act of 2005 and the Energy Independence and Security Act of 2007,
and in modernizing the nation's electricity delivery infrastructure.
The Electricity Advisory Committee includes representatives from
industry, academia, and state government.
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30. The number of states that have adopted renewable portfolio
standard measures, as well as the target levels set in those measures,
has continued to increase. Some 30 states and the District of Columbia
have now adopted renewable portfolio standard measures. These measures
typically require that a certain percentage of energy sales (MWh) or
installed capacity (MW) come from renewable energy resources, with the
target level and qualifying resources varying among the renewable
portfolio standard measures.
31. In its role as the Commission-designated Electric Reliability
Organization, the North American Electric Reliability Corporation
(NERC) concluded that significant transmission expansion will be needed
to comply with renewable mandates. Even in the absence of a national
renewable portfolio standard, NERC has stated that ``an analysis of the
past 14 years shows that the siting and construction of transmission
lines will need to significantly accelerate to maintain reliability
over the coming years.'' \39\ In
[[Page 37889]]
its 2009 assessment of transmission needs, NERC found that if a
national renewable portfolio standard of 15 percent were adopted, an
additional 40,000 miles of transmission lines would be needed and
``transmission would be a key component to accommodating new resources,
linking geographically remote generation to demand centers.'' \40\
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\39\ North American Electric Reliability Corporation, 2009 Long-
Term Reliability Assessment: 2009-2018, October 2009, at 29.
\40\ North American Electric Reliability Corporation, 2009
Scenario Reliability Assessment: 2009-2018, October 2009, at 9.
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III. The Need for Reform
32. The Commission notes that transmission planning processes,
particularly at the regional level, have seen substantial improvement
through compliance with Order No. 890. As noted above, these
improvements have increased opportunities for customers and other
stakeholders to participate in the identification of regional needs and
corresponding solutions, facilitating the development of more efficient
and effective transmission plans. The Commission believes that the
expanded cooperation and collaboration that is now occurring in
transmission planning both among transmission providers and between
transmission providers and their stakeholders is to be commended.
33. Although Order No. 890 became effective just a few years ago,
there have been significant changes in the nation's electric power
industry in those few years that require the Commission to consider
additional reforms to transmission planning and cost allocation to
reflect these new circumstances. These changes have been widely
recognized within the industry.\41\ Our intention in this Proposed Rule
is not to disrupt the progress that is already being made with respect
to transmission planning and investment in transmission infrastructure,
but rather to address remaining deficiencies in transmission planning
and cost allocation processes so that the transmission grid can better
support wholesale power markets and thereby ensure that Commission-
jurisdictional services are provided at rates, terms and conditions
that are just and reasonable and not unduly discriminatory or
preferential.
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\41\ For example, a trend of increased investment in the
country's transmission infrastructure has emerged in recent years.
EEI attributes that trend to, among other factors, recognition of
the reliability and other developments discussed above, as well as
enactment of the Energy Policy Act of 2005 and the Commission's
implementation of its new transmission pricing policies. EEI has
also observed that even amid this trend of increased investment in
transmission infrastructure, transmission projects that would be
located in more than one state ``face significant challenges for
siting, permitting, cost allocation and cost recovery.''
Transmission Projects: At a Glance, Prepared by Edison Electric
Institute with assistance from Navigant Consulting, Inc., February
2010, at iii-iv. EEI has also stated that ``[t]hese challenges must
be resolved to facilitate the movement of large quantities of
renewable energy.'' Transmission Projects Supporting Renewable
Resources, Prepared by Edison Electric Institute, February 2009, at
iv.
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34. The siting, permitting, and cost allocation of transmission
facilities face significant challenges. These challenges may be present
whether an interstate transmission project is proposed to be located
within a single region for which transmission planning is conducted in
accordance with Order No. 890 (i.e., an intraregional transmission
facility) or is instead proposed to be located in more than one such
transmission planning region (i.e., an interregional transmission
facility). The failure to address these challenges also can lead to
increases in congestion costs. For example, PJM stated recently that
prices for new generating capacity in the eastern part of its
transmission planning region have increased due to constraints on its
transmission system. Observing that capacity prices in the western
portion of PJM were $27.73 per megawatt-day, while capacity prices in
the transmission-constrained areas of PJM were between $226.15 and
$247.14 per megawatt-day, PJM noted that ``the great difference in
prices for the eastern portion of PJM compared with elsewhere shows the
need for increased transmission line capacity into the region.
Transmission line additions and upgrades would reduce capacity price
differences.'' \42\
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\42\ PJM Interchange, News Release, May 14, 2010.
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35. In light of the comments and developments discussed above, one
deficiency that has arisen is the lack of a requirement for a regional
transmission plan, without which the construction of new transmission
facilities could be inhibited. Additionally, in the absence of such a
requirement, the facilities best suited to meet the needs of a
particular region may not be identified.
36. Another deficiency that has arisen since the issuance of Order
No. 890 involves transmission needs driven by public policy
requirements established by State or Federal laws or regulations. For
example, State policies to promote increased reliance on renewable
energy resources, such as the renewable portfolio standard measures
discussed above, accentuate the need for transmission to deliver
electricity from location-constrained renewable energy resources to
load centers. Other State policies, such as goals for use of energy
efficiency or demand response, may lower load forecasts within a given
load zone and thereby affect transmission planning determinations. In
addition, states may adopt economic development policies associated
with meeting energy needs that may be relevant to assumptions made in a
transmission planning process. Future public policy requirements
established by Federal laws or regulations also could have a
significant effect on transmission planning.
37. However, existing transmission planning processes generally
were not designed to account for, and do not explicitly consider, these
types of public policy requirements established by State or Federal
laws or regulations. Indeed, some comments submitted in response to the
October 2009 Notice indicate that current transmission planning
processes may not permit consideration of public policy requirements
within regional transmission plans.\43\ As discussed in greater detail
below, the Commission preliminarily finds that the failure to account
explicitly for such public policy requirements in the transmission
planning process may result in undue discrimination and rates, terms,
and conditions of service that are not just and reasonable.
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\43\ E.g., Baltimore Gas and Electric, Eastern PJM Governors,
ITC Holdings, LS Power, National Grid, Old Dominion, PJM, and Trans-
Elect.
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38. A third deficiency involves obstacles to nonincumbent
transmission project developers' participation in regional transmission
planning processes. The Commission in recent years has seen increasing
interest in transmission investment among these developers. Such
interest, however, often has been coupled with expressions of concern
about the treatment of merchant and independent transmission project
developers in relevant transmission planning processes.\44\ Many
commenters raised similar concerns in response to the October 2009
Notice, describing what they see as remaining opportunities for undue
discrimination against nonincumbent transmission project developers in
transmission planning processes. Such undue discrimination could
discourage these developers from presenting projects in regional
transmission planning processes, which, in turn, could inhibit
development of beneficial transmission facilities.
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\44\ See, e.g., Green Energy Express LLC, 129 FERC ] 61,165
(2009); Western Grid Dev., LLC, 130 FERC ] 61,056 (2010); Pioneer
Transmission LLC, 126 FERC ] 61,281 (2009).
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39. A fourth deficiency involves the relative lack of coordination
between transmission planning regions. In Order No. 890, the Commission
found that when transmission providers engage in
[[Page 37890]]
regional transmission planning, they may identify solutions to regional
needs that are more efficient than those that would have been
identified if needs and potential solutions were evaluated only
independently by each individual transmission provider.\45\ Similarly,
in the absence of coordination between transmission planning regions,
transmission providers may not identify more efficient and cost-
effective solutions to the individual needs identified in their
respective utility-level and regional transmission planning processes,
potentially including interregional transmission projects. In the few
years since the issuance of Order No. 890, interest in multiregional
facilities has grown significantly.\46\ The October 2009 Notice
observed that the lack of coordinated planning over the seams of
current transmission planning regions could be needlessly increasing
costs for customers of individual transmission providers. Accordingly,
the Order No. 890 transmission planning requirements may not be just
and reasonable in that they may not be sufficient to address the need
for greater coordination in interregional transmission planning.
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\45\ ``The coordination of planning on a regional basis will
also increase efficiency through the coordination of transmission
upgrades that have region-wide benefits, as opposed to pursuing
transmission expansion on a piecemeal basis.'' Order No. 890, FERC
Stats. & Regs. ] 31,241 at P 524.
\46\ See, e.g., Pioneer Transmission LLC, 126 FERC ] 61,281
(2009); Green Power Express, 127 FERC ] 61,031 (2009).
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40. Finally, we preliminarily conclude that existing methods for
allocating the costs of new transmission may not be just and reasonable
because they may inhibit the development of efficient, cost-effective
transmission facilities necessary to produce just and reasonable rates.
While challenges associated with allocating the cost of transmission
are not new, those challenges appear to have become more acute as the
need for transmission infrastructure has grown. For example, the
expansion of regional power markets and the increasing adoption of
State policies to promote increased reliance on renewable energy
resources have led to a growing need for regional or interregional
transmission facilities. Meanwhile, determining the benefits of adding
transmission infrastructure to the grid is a complex process,
particularly for projects that affect multiple utilities' transmission
systems and therefore may have multiple beneficiaries. In such
circumstances, any individual beneficiary of a project has an incentive
to defer investment in the hopes that other beneficiaries will value
the project enough to fund its development.
41. Moreover, as stated in the October 2009 Notice, constructing
new transmission facilities requires a significant amount of capital.
Therefore, a threshold consideration for any company considering
investing in transmission is whether it will have a reasonable
opportunity to recover its costs. However, there are few rate
structures in place today that provide for the allocation and recovery
of costs for projects that are proposed to be located either within a
transmission planning region that is outside of an RTO or ISO, or in
more than one transmission planning region. The lack of such rate
structures creates significant risk for transmission project developers
that they will have no identified group of customers from which to
recover the cost of their investment.
42. Therefore, the Commission proposes to reform transmission
planning and cost allocation processes as described in the following
sections of this Proposed Rule. Although focused on discrete aspects of
the transmission planning and cost allocation processes, these reforms
are integrally related and should be understood as a package. With
these related reforms, more transmission projects would be considered
in the transmission planning process on an equitable basis, and more
facilities that are included in transmission plans are likely to move
forward to construction.
43. The Commission recognizes that many of the existing regional
transmission planning processes are comprised of both public utility
and non-public utility transmission providers. Consistent with the
approach taken in Order No. 890,\47\ the Commission expects all public
utility and non-public utility transmission providers to participate in
the regional transmission planning and cost allocation processes
proposed by this Proposed Rule. Reciprocity dictates that non-public
utility transmission providers that take advantage of open access,
including improved regional transmission planning and cost allocation,
should be subject to the same requirements as public utility
transmission providers. We are encouraged, based on the efforts that
followed Order No. 890, that both public utility and non-public utility
transmission providers collaborate in a number of regional transmission
planning processes. We therefore do not believe it is necessary at this
time to invoke our authority under FPA section 211A, which allows us to
require non-public utility transmission providers to provide
transmission services on a comparable and not unduly discriminatory or
preferential basis. However, if the Commission finds on the appropriate
record that non-public utility transmission providers are not
participating in the regional transmission planning and cost allocation
processes proposed in this Proposed Rule, the Commission may exercise
its authority under FPA section 211A on a case-by-case basis.
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\47\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 441.
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IV. Proposed Reforms: Transmission Planning
44. Transmission planning is a critical component of the provision
of transmission service in interstate commerce. Among other purposes,
transmission planning is the means by which the transmission needs of a
given area and the facilities that are best suited to meet those needs
are identified. Based on the comments received in response to the
October 2009 Notice and the other developments and considerations
discussed above, the Commission believes that further steps with
respect to transmission planning may be necessary to protect against
unjust and unreasonable rates, terms and conditions and undue
discrimination in the provision of Commission-jurisdictional services.
A. Participation in the Regional Planning Process
45. In Order No. 890, the Commission adopted a regional
participation principle as a necessary component of a public utility
transmission provider's transmission planning process. To meet that
principle, the Commission required that each public utility
transmission provider coordinate with interconnected systems to: (1)
Share system plans to ensure that the plans are simultaneously feasible
and otherwise use consistent assumptions and data; and (2) identify
system enhancements that could relieve congestion or integrate new
resources.\48\ This requirement for coordination at the regional level
can be contrasted with the separate requirement in Order No. 890 that
each public utility transmission provider use an open and transparent
process to develop a transmission plan for its own control area.\49\ In
other words, by adopting the regional participation principle, the
Commission
[[Page 37891]]
did not require development of a comprehensive regional transmission
plan.
---------------------------------------------------------------------------
\48\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 523.
\49\ Id. P 494, 523.
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46. The Commission explained that in complying with the regional
participation principle, the specific features of a public utility
transmission provider's regional transmission planning process should
take account of and accommodate, where appropriate, existing
institutions, as well as historical practices and the physical
characteristics of the region.\50\ The Commission recognized that
regional transmission planning already occurs, for example, as part of
the NERC Regional Entity planning process.\51\ The Commission urged
public utility transmission providers to closely examine whether
improvements in these regional transmission planning processes could be
implemented to satisfy the requirements of Order No. 890 imposed on
individual transmission providers.\52\
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\50\ Id. P 524.
\51\ Id. P 528.
\52\ Id. P 526.
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47. The Commission also stated that to satisfy the regional
participation principle, an existing transmission planning process must
be open and inclusive and address both reliability and economic
considerations.\53\ The Commission required each public utility
transmission provider to participate in a transmission planning process
that facilitates regional participation and that is open to all
interested customers and stakeholders.\54\ However, the Commission did
not require each regional transmission planning process to comply with
each of the nine transmission planning principles established in Order
No. 890.\55\
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\53\ Id. P 528.
\54\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 226.
\55\ See, e.g., Entergy Services, Inc., 124 FERC ] 61,268, at P
104 (2008).
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48. On compliance with these Order No. 890 requirements, many
public utility transmission providers relied on existing regional
entities and transmission planning processes, modified as necessary, to
comply with the regional participation principle.\56\
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\56\ As we note above, the regional transmission planning
processes that public utility transmission providers in regions
outside of RTOs and ISOs have relied on to comply with certain
requirements of Order No. 890 are North Carolina Transmission
Planning Collaborative, Southeast Inter-Regional Participation
Process, SERC Reliability Corporation, ReliabilityFirst Corporation,
Mid-Continent Area Power Pool, Florida Reliability Coordination
Council, WestConnect, ColumbiaGrid, and Northern Tier Transmission
Group.
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49. Since the issuance of Order No. 890, it has become apparent to
the Commission that Order No. 890's regional participation principle
may not be sufficient, in and of itself, to ensure an open,
transparent, inclusive, and comprehensive regional transmission
planning process. Without such a process, each transmission provider
will not have information needed to assess proposed projects and
determine which project or group of projects could satisfy local and
regional needs more efficiently and cost-effectively. As a result, the
rates, terms and conditions of transmission services may not be just
and reasonable. For example, greater regional coordination in
transmission planning would expand opportunities for transmission
providers, their transmission customers, and other stakeholders to
identify and implement regional solutions to local and regional needs
that are more cost-effective than those proposed in the transmission
planning process of individual transmission providers. In addition,
more effective regional transmission planning could better facilitate
the integration of location-constrained renewable energy resources,
which may be needed to fulfill public policy requirements such as the
renewable portfolio standards adopted by many states.
50. Given this concern, we propose to require that each public
utility transmission provider participate in a regional transmission
planning process that produces a regional transmission plan and that
meets the following transmission planning principles established in
Order No. 890: (1) Coordination; (2) openness; (3) transparency; (4)
information exchange; (5) comparability; (6) dispute resolution; and
(7) economic planning studies.\57\
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\57\ This proposal does not include the regional participation
principle and cost allocation for new projects principle of Order
No. 890 because we address interregional coordination in
transmission planning and cost allocation for transmission
facilities included in a regional transmission plan elsewhere in
this Proposed Rule.
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51. More specifically, we propose to require that each regional
transmission planning process consider and evaluate transmission
facilities and other non-transmission solutions that may be proposed
and develop a regional transmission plan that identifies the
transmission facilities that cost-effectively meet the needs of
transmission providers, their transmission customers, and other
stakeholders.\58\ When an individual transmission provider engages in
local transmission planning, it considers and evaluates transmission
facilities and non-transmission solutions that are proposed and then
develops a local transmission plan that identifies what transmission
facilities are needed to meet the needs of its native load (if any),
transmission customers, and other stakeholders. Likewise, the regional
transmission planning process would consider and evaluate transmission
facilities and non-transmission solutions that are proposed and develop
a regional transmission plan that identifies what transmission
facilities are needed to meet the needs of transmission customers and
other stakeholders in the region.\59\
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\58\ When evaluating potential solutions to identified needs,
transmission providers must evaluate proposals for transmission,
generation, and demand resources against one another based on
criteria set forth in their tariffs. See Order No. 890, FERC Stats.
& Regs. ] 31,241 at P 494-95; Order No. 890-A, FERC Stats. & Regs. ]
31,261 at P 216. The Commission also has recognized that in
appropriate circumstances alternative technologies may be eligible
for treatment as transmission for ratemaking purposes. Western Grid,
130 FERC ] 61,056 (2010).
\59\ As noted in Order No. 890, the planning obligations
proposed here do not address or dictate which investments identified
in a transmission plan should be undertaken by transmission
providers. Order No. 890, FERC Stats. & Regs. ] 31,241 at P 438. As
also noted in Order No. 890, the ultimate responsibility for
transmission planning remains with transmission providers. With that
said, the Commission fully intends that the transmission planning
processes provide for the timely and meaningful input and
participation of customers into the development of transmission
plans. Id. P 454.
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52. In addition, because of the increased importance of regional
transmission planning that is designed to produce a regional
transmission plan, transmission customers and other stakeholders must
be provided with an opportunity to participate meaningfully in that
process. Therefore, we propose to apply the above-noted Order No. 890
transmission planning principles to the regional transmission planning
process, which would ensure that transmission customers and other
stakeholders can express their needs before a regional transmission
plan is finalized and thus help to identify solutions that more
efficiently address the region's needs. Similarly, ensuring access to
the models and data used in the regional transmission planning process
would allow transmission customers and other stakeholders to determine
if their needs are being addressed in a cost-effective manner. Greater
access to information and transparency would also help transmission
customers and other stakeholders to recognize and understand the
benefits that they will receive from a transmission facility that is
included in a regional transmission plan. This consideration is
particularly important in light of our proposal below to require that
each public utility transmission provider have a cost allocation method
for transmission
[[Page 37892]]
facilities included in its regional transmission plan that reflects the
benefits that those facilities provide.
53. Although the explicit requirement for a public utility
transmission provider to participate in a regional transmission
planning process that complies with the Order No. 890 transmission
planning principles identified above would be new, we note that the
existing regional transmission planning processes that many utilities
relied upon to comply with the requirements of Order No. 890 may
require only modest changes to fully comply with these requirements.
54. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule.
B. Public Policy Driven Projects
55. In Order No. 890, the Commission included an Economic Planning
Studies principle among the nine transmission planning principles. The
Commission stated that its primary objective in adopting that principle
was ``to ensure that the transmission planning process encompasses more
than reliability considerations.'' \60\ The Commission explained that
although planning to maintain reliability is a critical priority,
transmission planning also involves economic considerations.\61\
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\60\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 542.
\61\ Id.
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56. More specifically, the Commission stated that when conducting
transmission planning to serve native load customers, a prudent
vertically integrated transmission provider will plan not only to
maintain reliability, but also consider whether transmission upgrades
or other investments can reduce the overall costs of serving native
load.\62\ The Commission identified this potential for undue
discrimination among a transmission provider's customers as a
justification to implement the Economic Planning Studies principle
requiring transmission providers to make available to their customers
services that are comparable to those they are performing on behalf of
their native loads.\63\
---------------------------------------------------------------------------
\62\ The Commission further stated that such upgrades could, for
example, reduce congestion (redispatch) costs or integrate efficient
new resources (including demand resources) and new or growing loads.
Id.
\63\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 240.
---------------------------------------------------------------------------
57. The Economic Planning Studies principle requires that
stakeholders be given the right to request a defined number of high
priority studies annually through the transmission planning process. As
defined in Order No. 890, these high priority studies are intended to
identify solutions that could relieve transmission congestion or
integrate new resources and loads, including upgrades to integrate new
resources or loads on an aggregated or regional basis.\64\
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\64\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 547-48.
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58. In Order No. 890, the Commission also required each public
utility transmission provider to coordinate its transmission planning
activities with the relevant State and local regulatory authorities
that choose to participate in the transmission planning process and
stated its expectation that ``all transmission providers will respect
states' concerns.'' \65\ As such, State and local regulatory
authorities may fully participate in the existing Order No. 890
transmission planning process and identify, among other issues, public
policy requirements established by State or Federal laws or regulations
that they see as relevant to transmission needs. However, when choosing
whether to include a proposed transmission project in its local or
regional transmission plan, a public utility transmission provider has
no explicit obligation under Order No. 890 or the pro forma OATT to
evaluate the project based on its potential to facilitate the
achievement of public policy requirements established by State or
Federal laws or regulations.
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\65\ Id. P 574.
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59. The October 2009 Notice observed that some areas are struggling
with how to adequately address transmission expansion necessary to, for
example, integrate renewable generation resources into the transmission
system. The October 2009 Notice attributed these difficulties in part
to the fact that planning transmission facilities necessary to meet
State resource requirements, such as the renewable portfolio standard
measures discussed above, must be integrated with existing transmission
planning processes that are based on metrics or tariff provisions
focused on reliability or in some cases production cost savings.\66\
Drawing on these observations, the October 2009 Notice sought comment
as to whether reliability impact studies are properly aligned with
evaluations of economic-based projects or projects proposed to satisfy
renewable energy standards. To the extent that assessments of various
possible project benefits are not properly aligned, the October 2009
Notice sought comment as to how reliability assessments, economic
evaluations and assessments of a project's ability to meet public
policy goals could be aligned to better identify options that meet all
of these regional needs.\67\
---------------------------------------------------------------------------
\66\ October 2009 Notice at 3.
\67\ Id. at 4.
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60. The Commission received a number of comments on these issues,
expressing a range of opinions. Several commenters argue that the
existing transmission planning and stakeholder processes properly align
reliability impact studies with evaluations of other projects designed
to meet economic-based or public policy requirements.\68\ Other
commenters suggest that it would be inappropriate for the Commission to
require that renewable energy standards be incorporated into the
transmission planning process.\69\ For example, Public Power Council
contends that the Commission lacks jurisdiction to require that the
resources necessary to comply with State renewable energy standards are
accounted for in the transmission planning process, as such standards
are State-level policies.\70\
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\68\ E.g., Dominion, Entergy, Large Public Power Council,
Midwest ISO, New York PSC, Northern Tier Transmission Group,
Southern Companies, WestConnect Planning Parties, and WECC. In
addition, PSEG Companies state that while it is true that
reliability impact studies are performed independently of economic
planning, such a distinction is appropriate because ensuring
reliability is the primary objective of the planning process.
\69\ E.g., Massachusetts Departments and Public Power Council.
\70\ Massachusetts Departments share a similar concern.
---------------------------------------------------------------------------
61. In addition, several commenters recommend that the Commission
incorporate public policy objectives into the transmission planning
process.\71\ For example, PJM argues that ``additional guidance from
the Commission is needed if public policy imperatives such as
aggressive integration of renewable resources are to be met.'' \72\ PJM
states that while ensuring system reliability should remain the primary
goal of the transmission planning process, providing for incorporation
of public policy objectives, where applicable, could facilitate cost-
effective achievement of those objectives. In particular, PJM suggests
that the Commission move beyond a strict application of ``bright line''
criteria currently used for reliability and economic projects and allow
transmission providers more flexibility
[[Page 37893]]
to take into account the multiple reliability, economic, or public
policy-based benefits a single project may be able to provide.\73\
---------------------------------------------------------------------------
\71\ E.g., AWEA, Baltimore Gas and Electric, Public Interest
Organizations & Renewable Energy Groups, Exelon, Eastern PJM
Governors, ITC Holdings, LS Power, National Grid, NextEra, Old
Dominion, PJM, Renewable Energy Systems Americas, Trans-Elect, and
The Brattle Group.
\72\ PJM Order No. 890 Technical Conference Comments, op. cit.
at 6.
\73\ Citing, PJM Interconnection, L.L.C., 119 FERC ] 61,265
(2007) (directing PJM to adopt a formulaic approach to applying
metrics used to choose economic projects).
---------------------------------------------------------------------------
62. Other commenters propose various approaches to incorporating
public policy objectives into the transmission planning process. Some
of these commenters argue that if the goal of the transmission planning
process is to allow load-serving entities to satisfy their resource
needs, such needs could include resources required to comply with State
and Federal public policy objectives.\74\ Still other commenters
recommend that the Commission provide flexibility in the transmission
planning process so that each region can determine which resources it
will use to fulfill any applicable public policy objectives.\75\
---------------------------------------------------------------------------
\74\ E.g., APPA and Bay Area Municipal Transmission Group.
\75\ E.g., Consolidated Edison, et al.
---------------------------------------------------------------------------
63. To ensure that each public utility transmission provider's
transmission planning process supports rates, terms, and conditions of
transmission service in interstate commerce that are just and
reasonable and not unduly discriminatory or preferential, the
Commission preliminarily finds that transmission needs driven by public
policy requirements established by State or Federal laws or regulations
should be taken into account in the transmission planning process.
Indeed, consideration of such public policy requirements raises issues
similar to those raised in the Commission's discussion in Order No. 890
of the Economic Planning Studies principle.\76\ When conducting
transmission planning to serve native load customers, a prudent
transmission provider will not only plan to maintain reliability and
consider whether transmission upgrades or other investments can reduce
the overall costs of serving native load, but also consider how to
enable compliance with relevant public policy requirements established
by State or Federal laws or regulations in a cost-effective manner.
Therefore, we propose to find that, to avoid acting in an unduly
discriminatory manner, a public utility transmission provider must
consider these same needs on behalf of all of its customers. In
addition, providing for incorporation of public policy requirements
established by State or Federal laws or regulations in transmission
planning processes, where applicable, could facilitate cost-effective
achievement of those requirements.
---------------------------------------------------------------------------
\76\ In Order No. 890, the Commission intended the economic
planning studies principle to be sufficiently broad to identify
solutions that could relieve transmission congestion or integrate
new resources and loads, including upgrades to integrate new
resources and loads on an aggregated or regional basis. The
Commission recognizes that its statements with respect to the
economic planning studies principle may have contributed to
confusion as to whether public policy requirements may be considered
in the transmission planning process.
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64. To address these issues, we propose to revise the requirements
established in Order No. 890 with respect to local and regional
transmission planning processes.\77\ Specifically, we propose to
require each public utility transmission provider to amend its OATT
such that its local and regional transmission planning processes
explicitly provide for consideration of public policy requirements
established by State or Federal laws or regulations that may drive
transmission needs. After consulting with stakeholders, a public
utility transmission provider may include in the transmission planning
process additional public policy objectives not specifically required
by State or Federal laws or regulations. This proposed requirement
would be a supplement to, and would not replace, any existing
requirements with respect to consideration of reliability needs and
application of the economic studies principle in the transmission
planning process.
---------------------------------------------------------------------------
\77\ By ``local'' transmission planning process, we mean the
transmission planning process that a pubic utility transmission
provider performs for its individual service territory or footprint
pursuant to the requirements of Order No. 890.
---------------------------------------------------------------------------
65. The Commission does not propose to identify the public policy
requirements established by State or Federal laws or regulations that
must be considered in individual local and regional transmission
planning processes. Instead, we propose to require each public utility
transmission provider to coordinate with its customers and other
stakeholders to identify public policy requirements established by
State or Federal laws or regulations that are appropriate to include in
its local and regional transmission planning processes.
66. We propose to require each public utility transmission provider
to specify in its OATT the procedures and mechanisms in its local and
regional transmission planning processes for evaluating transmission
projects proposed to achieve public policy requirements established by
State or Federal laws or regulations. If a public utility transmission
provider believes that its existing transmission planning processes
satisfy these requirements, then it must make that demonstration in its
compliance filing.
67. This proposed requirement is intended to clarify the objectives
that would be considered in local and regional transmission planning
processes. As we stated in Order No. 890, we believe that the
transparency provided under open transmission planning processes can
provide useful information that would help states to coordinate
transmission and generation siting decisions, allow consideration of
regional resource adequacy requirements, facilitate consideration of
demand response and load management programs at the State level, and
address other factors states wish to consider.
68. Another benefit of this proposed requirement to consider public
policy requirements established by State or Federal laws or regulations
within the transmission planning process is that adherence with this
proposed requirement may eventually increase the proportion of
transmission network investment that is constructed pursuant to
proactive transmission planning processes, thereby reducing the
proportion of network upgrades that would otherwise be triggered by
individual generator interconnection requests, which can be time
consuming and inefficient. If more of the transmission network were
expanded under the type of regional transmission planning process
described above, then the network upgrades triggered by interconnection
requests should be less significant in size and cost than they have
been in the past and the associated differences in cost allocation
provisions may become less significant as well.
69. This proposed requirement is not intended in any way to
infringe upon State authority with respect to integrated resource
planning.\78\ In addition, to the extent that a public utility
transmission provider has an obligation to comply with public policy
requirements established by State or Federal laws or regulations, such
as the State renewable portfolio standard measures discussed above,
this proposed requirement is not intended to convert a failure to
satisfy that obligation into a violation of its OATT. In other words,
while a public utility transmission provider would be required to
identify and consider public policy requirements established by State
or Federal laws or regulations in its local and regional transmission
planning processes, this proposed requirement would not establish an
[[Page 37894]]
independent obligation to satisfy those requirements.
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\78\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 479,
n.274.
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70. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule. In
particular, we seek comment as to whether public policy requirements
established by State or Federal laws or regulations should be
considered in the transmission planning process. Further, we seek
comment on how planning criteria based on public policy requirements
should be formulated, including whether it is more appropriate to use
flexible criteria instead of ``bright line'' metrics when determining
which projects are to be included in the regional transmission plan,
whether the use of flexible criteria would provide undue discretion as
to whether a project is included in a regional transmission plan, and
whether the use of ``bright line'' metrics may inappropriately result
in alternating inclusion and exclusion of a single project over
successive planning cycles and therefore create inappropriate
disruptions in long-term transmission planning.
C. Opportunities for Undue Discrimination Against Nonincumbent
Transmission Developers
1. Nonincumbent Transmission Developer Participation in the
Transmission Planning Process
71. As discussed above, Order No. 890 sought to reduce
opportunities for undue discrimination and preference in the provision
of transmission service. With regard to the transmission planning
process, the Commission established nine transmission planning
principles to prevent undue discrimination. However, Order No. 890 did
not specifically address the potential for undue preference to
incumbent utilities over nonincumbent transmission developers through
practices applied within transmission planning processes.
72. The October 2009 Notice observed that in some areas, when a
nonincumbent transmission developer participates in the transmission
planning process, it may lose the opportunity to construct its proposed
project to the incumbent transmission owner if that owner has a right
of first refusal to construct any transmission facility in its service
territory. The October 2009 Notice also observed that in some areas,
merchant transmission developers choose to plan proposed facilities
outside of the transmission providers' planning processes.\79\
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\79\ October 2009 Notice at 3.
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73. The October 2009 Notice posed several questions relating to
merchant and independent transmission developers' participation in the
regional transmission planning process. The October 2009 Notice sought
comment on how projects proposed by merchant or independent
transmission developers should be treated in the regional transmission
planning process. The October 2009 Notice also asked whether these
types of developers should be required to participate in the regional
transmission planning process and, if so, at what point they should be
required to engage in that process. In addition, the October 2009
Notice asked whether the right of first refusal for incumbent
transmission owners unreasonably impedes the development of merchant
and independent transmission and, if so, how that impediment could be
addressed. Finally, the October 2009 Notice asked whether there are
barriers to merchant and independent transmission developers'
participation in the regional transmission planning process other than
rights of first refusal.\80\
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\80\ Id. at 4.
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74. These questions generated extensive comments. For example, many
commenters argue that a project proposed by a merchant or independent
transmission developer should be treated on the same basis as all other
proposed projects.\81\ Also, a number of commenters assert that
merchant and independent developers should be required to participate
in the transmission planning process.\82\ For example, Southern
Companies asserts that it would be discriminatory if the Commission did
not require merchant and independent developers to participate in the
transmission planning process, as jurisdictional and non-jurisdictional
transmission providers are required to do.
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\81\ E.g., Allegheny Companies, AEP, CAlifornians for Renewable
Energy, Delaware Municipal and Southwestern Electric, E.ON Climate &
Renewables North America, Great River Energy, Sun Flower and Mid-
Kansas, National Nuclear Security Administration Service Center,
Organization of MISO States, and Transmission Agency of Northern
California.
\82\ E.g., APPA, CAlifornians for Renewable Energy, Delaware
Municipal and Southwestern Electric, Dominion, Exelon, Integrys, Old
Dominion, Sun Flower and Mid-Kansas, Large Public Power Council,
Midwest ISO, National Nuclear Security Administration Service
Center, National Rural Electric Coops, New England States' Committee
on Electricity, New York PSC, Organization of MISO States, Pacific
Gas and Electric, Ohio Commission, SPP, San Diego Gas & Electric,
South Carolina Electric & Gas, Transmission Access Policy Study
Group, Transmission Agency of Northern California, Transmission
Dependent Utility Systems, and Xcel.
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75. Other commenters state that merchant and independent developers
should not be treated similarly or required to participate in the
transmission planning process. For example, Chinook and Zephyr and ITC
Holdings state that because the business model of merchant and
independent transmission developers is different from that of
vertically-integrated utilities, different transmission planning
requirements are appropriate for them. Chinook and Zephyr also argue
that regional transmission planning requirements should apply to a
merchant developer only after it is operating under a Commission-
approved OATT. Dayton Power and Light contends that while any
transmission facility that is necessary to meet NERC reliability
criteria, regardless of ownership, should be required to be included in
the transmission planning process, merchant and independent projects
planned for nonreliability reasons can be developed independently of
the transmission planning process, subject to appropriate
interconnection requirements.
76. Other commenters emphasize the importance of allowing merchant
and independent developers to participate actively in the transmission
planning process.\83\ Generally, these commenters argue that merchant
and independent transmission developers should either participate in
the transmission planning process as early as practical, at the
beginning of the transmission planning cycle, or as soon as they have a
proposal that is developed well enough to be considered. Pattern
Transmission also suggests that the Commission should better define the
transmission planning process and the roles of its participants to
ensure a level playing field for independent transmission developers.
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\83\ E.g., Green Energy Express, ITC Holdings, Pattern
Transmission, and Starwood.
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77. The questions about whether an incumbent transmission owner's
right of first refusal unreasonably impedes merchant or independent
transmission development and, if so, how this impediment could be
addressed, also generated extensive comments. Many commenters state
that a right of first refusal does not unreasonably impede merchant and
independent transmission development.\84\ Various commenters
[[Page 37895]]
present a range of reasons that it is appropriate for an incumbent
transmission provider to have a right of first refusal, including that
the incumbent transmission owner: (1) Has a legally enforceable
obligation to maintain reliability on its systems and faces penalties
for noncompliance; (2) is obligated under State law to provide reliable
service at the lowest reasonable cost; (3) may be required to build
facilities included in an RTO's or ISO's regional plan, an obligation
that merchant and independent transmission developers lack; (4) is best
situated to develop transmission facilities within its service
territory, as it is most familiar with the design and operation of its
system, its customers' needs, and State and local permitting and siting
processes; and (5) may be able to provide transmission services at a
lower cost than a merchant or independent transmission developer
because it enjoys economies of scale with respect to the staff and
resources necessary to maintain and operate new transmission
facilities.
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\84\ E.g., Allegheny Companies, AEP, Ameren, Baltimore Gas and
Electric, Dominion, EEI, Great River Energy, Integrys, et al., Sun
Flower and Mid-Kansas, Large Public Power Council, MidAmerican,
Midwest ISO Transmission Owners, National Grid, Northern Tier
Transmission Group, Old Dominion, PPL, PSEG Companies, Ohio
Commission, San Diego Gas & Electric, Southern California Edison,
Southern Companies, WestConnect Planning Parties, and Xcel. However,
Old Dominion suggests that the Commission could eliminate the right
of first refusal if merchant and independent transmission developers
were subject to the same rules and had the same responsibilities as
incumbent transmission owners, and could recover their costs through
the RTO/ISO tariff.
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78. Some commenters contend that the right of first refusal should
be preserved because an incumbent transmission owner that voluntarily
joined an RTO or ISO did so with the understanding that it would retain
the right to invest in and earn a return on new facilities within its
system.\85\ According to Midwest ISO Transmission Owners, eliminating a
right of first refusal could provide a disincentive for RTO membership.
Similarly, the California ISO asserts that without a right of first
refusal, a transmission owner may have less incentive to participate in
an RTO or ISO.
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\85\ E.g., Ameren, MidAmerican, and Midwest ISO Transmission
Owners.
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79. However, other commenters argue that a right of first refusal
impedes transmission development and provides an undue advantage to an
incumbent transmission owner.\86\ Such commenters present a number of
reasons for eliminating a right of first refusal, including the
following: (1) A right of first refusal provides a disincentive for a
merchant or independent developer to propose a project, especially a
proposal for a transmission facility that spans multiple utilities'
service territories, because any investment that it makes in developing
a proposal may be lost if an incumbent transmission owner can exercise
its right of first refusal or otherwise delay the project or prevent
construction of the project; (2) by discouraging competition and new
entry, a right of first refusal likely increases costs to ratepayers;
and (3) a merchant or independent transmission developer may have
difficulty obtaining financing if investors perceive that its proposed
project could be subject to a right of first refusal or is otherwise at
a disadvantage compared to a project sponsored by an incumbent
transmission owner.
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\86\ E.g., American Forest and Paper, AWEA, CAlifornians for
Renewable Energy, EPSA, Indicated Partners, Modesto Irrigation
District, NationalWind, NextEra, Renewable Energy Systems Americas,
Startrans, Starwood, Transmission Access Policy Study Group,
Transmission Agency of Northern California, and Transmission
Dependent Utility Systems.
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80. Among other comments on this issue, Startrans claims that for
an incumbent transmission owner, a Commission-approved right of first
refusal effectively creates a Federal franchise for transmission
development derived from a State franchise for retail electricity.
Transmission Agency of Northern California contends that a right of
first refusal also may ``diminish the incentive for the incumbent
utilities to conceive projects in their own service territory.'' \87\
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\87\ Transmission Agency of Northern California at 3.
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81. Responding to arguments in favor of a right of first refusal,
some commenters argue that concerns about the reliability of a merchant
or independent transmission developer's project are unfounded, as the
merchant or independent transmission developer will be subject to NERC
reliability standards and to the same penalties for noncompliance as an
incumbent transmission owner.\88\ Pattern Transmission states that a
merchant or independent developer has a financial incentive to
construct and operate facilities safely and reliably in accordance with
all applicable regulatory and industry standards, as its investment is
at risk if it does otherwise. With regard to an incumbent transmission
owner's obligation to build, some commenters assert that it is not a
burden, but rather a privilege, as the incumbent transmission owner is
assured the opportunity to recover its costs and earn a return on its
investment through the rate base. These commenters argue that a
merchant or independent developer would be willing to compete for such
an obligation.\89\ In response to concerns that a merchant or
independent developer would submit an inaccurately low bid to construct
a proposed transmission facility, some commenters claim that such a
developer is no more likely to do so than an incumbent transmission
owner.\90\ These same commenters argue that, contrary to what some
commenters assert, an incumbent transmission owner will not leave an
RTO or ISO if the right of first refusal is eliminated.
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\88\ E.g., Green Energy Express and Pattern Transmission.
\89\ E.g., Indicated Partners and Startrans.
\90\ E.g., Indicated Partners.
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82. While some commenters advocate elimination of all rights of
first refusal, other commenters support more limited restrictions. For
example, Exelon states that ``where an independent developer bids on
transmission expansion that is justified under existing planning
criteria and will be included in rate base, the incumbent transmission
owner should be required to match the bid to invoke its right of first
refusal.'' \91\ Several commenters argue that a right of first refusal
should be allowed for reliability-based projects, but may not be
necessary for economic-based or other projects.\92\ While AWEA and LS
Power both maintain that the right of first refusal should be
eliminated, they contend that if the right of first refusal is
preserved then those practices should apply only to local reliability
projects. Moreover, AWEA asserts that a right of first refusal should
be required to be exercised within ninety days. Similarly, ITC Holdings
contends that a right of first refusal will continue to impede
transmission development if the time for exercising it is allowed to
continue indefinitely, and Pacific Gas and Electric argues that any
right of first refusal should be exercised in a timely manner.
Transmission Access Policy Study Group, however, states that the
Commission may need to take other steps in addressing this issue in
addition to limiting the time in which a right of first refusal may be
exercised. In addition, several commenters contend that placing
restrictions on a right of first refusal makes the practice no less
discriminatory.\93\
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\91\ Exelon at 12.
\92\ E.g., Allegheny Companies, Dominion, Large Public Power
Council, and SPP.
\93\ E.g., Indicated Partners.
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83. EEI argues that while ``in general, applicability of a right of
first refusal does not create an impediment to transmission planning or
development'' and that in many cases, ``incumbent transmission owners
are better situated to build needed transmission within their
franchised service territories,'' if
[[Page 37896]]
the Commission finds it necessary to address the exercise of a right of
first refusal, it should do so on a case-specific basis.\94\ Similarly,
the California ISO recommends that the Commission allow the right of
first refusal to be addressed through individual RTO and ISO
stakeholder processes, rather than adopting generic right of first
refusal regulations. Pacific Gas and Electric states that this
proceeding should not preempt the California ISO's development of a
right of first refusal proposal. In contrast, SPP states that
additional clarification and a generally applicable policy regarding
the right of first refusal is necessary. The Organization of MISO
States argues that, while a right of first refusal may limit
competition, any modifications must recognize various State regulatory
structures and respect State jurisdiction and statutes. The Alabama PSC
argues that the Commission should adopt policies that encourage
merchant transmission development only if the State commissions in a
region support such policies.
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\94\ EEI at 9-10.
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84. In response to the question in the October 2009 Notice
regarding barriers to merchant and independent transmission developers'
participation in the regional transmission planning process other than
a right of first refusal, several commenters state that there are none
or that they are unaware of any.\95\ However, Pattern Transmission
suggests that the uncertainty of recovering the costs associated with
participation in the transmission planning process can be a barrier to
participation by merchant and independent transmission developers,
particularly if the planning process is inefficient and deadlines are
not met. Pattern Transmission also asserts that an incumbent
transmission owner has an advantage in developing proposals as it has
priority access to data. Green Energy Express states that the
Commission should ensure ``a level playing field with regard to the
flow of information, the determination of need, and related
interactions between an RTO or ISO or other transmission planning
region, incumbent transmission owners and developers, and independent,
nonincumbent developers.'' \96\
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\95\ E.g., Allegheny Companies, CAlifornians for Renewable
Energy, Integrys, et al., Maine PUC and Public Advocate, New York
PSC, and Xcel.
\96\ Green Energy Express at 10.
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85. LS Power states that there are several additional barriers to
third party developers' participation in regional transmission planning
processes, some of which are unique to certain markets. For example, LS
Power states that there are regions in which an independent developer
cannot become a transmission owner until it has completed a project and
owns the resulting transmission facility. Additionally, LS Power states
that it is difficult to develop a project in a region where the load-
serving entity is also a transmission owner, as the incumbent utility
is often responsible for both generation and transmission planning and
resource procurement and may have an incentive to expand its rate base
by investing in transmission infrastructure rather than support
independent transmission development.
86. Northern Tier Transmission Group suggests that some merchant
transmission developers self-impose a barrier to successful
participation in the transmission planning process in that they do not
submit comparable planning data. As such, Northern Tier Transmission
Group is unable to include their projects in its analytical studies.
2. Proposed Reforms Regarding Nonincumbents
87. Based on the comments submitted in response to the October 2009
Notice, there appear to be opportunities for undue discrimination and
preferential treatment against nonincumbent transmission developers
within existing regional transmission planning processes. Where an
incumbent transmission provider has a right of first refusal, a
nonincumbent transmission developer risks losing its investment in
developing a proposal for submittal to the regional transmission
planning process, even if that proposal is selected for inclusion in
the regional transmission plan. We are concerned that it may be unduly
discriminatory or preferential to deny a nonincumbent transmission
developer that sponsors a project that is included in a regional
transmission plan the rights of an incumbent transmission provider that
are created by a transmission provider's OATT or agreements subject to
the Commission jurisdiction.
88. In addition, under these circumstances, nonincumbent
transmission developers may be less likely to participate in the
regional transmission planning process. If the regional transmission
planning process does not consider and evaluate projects proposed by
nonincumbents, it cannot meet the principle of being ``open.''
Moreover, such a planning process may not result in a cost-effective
solution to regional transmission needs and projects that are included
in a transmission plan therefore may be developed at a higher cost than
necessary. The result may be that regional transmission services may be
provided at rates, terms and conditions that are not just and
reasonable.
89. To address these issues, we propose a framework that reflects
the following reforms, including the elimination from a transmission
provider's OATT or agreements subject to the Commission's jurisdiction
of provisions that establish a Federal right of first refusal for an
incumbent transmission provider with respect to facilities that are
included in a regional transmission plan. Neither incumbent nor
nonincumbent transmission facility developers should, as a result of a
Commission-approved OATT or agreement, receive different treatment in a
regional transmission planning process. Further, both should share
similar benefits and obligations commensurate with that participation,
including the right, consistent with State or local laws or
regulations, to construct and own a facility that it sponsors in a
regional transmission planning process and that is selected for
inclusion in the regional transmission plan. The Commission proposes
that the tariff changes to implement these proposed reforms would be
developed through an open and transparent process involving the public
utility transmission provider, its customers, and other stakeholders.
90. First, we propose to require that each public utility
transmission provider must revise its OATT to demonstrate that the
regional transmission planning process in which it participates has
established appropriate qualification criteria for determining an
entity's eligibility to propose a project in the regional transmission
planning process, whether that entity is an incumbent transmission
owner or a nonincumbent transmission developer. These criteria must be
included in the public utility transmission provider's OATT and must
not be unduly discriminatory or preferential. However, it would not be
unduly discriminatory or preferential to have appropriate qualification
criteria for all potential transmission owners. Such criteria should be
designed to demonstrate that each potential transmission owner has the
necessary financial and technical expertise to develop, construct, own,
operate, and maintain transmission facilities.\97\ Any such criteria
must be approved by the Commission. Although we do not
[[Page 37897]]
propose here to establish a single set of qualification criteria that
would apply in all regional transmission planning processes, we seek
comment on whether we should do so and if so, what these criteria
should be. Instead, we propose that each public utility transmission
provider, in cooperation with customers and other stakeholders in its
transmission planning region, must participate in a regional
transmission planning process that develops qualification criteria that
satisfy the requirements of this Proposed Rule.
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\97\ Nothing would preclude the incumbent transmission owner
from agreeing to operate and maintain the facilities. Additionally,
nothing in this Proposed Rule is intended to change existing RTO and
ISO operational procedures and practices.
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91. Second, we propose to require that each public utility
transmission provider must revise its OATT to include a form by which a
prospective project sponsor would provide information in sufficient
detail to allow the proposed project to be evaluated in the regional
transmission planning process.\98\ In connection with the other aspects
of the framework discussed in this section, we also propose to require
that all proposals to be considered in a given transmission planning
cycle must be submitted by a single, specified date, to minimize the
opportunity for other entities to propose slight modifications to
already submitted projects.
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\98\ The information about its proposed project that a sponsor
provides also should include, as relevant, engineering studies, cost
analyses, and any other detailed reports completed by the project
sponsor as needed to facilitate evaluation of the project in the
regional transmission planning process.
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92. Third, we propose to require that each public utility
transmission provider participate in a regional transmission planning
process that evaluates the proposals submitted to the regional planning
process through a transparent and not unduly discriminatory or
preferential process. Each public utility transmission provider would
be required to describe in its OATT the process used for evaluating
whether to include a proposed transmission facility in the regional
transmission plan.\99\
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\99\ The description would need to provide sufficient detail so
that an entity that proposed a project could determine why the
project was included or not included in the regional transmission
plan. In addition to addressing concerns about undue discrimination
or preference, the description would facilitate understanding of the
relative weight placed on various benefits associated with competing
proposals (e.g., one proposal might address only a reliability-
driven transmission need, while another proposal might also provide
greater benefits in terms of congestion relief or advancement of
public policy requirement established by State or Federal laws or
regulations that a transmission planning region has identified).
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93. Fourth, with respect to facilities that are included in a
regional transmission plan, we propose to require removal from a
transmission provider's OATT or agreements subject to the Commission's
jurisdiction provisions that establish a Federal right of first refusal
for an incumbent transmission provider.\100\ We also propose to require
each public utility transmission provider to amend its OATT to describe
how the regional transmission planning process in which it participates
provides for the sponsor (whether an incumbent transmission provider or
a nonincumbent transmission developer) of a facility that is selected
through the regional transmission planning process for inclusion in the
regional transmission plan to have a right, consistent with State or
local laws or regulations, to construct and own that facility.
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\100\ If a Commission-approved tariff or agreement contains a
reference to a right provided under state or local laws or
regulations, such a provision would not be subject to this
requirement.
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94. Moreover, because a regional transmission planning process may
result in modifications to proposed projects in order to better meet
the needs of the region, the public utility transmission provider must
ensure that its regional transmission planning process has a mechanism
to determine which proposal the modified project is most similar to,
with the sponsor of the most similar project having the right,
consistent with State or local laws or regulations to construct and own
the facilities.
95. Fifth, we propose to require that if a proposed project is not
included in a regional transmission plan and if the project's sponsor
resubmits that proposed project in a future transmission planning
cycle, that sponsor would have the right to develop that project under
the foregoing rules even if one or more substantially similar projects
are proposed by others in the future transmission planning cycle. The
OATT must state that this priority to develop the proposed facility
continues for a defined period of time (e.g., for resubmission annually
in subsequent transmission planning cycles over a 5-year period).
96. Sixth, we propose to require that, if an incumbent transmission
project developer may recover the cost of a transmission facility for a
selected project through a regional cost allocation method, a
nonincumbent transmission project developer must enjoy that same
eligibility. More specifically, each public utility transmission
provider must participate in a regional planning process that provides
that, when a project proposed by a nonincumbent transmission developer
is included in a regional transmission plan, that developer must have
an opportunity comparable to that of an incumbent transmission owner to
recover the costs associated with developing the project and
constructing the transmission facility. Costs associated with a project
that is not included in the regional transmission plan, whether
proposed by an incumbent or by a nonincumbent transmission provider,
may not be recovered through a transmission planning region's cost
allocation process.
97. We emphasize that these proposed reforms would apply only to
facilities that are evaluated in a regional transmission planning
process and selected for inclusion in a regional transmission plan. We
do not propose to modify any existing obligation for an incumbent
transmission owner to build unsponsored projects that are identified as
necessary in a regional transmission plan.\101\ In addition, where an
incumbent transmission owner has the right to build, own, and recover
costs for upgrades to its own existing transmission facilities (e.g.,
tower change out and reconductoring), such right would not be affected
by the reforms proposed here.
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\101\ For example, in some RTO and ISO regions, transmission
owners have obligations to build certain transmission facilities
identified by the RTO or ISO. As new transmission owners, including
nonincumbent transmission owners, join the RTO or ISO, they will
incur the obligations accompanying that status in the RTO or ISO's
tariff and other governing documents. We note that provisions
imposing such obligations may need to be modified to reflect how
they will apply to nonincumbent transmission project developers. We
also note that before turning to a transmission owner with such an
obligation, the RTO or ISO could conduct a competitive bidding
process to assign construction rights for an unsponsored project in
its regional transmission plan.
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98. We also emphasize that these proposed reforms would affect only
a right of first refusal established in a transmission provider's OATT
or agreements subject to the Commission's jurisdiction. This Proposed
Rule does not address, propose to change, or seek to preempt any State
or local laws or regulations.
99. Finally, we do not propose here to require a transmission
developer that does not seek to use the regional cost allocation
process to participate in the regional transmission planning process,
as some commenters recommend. For example, because a merchant
transmission developer assumes all financial risk for developing its
project and constructing the proposed facilities, it is unnecessary to
require such a developer to participate in a regional transmission
planning process for purposes of identifying the beneficiaries of its
project or securing eligibility to use a regional cost allocation
method. A
[[Page 37898]]
developer that does not seek to use the regional cost allocation
process nevertheless would be required to comply with all reliability
requirements applicable to facilities in the transmission planning
region in which its project would be located. In addition, such a
developer is not prohibited from participating--and, indeed, is
encouraged to participate--in the regional transmission planning
process.
100. As discussed above, in response to the October 2009 Notice,
many commenters link the right of first refusal for an incumbent
utility to its obligation to construct new facilities if called upon to
do so. While the Commission acknowledges these comments, we
preliminarily find that these two practices are not, and should not be,
linked within regional transmission planning processes. That is, while
a public utility transmission owner may have accepted an obligation to
build in relation to its membership in an RTO or ISO, this obligation
is not directly dependent on that transmission provider having a
corresponding right of first refusal with regard to a proposal to
construct and own a new transmission facility located in that region.
What is important from the Commission's perspective is that the
documents approved by the Commission must not be unduly discriminatory.
The Commission preliminarily finds that neither incumbent nor
nonincumbent transmission facility developers should, as a result of a
Commission approved OATT or agreement, receive different treatment in
the transmission planning and selection process, and both should share
similar benefits and obligations commensurate with that participation.
101. We seek comment on how the reforms proposed in this section of
the Proposed Rule would affect the rights, obligations, and
responsibilities of incumbent and nonincumbent transmission providers.
In particular, we seek comment on the relationship or lack of
relationship between a right of first refusal and an obligation to
build. We also seek comment on whether it would be appropriate to
retain a Federal right of first refusal in an OATT or other documents
subject to the Commission's jurisdiction. If not, why not? If so, would
it be appropriate to retain an obligation to build for an incumbent
transmission provider while removing a Federal right of first refusal
for that incumbent?
D. Interregional Coordination
1. The Need for Interregional Planning Reforms
102. As discussed above, the transmission planning principles
established in Order Nos. 890 and 890-A establish a framework for
transmission planning at the local and regional levels. In Order No.
890-A, the Commission emphasized that effective regional planning
should include coordination among regions. Further, the Commission
stated that regions and subregions should coordinate as necessary to
share data, information and assumptions to maintain reliability and
allow customers to consider the resource options that span the
regions.\102\ In several of the Order No. 890 compliance orders, the
Commission requested more detailed information regarding compliance
with this aspect of the regional participation principle.\103\
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\102\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 226.
\103\ See, e.g., Southern Co. Servs., Inc.; 124 FERC ] 61,265,
at P 70 (2008); United States Department of Energy--Bonneville Power
Administration, 124 FERC ] 61,054, at P 65 (2008); Southwest Power
Pool, Inc., 124 FERC ] 61,028, at P 49 (2008).
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103. Within that Order No. 890 and 890-A framework, transmission
providers in certain parts of the country have organized subregional
transmission planning groups for the purpose of collectively developing
plans for upgrades on their combined transmission systems. These
subregional transmission plans are then analyzed at a regional level to
ensure that, if implemented, they will be simultaneously feasible and
meet reliability requirements.\104\ Additionally, some neighboring
transmission providers have undertaken joint transmission planning
pursuant to bilateral agreements.\105\ However, as observed in the
October 2009 Notice, there are few processes in place to analyze
whether alternative interregional solutions would more efficiently or
effectively meet the needs identified in individual regional
transmission plans.\106\
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\104\ Such analysis is consistent with one aspect of the
Regional Participation transmission planning principle that the
Commission established in Order No. 890. On that issue, the
Commission stated: ``[I]n addition to preparing a system plan for
its own control area on an open and nondiscriminatory basis, each
transmission provider will be required to coordinate with
interconnected systems to: (1) Share system plans to ensure that
they are simultaneously feasible and otherwise use consistent
assumptions and data, and (2) identify system enhancements that
could relieve congestion of integrate new resources * * *'' Order
No. 890, FERC Stats. & Regs. ] 31,241 at P 523.
\105\ See, e.g., Joint Operating Agreement Between the Midwest
Independent Transmission System Operator, Inc. and PJM
Interconnection, L.L.C. (Midwest Independent Transmission System
Operator, Inc., Second Revised Rate Schedule FERC No. 5; PJM
Interconnection, L.L.C. Second Revised Rate Schedule FERC No. 38).
\106\ October 2009 Notice at 2.
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104. The October 2009 Notice posed several questions related to
this issue, including whether existing transmission planning processes
are adequate to identify and evaluate potential solutions to needs
affecting the systems of multiple transmission providers. The October
2009 Notice also sought comment as to what processes should govern the
identification and selection of projects that affect multiple
systems.\107\
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\107\ Id. at 3.
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105. In response to the October 2009 Notice, some commenters state
that the need for supplemental interregional transmission planning
processes cannot be evaluated until stakeholders gain more experience
with the regional transmission planning processes conducted pursuant to
Order No. 890, and thus oppose Commission action on this issue at this
time.\108\ Other commenters state that the lack of interregional
planning is a considerable problem and that transmission planning could
be enhanced by increasing the amount of coordination that occurs
between neighboring transmission planning regions.\109\
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\108\ E.g., American Transmission, Consolidated Edison, et al.,
Dominion, Eastern Interconnection Planning Collaborative Analysis
Team, Imperial Irrigation District, New York ISO, Public Power
Council, South Carolina Electric & Gas, and Southern Companies.
\109\ E.g., Duke, Exelon, NextEra, Ohio Commission, Old
Dominion, Organization of MISO States, PSEG Companies, Transmission
Access Policy Study Group, and Transmission Dependent Utility
Systems.
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106. More specifically, several commenters advocate expansion of
interregional transmission planning, but disagree as to the extent to
which interregional coordination should be institutionalized. Proposals
range from requiring regional transmission planning entities to comply
with Order No. 890 transmission planning principles,\110\ to requiring
greater coordination among existing transmission planning regions,\111\
to expanding the authorities of regional transmission planning
entities.\112\ Some
[[Page 37899]]
commenters suggest that the Commission should require interregional
transmission planning or develop pro forma seams agreements that
describe the requirements for coordinating transmission planning with a
neighboring transmission planning region.\113\
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\110\ E.g., Old Dominion.
\111\ E.g., AWEA, Pioneer Transmission, PSEG Companies, Public
Interest Organizations & Renewable Energy Groups, Transmission
Access Policy Study Group, and Transmission Dependent Utility
Systems.
\112\ Regional transmission planning entities would be empowered
``to make specific project recommendations at the end of the
planning process and to enter binding, near-juridical findings of
fact and conclusions related to the need and economic benefits of
specific projects or solutions.'' San Diego Gas & Electric at 6.
\113\ E.g., AEP, Energy Future Coalition, Old Dominion, Pioneer
Transmission, Public Interest Organizations & Renewable Energy
Groups, SPP, Transmission Access Policy Study Group, and
Transmission Dependent Utility Systems.
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107. San Diego Gas & Electric, for example, states that, in the
West, transmission planning is a hodgepodge of balkanized processes
resulting in a flood of proposed interstate transmission facilities but
with virtually no consideration given to which of the proposed
facilities would be most effective in meeting the needs of the broadest
set of constituents. San Diego Gas & Electric also states that little
serious consideration is given to how various project proposals could
be modified, combined, or eliminated so as to make the best possible
use of available transmission corridors, minimize adverse environmental
impacts, and enhance overarching system efficiencies.\114\
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\114\ San Diego Gas & Electric at 5.
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108. Pioneer Transmission states that it has a unique perspective
on interregional transmission planning issues, as it spent the last
year and a half working with the Midwest ISO and PJM in an effort to
develop extra high voltage transmission facilities that will be located
in both the Midwest ISO and PJM footprints. Pioneer Transmission states
that although the Midwest ISO and PJM have undertaken various studies
and have worked cooperatively with Pioneer Transmission, they have been
hampered in their efforts to assess the Pioneer project for inclusion
in their transmission plans because neither RTO has in place formal
procedures for evaluating interregional projects.\115\
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\115\ Pioneer Transmission at 1-2.
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109. The Ohio Commission states in its comments that ``[j]ust as
the development of RTOs and ISOs was encouraged to better coordinate
individual transmission owners' and operators' plans, the development
of inter-regional planning committees to review and coordinate
individual and RTO and ISO plans should be encouraged.'' \116\ The
California ISO states that it would be easier to analyze and justify
transmission facilities that would be located in more than one region
if the underlying data were consistent in all of the areas that are
part of evaluating the transmission project in question.\117\
Similarly, Public Interest Organizations & Renewable Energy Groups
state that the Commission should require coordinated transmission
infrastructure plan development by regional or interregional
transmission planning authorities informed by interconnection-wide
assessments and broad stakeholder input.
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\116\ Ohio Commission Comments at 6.
\117\ California ISO at 8.
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110. The October 2009 Notice also recognized that proposals to
implement interconnectionwide transmission planning were being
developed in response to the above-noted funding opportunities that DOE
offered under the American Recovery and Reinvestment Act of 2009. The
October 2009 Notice observed that it was not clear whether those
activities would result in a regular process for jointly identifying
and evaluating alternatives to solutions identified in transmission
plans developed through existing transmission planning processes
conducted in accordance with Order No. 890.\118\
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\118\ October 2009 Notice at 2-3.
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111. In response to the October 2009 Notice, some commenters state
that interconnectionwide transmission planning undertaken pursuant to
the ARRA should be given a chance to mature before the Commission takes
additional action with respect to transmission planning.\119\ Other
commenters emphasize that funding under the ARRA is an important one-
time opportunity, but should not be viewed as a prerequisite for
initiating or expanding upon other transmission planning efforts.\120\
For example, Exelon states that the ARRA-funded transmission planning
for the Eastern Interconnection is a positive effort, but is aimed at
evaluating what would happen under various scenarios rather than at
evaluating solutions and identifying the best solution for any given
transmission planning problem. AWEA states that the Commission should
not rely on interconnectionwide transmission planning undertaken
pursuant to the ARRA as the sole means for reforming the transmission
planning process because the ARRA-funded efforts cannot be expected to
lead to the near-term changes that need to be implemented in order to
support development of renewable energy resources.
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\119\ E.g., ColumbiaGrid, NARUC, New England States' Committee
on Electricity, and Organization of MISO States.
\120\ E.g., Eastern Interconnection Planning Collaborative
Analysis Team, Entergy, and Progress Energy.
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112. The Commission supports and encourages the interconnectionwide
transmission planning efforts being undertaken pursuant to the ARRA. As
noted above, broad participation in sessions to date related to these
efforts suggests that that the availability of Federal funds to pursue
interconnectionwide transmission planning has increased awareness of
the potential for greater coordination among regions in transmission
planning. The Commission anticipates that the ARRA-funded efforts will
enhance transmission planning by, among other actions, building upon
local and regional transmission planning processes and improving
capabilities to model the development of transmission enhancements for
the various scenarios of interest to State and Federal policy makers
and other stakeholders, as well as Canadian provincial policy makers in
the Western Interconnection. We emphasize that this Proposed Rule,
which does not require interconnectionwide planning or cost allocation,
is not intended to interfere with the efforts already underway in ARRA-
funded transmission planning initiatives.
113. However, even with these important steps toward
interconnection-wide scenario analysis, the Commission remains
concerned that the lack of coordinated transmission planning processes
across the seams of neighboring transmission planning regions could be
needlessly increasing costs for customers of transmission providers.
These circumstances may result in transmission rates that are unjust
and unreasonable. Therefore, the Commission proposes reforms that are
intended to improve coordination between neighboring transmission
planning regions with respect to facilities that are proposed to be
located in both regions, as well as interregional facilities that could
address transmission needs more efficiently than separate intraregional
facilities.
2. Proposed Interregional Planning Reforms
114. We propose to require each public utility transmission
provider through its regional transmission planning process to
coordinate with the public utility transmission providers in each of
its neighboring transmission planning regions within its
interconnection to address transmission planning issues, as discussed
below.\121\ This coordination between transmission planning regions
must be reflected in an
[[Page 37900]]
interregional transmission planning agreement to be filed with the
Commission.
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\121\ This proposal does not require a public utility
transmission provider to enter into an interregional transmission
planning agreement with a neighboring transmission planning region
in another interconnection.
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115. The interregional transmission planning agreement may be
developed on behalf of the public utility transmission providers within
multiple transmission planning regions. For example, two RTOs may set
forth the requirements of their interregional transmission planning
coordination as part of an overall joint operating agreement between
them. A public utility transmission provider that is not in an RTO or
ISO may, for example, work with other transmission providers that
participate in its regional transmission planning process to create and
enter into a multilateral interregional transmission planning agreement
with transmission providers in a neighboring transmission planning
region. Although not required under this proposal, we encourage public
utility transmission providers to explore possible multilateral
interregional transmission planning agreements among several, or even
all, regions within an interconnection, building on processes developed
through the ARRA-funded transmission planning initiatives. We note that
multilateral interregional transmission planning agreements may
minimize the growing number of planning meetings that some stakeholders
suggest pose barriers to their meaningful participation in the planning
processes, given their limited resources.
116. The interregional transmission planning agreement must include
a detailed description of the process for coordination between public
utility transmission providers in neighboring transmission planning
regions with respect to facilities that are proposed to be located in
both regions, as well as interregional facilities that are not proposed
but that could address transmission needs more efficiently than
separate intraregional facilities.
117. While the Commission encourages every interregional
transmission planning agreement to be tailored to best fit the needs of
the regions entering into the agreement, there are certain elements
that we propose each public utility transmission provider must ensure
are included in any interregional transmission planning agreement in
which it participates. Including these elements will help to ensure a
proactive, comprehensive process. Specifically, we propose that an
interregional transmission planning agreement must include: (1) A
commitment to coordinate and share the results of respective regional
transmission plans to identify possible interregional facilities that
could address transmission needs more efficiently than separate
intraregional facilities; (2) an agreement to exchange at least
annually planning data and information; (3) a formal procedure to
identify and jointly evaluate transmission facilities that are proposed
to be located in both regions; and (4) a commitment to maintain a Web
site or e-mail list for the communication of information related to the
coordinated planning process.
118. With respect to the third proposed requirement for an
interregional transmission planning agreement, the Commission proposes
that the sponsor of a project that would be located in both
transmission planning regions to which that agreement applies must
first propose its project in the transmission planning process of each
of those transmission planning regions. The Commission further proposes
that such a submission would trigger a procedure established by the
interregional transmission planning agreement, under which the
transmission planning regions would coordinate their reviews of and
jointly evaluate the proposed project. The Commission proposes that
such coordination and joint evaluation must be conducted in the same
general timeframe as, rather than subsequent to, each transmission
planning region's individual consideration of the proposed project.
Finally, the Commission proposes that inclusion of the interregional
transmission project in each of the relevant regional transmission
plans would be a prerequisite to application of an interregional cost
allocation method that satisfies the cost allocation principles
proposed below in this NOPR.
119. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule,
including the proposed required elements of an interregional
transmission planning agreement and any other elements that should be
part of an interregional transmission planning agreement. In
particular, we seek comment on how such an agreement would be
implemented in non-RTO or ISO regions and on the impact that an
interregional transmission planning agreement would likely have on the
development of interregional transmission facilities.
120. We recognize that development of interregional transmission
planning agreements would take time and would necessarily depend on
progress at the regional level. Accordingly, the Commission proposes to
require the interregional transmission planning agreements to be
submitted to the Commission no later than one year after the effective
date of the final rule issued in this proceeding.
V. Proposed Reforms: Cost Allocation
A. Introduction
1. Order No. 890's Transmission Planning Principle on Cost Allocation
for New Transmission Facilities
121. In Order No. 890, the Commission found that there is a close
relationship between transmission planning, which identifies needed
transmission facilities, and the allocation of costs of the
transmission facilities in the plan. The Commission stated that knowing
how the costs of new transmission facilities would be allocated is
critical to the development of new infrastructure, because transmission
providers and customers cannot be expected to support the construction
of new transmission unless they understand who will pay the associated
costs.\122\
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\122\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 557.
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122. In light of this close relationship, the Commission included a
principle entitled ``Cost Allocation for New Projects'' among the Order
No. 890 transmission planning principles. The Commission stated that
the Order No. 890 Cost Allocation principle was intended to apply to
projects that did not fit under existing cost allocation methods. As
examples of such projects, the Commission cited regional projects
involving several transmission owners and economic projects that are
identified pursuant to the Order No. 890 economic planning studies
principle for transmission planning, rather than through individual
requests for transmission service.\123\
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\123\ Id. P 558.
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123. The Commission did not impose a particular cost allocation
method in Order No. 890, but instead permitted public utility
transmission providers, customers, and other stakeholders to determine
a method that would be appropriate given the needs of the region. While
allowing this flexibility among regions, the Commission also stated
that providing some overall guidance on the issue was appropriate. The
Commission stated that when considering a dispute over cost allocation,
it would exercise its judgment by weighing several factors. First, the
Commission stated that it would consider whether a cost allocation
proposal fairly assigns costs among participants, including those who
cause the costs to be incurred and
[[Page 37901]]
those that otherwise benefit from them. Second, the Commission stated
that it would consider whether a cost allocation proposal provides
adequate incentives to construct new transmission. Third, the
Commission stated that it would consider whether the proposal is
generally supported by State authorities and participants across the
region.\124\
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\124\ Id. P 559.
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124. The Commission also stated that these factors are particularly
important as applied to economic projects that are identified pursuant
to the Order No. 890 economic planning studies principle for
transmission planning, such as upgrades to reduce congestion or enable
groups of customers to access new generation. The Commission stated
that, as a general matter, the beneficiaries of any such project should
agree to support its costs. The Commission recognized, however, that
there are free rider problems associated with new transmission
investment, such that customers who do not agree to support a
particular project may nonetheless receive substantial benefit from it.
The Commission also stated that a range of solutions to free rider
problems is available, noting that different regions have attempted to
address those problems in a variety of ways.\125\
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\125\ Id. P 561 (``[D]ifferent regions have attempted to address
such issues in a variety of ways, such as by assigning transmission
rights only to those who financially support a project or spreading
a portion of the cost of certain high-voltage projects more broadly
than the immediate beneficiary/supporters of the project.'').
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125. To comply with the cost allocation principle, the Commission
directed each public utility transmission provider to clearly define
the details of its cost allocation method as part of a new attachment
to its OATT. The Commission stated that each proposal should identify
the types of new projects that are not covered under previously
existing cost allocation methods and, therefore, would be affected by
the Order No. 890 cost allocation principle.\126\ The Commission also
stated that it is important that each region address these cost
allocation issues up front, at least in principle, rather than having
them relitigated each time a project is proposed.\127\ The Commission
explained that up-front identification of how the cost of a facility
will be allocated will allow transmission providers, customers, and
potential investors to make the decision whether or not to build that
facility on an informed basis.\128\
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\126\ Id. P 558.
\127\ Id. P 561.
\128\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 251.
The Commission also stated that neither adoption of a cost
allocation method nor identification of an upgrade (whether driven
by reliability or economics) in a transmission plan triggers an
obligation to build. Id.
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126. After several rounds of compliance filings, the Commission
approved various public utility transmission providers' proposals
pursuant to the cost allocation principle. The Commission found that
the proposals adequately identified both the types of new projects that
were not covered under previously existing cost allocation methods and
new methods for allocating the cost of those projects.
127. Particularly in transmission planning regions outside of the
RTO and ISO footprints, many of the cost allocation methods that the
Commission accepted in the Order No. 890 compliance proceedings rely
exclusively on a ``participant funding'' approach to cost allocation.
Under a participant funding approach to cost allocation, the costs of a
new transmission facility are allocated only to entities that volunteer
to bear those costs.
128. For example, El Paso Electric proposed in its Order No. 890
compliance filing to use a cost allocation method in which such
entities would share the costs proportionally based on each
participant's desired use of the facility to be constructed.\129\ Other
members of WestConnect, such as Public Service Company of Colorado,
filed and now use similar participant funding cost allocation
methods.\130\ South Carolina Electric & Gas included in its Order No.
890 compliance filing the Southeast Inter-Regional Participation
Process (SIRPP) provisions stating that costs for economics-driven
upgrades will be born entirely by the transmission owner that builds
the facilities.\131\ Similarly, Entergy filed and had approved a method
where the costs for projects developed under its Regional Planning
Process and its interregional transmission planning process would be
born by the party that constructs the facilities.\132\ ColumbiaGrid and
the Northern Tier Transmission Group both utilize a study committee
process whereby alternative cost allocation methods can be proposed for
projects within their respective regions.\133\ However, both
ColumbiaGrid and Northern Tier Transmission Group use a process where,
if no agreement on cost allocation among the study team participants or
the project proponents is obtained, the entities requesting the project
will bear the costs.
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\129\ El Paso Electric Company, 124 FERC ] 61,051, at P 44
(2008).
\130\ Xcel Energy Services, Inc.--Public Service Company of
Colorado, 124 FERC ] 61,052 (2008).
\131\ South Carolina Electric & Gas Company, 127 FERC ] 61,275,
at P 50 (2009).
\132\ Entergy Services, Inc., 127 FERC ] 61,272 (2009).
\133\ See Avista Corporation, 128 FERC ] 61,065 (2009) and Idaho
Power Company, 128 FERC ] 61,064 (2009).
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2. October 2009 Notice and Subsequent Comments
129. As discussed above, in the October 2009 Notice, the Commission
posed a number of questions with respect to allocating the cost of
transmission facilities. Those questions drew wide-ranging responses as
to whether further Commission action on cost allocation is needed at
this time and, if so, what that action should be.
130. Among the commenters, there is general agreement that the
Commission should not supersede existing, ongoing processes in various
parts of the country that are attempting to address regional and
interregional cost allocation issues.
131. Nonetheless, commenters supporting further Commission action
on cost allocation at this time generally assert that the Commission
should provide more detailed guidelines or principles for allocating
the costs of new transmission facilities.\134\ Many commenters argue
that a clear path to cost recovery is necessary for a new transmission
project to move beyond the evaluation stage and to be included in any
regional transmission planning process and ultimately to proceed to
construction.\135\ Such commenters indicate that risks associated with
cost recovery--together with the risks associated with permitting and
siting--are among the most significant obstacles to the construction of
a new transmission facility, especially if customers that are allocated
costs do not perceive that they will benefit from the proposed
facility.\136\ Old Dominion emphasizes that many of the obstacles
inhibiting transmission development are interrelated, but that greater
certainty on cost allocation would likely ease access to capital for
proposed facilities.\137\
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\134\ E.g., APPA, National Rural Electric Coops, Transmission
Access Policy Study Group, Transmission Dependent Utility Systems,
and California ISO.
\135\ E.g., American Transmission, AWEA, E.ON Climate &
Renewables North America, Energy Future Coalition, and NextEra.
\136\ E.g., AWEA, Transmission Dependent Utility Systems, Xcel,
Transmission Access Policy Study Group, and National Rural Electric
Coops.
\137\ Old Dominion at 26.
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132. Several commenters specifically address cost allocation as an
impediment to the development of generation to satisfy renewable
portfolio
[[Page 37902]]
standards implemented by the states.\138\ AWEA, for example, states
that cost allocation policies are the biggest impediment to
construction of new transmission facilities, regardless of location,
and that costs should be assigned to all entities that benefit from a
new facility. AWEA further comments that a participant funding cost
allocation method does not achieve that goal.\139\ These commenters
also state that uncertainty over cost allocation imposes significant
costs on customers attempting to export energy from renewable resources
and inhibit planning for the integration of the most economic
generation resources into the transmission grid. Maine PUC and Public
Advocate state that the existing ISO-NE cost allocation methods are not
optimal when considering large amounts of wind integration.\140\
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\138\ E.g., AWEA at 9-10, American Transmission and Exelon.
\139\ AWEA at 4. See also Transmission Access Policy Study Group
at 25-27.
\140\ Maine PUC and Public Advocate at 7-8.
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133. Similarly, the majority of commenters that address cost
allocation for large, interregional transmission facilities agree that
the Commission should provide more guidance on cost allocation.\141\
Some commenters complain that as a general matter, the Commission has
addressed cost allocation methods only for facilities within the
footprint of a single transmission provider or a single RTO or ISO, and
not for interregional projects. For example, AEP states that it has
experienced delays in developing transmission facilities that cross RTO
boundaries as a result of uncertainty over cost allocation, as well as
difficulties with how the facilities are to be planned.
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\141\ E.g., AEP, ITC Holdings, and Exelon.
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134. Some of these commenters assert that the expansion of regional
power markets and the increasing adoption by State governments of
renewable energy requirements have led to a growing need for new
transmission facilities that cross several utility and/or RTO or ISO
regions. These commenters generally support, or state that they do not
oppose, the Commission establishing a process to help stakeholders
address cost allocation matters over larger geographic areas. For
example, California ISO and the California Commission comment that,
although cost allocation within the California ISO works well, they
support the Commission creating a process to consider cost allocation
over a larger region in the West.
135. In addition, the comments in response to the October 2009
Notice reflect a general consensus that those who share in the benefits
of transmission projects should also share in their costs. However,
there is no consensus on what types of benefits should be considered or
how such benefits should be calculated. Certain commenters, for
example, support recognition of a broad spectrum of benefits that may
stem from transmission development, such as environmental impacts, land
conservation and energy security.\142\ Other commenters urge the
Commission to avoid a uniform approach to determining the benefits of
transmission projects.\143\
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\142\ E.g., AEP, AWEA, Baltimore Gas and Electric, Energy Future
Coalition, Green Energy Express, ITC Holdings, MidAmerican, National
Audubon Society, NextEra, and Public Interest Organizations &
Renewable Energy Groups.
\143\ E.g., ColumbiaGrid, ConEd, Delaware Municipal and
Southwestern Electric, and Northeast Utilities.
---------------------------------------------------------------------------
136. Several commenters suggest that if the Commission decides to
establish a default cost allocation method for new transmission
facilities, such a method should be employed and enforced only when
stakeholders are unable to agree upon their own regional cost
allocation method or methods.\144\ For example, American Transmission,
National Grid, Northern Tier Transmission Group, and NEPOOL
Participants state that the Commission could create a generic cost
allocation method as a backstop, which would apply when parties or
regions could not come to their own agreement. Other commenters express
the view that the Commission should create one or more rebuttable
presumptions about who benefits from various types of facilities in
order to make cost allocation easier.\145\
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\144\ E.g., American Transmission, National Grid, Northern Tier
Transmission Group, and NEPOOL Participants.
\145\ E.g., ITC Holdings, MidAmerican, PJM, Solar Energy
Industries, and WIRES.
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137. Finally, many commenters state that no further generic
Commission action on cost allocation is needed at this time because the
processes in their own regions already address, or are now working to
address, cost allocation. For example, in the Southeast, some
commenters state that their processes for cost allocation are working
well and argue that the Commission should continue to allow regional
flexibility on cost allocation processes.\146\ Similarly, in the West,
some commenters state that cost allocation in their region is not a
problem.\147\
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\146\ E.g., Entergy, Southern Companies, and Florida
Transmission Providers.
\147\ E.g., ColumbiaGrid, Northern Tier Transmission Group,
Transmission Agency of Northern California, Salt River Project and
WestConnect Planning Parties.
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B. Legal Authority and Need for Reform
138. Based on the comments received in response to the October 2009
Notice, the Commission believes that further reform with respect to
transmission cost allocation methods may be necessary in order to
ensure that the rates, terms and conditions of transmission service in
interstate commerce are just and reasonable and not unduly
discriminatory or preferential.
1. The Cost Causation Principle
139. Under sections 205 and 206 of the FPA, the Commission is
responsible for ensuring that the rates, terms, and conditions for
transmission of electricity in interstate commerce are just,
reasonable, and not unduly discriminatory or preferential.\148\ With
respect to this responsibility, the Commission and the courts have
found that the costs of jurisdictional transmission facilities must be
allocated in a manner that satisfies the ``cost causation'' principle.
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\148\ 16 U.S.C. 824d, 824e.
---------------------------------------------------------------------------
140. The U.S. Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) has defined the cost causation principle as follows:
``[I]t has been traditionally required that all approved rates reflect
to some degree the costs actually caused by the customer who must pay
them.'' \149\ The U.S. Court of Appeals for the Seventh Circuit
(Seventh Circuit) recently quoted and elaborated on that definition,
stating, ``All approved rates must reflect to some degree the costs
actually caused by the customer who must pay them. Not surprisingly, we
evaluate compliance with this unremarkable principle by comparing the
costs assessed against a party to the burdens imposed or benefits drawn
by that party. To the extent that a utility benefits from the costs of
new facilities, it may be said to have `caused' a part of those costs
to be incurred, as without the expectation of its contributions the
facilities might not have been built, or might have been delayed.''
\150\ The Commission has
[[Page 37903]]
frequently made similar statements with respect to the cost causation
principle. For example, as noted above, the Commission stated in Order
No. 890 that one factor it weighs when considering a dispute over cost
allocation is whether a cost allocation proposal fairly assigns costs
among participants, including those who cause the costs to be incurred
and those that otherwise benefit from them.\151\
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\149\ K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir.
1992) (K N Energy).
\150\ Illinois Commerce Comm'n v. FERC, 576 F.3d 470, 476 (7th
Cir. 2009) (Illinois Commerce Commission) (citing K N Energy, 968
F.2d at 1300; Transmission Access Policy Study Group v. FERC, 225
F.3d 667, 708 (D.C. Cir. 2000); Pacific Gas & Elec. Co. v. FERC, 373
F.3d 1315, 1320-21 (D.C. Cir. 2004); Midwest ISO Transmission Owners
v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (Midwest ISO
Transmission Owners); Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir.
2009); Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 1,
4-5 (D.C. Cir. 2002) (Sithe); 16 U.S.C. 824d).
\151\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 559.
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141. In applying the cost causation principle, the Commission has
generally allocated costs to beneficiaries that have entered a
voluntary arrangement with the public utility that is seeking to
recover those costs. One example of a voluntary cost recovery
arrangement with a public utility is voluntary membership in an RTO or
ISO that makes an entity subject to the cost allocation provisions of
the RTO's or ISO's tariff.\152\ The Commission also has permitted
joint-ownership agreements where the owners share the costs of the new
transmission facilities.
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\152\ The Commission notes that RTO or ISO membership does not
eliminate the need to satisfy the other aspects of the cost
causation principle that are discussed above.
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142. The cost causation principle, however, is not limited to
voluntary arrangements. Indeed, if the Commission were limited to
allocating costs only to beneficiaries that voluntarily accept those
costs, then the Commission could not fulfill its responsibilities under
the FPA. If the Commission could not address free rider problems
associated with new transmission investment, then it could not ensure
that transmission rates are just and reasonable and not unduly
discriminatory. The cost causation principle provides that costs should
be allocated to those who cause them to be incurred and those that
otherwise benefit from them, as the Commission also recognized in Order
No. 890. In other words, the Commission may determine that an entity's
status as a beneficiary of a transmission facility identified through
an appropriate process is relevant for purposes of applying the cost
causation principle, even if that beneficiary has not entered a
voluntary arrangement with (e.g., as a customer of) the public utility
that is seeking to recover the costs of that facility.
143. The Commission has expressed a willingness to make such a
determination. For example, when presented with concerns about parallel
path flow,\153\ the Commission has offered repeatedly that if a public
utility can demonstrate that a transaction is a burden on its system,
then that utility can propose a transmission service rate for
Commission consideration that would account for the unauthorized use of
its system.\154\ The Commission has cautioned against the hasty
submittal of such unilateral filings, describing its general policy as
expecting owners and controllers of transmission facilities to attempt
to resolve parallel path flow issues on a consensual, regional
basis.\155\ Nonetheless, if approved by the Commission, such a proposal
to address parallel path flow would allow a public utility to recover
costs from a beneficiary of its system in the absence of a voluntary
arrangement between the utility and that beneficiary.
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\153\ The Commission has described the phenomenon of parallel
path flow as follows: ``In general, utilities transact with one
another based on a contract path concept. For pricing purposes,
parties assume that power flows are confined to a specified sequence
of interconnected utilities that are located on a designated
contract path. However, in reality power flows are rarely confined
to a designated contract path. Rather, power flows over multiple
parallel paths that may be owned by several utilities that are not
on the contract path. The actual power flow is controlled by the
laws of physics which cause power being transmitted from one utility
to another to travel along multiple parallel paths and divide itself
along the lines of least resistance. This parallel path flow is
sometimes called `loop flow.' '' Indiana Michigan Power Co. and Ohio
Power Co., 64 FERC ] 61,184, at 62,545 (1993).
\154\ See, e.g., Amer. Elec. Power Svc. Corp., 49 FERC ] 61,377,
at 62,381 (1989).
\155\ Id. See also Southern California Edison Co., 70 FERC ]
61,087, at 61,241-42 (1995).
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144. The Commission also affirmatively required costs of
transmission facilities to be allocated to beneficiaries in the absence
of a voluntary arrangement in a series of orders involving the Midwest
Independent Transmission System Operator, Inc. (Midwest ISO) and PJM
Interconnection, L.L.C. (PJM). Specifically, the Commission directed
Midwest ISO and PJM to develop cost allocation methods for new
facilities in one of their footprints that benefit entities in the
other's footprint.\156\ Echoing precedent applying the cost causation
principle, the Commission later conditionally accepted a proposal that
Midwest ISO and PJM submitted in compliance with that directive on the
grounds that it ``more accurately identifies the beneficiaries and
allocates the associated costs'' than did the cost allocation methods
that were previously in place.\157\
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\156\ Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC
] 61,168, at P 60 (2004) (citing Midwest Indep. Transmission Sys.
Operator, Inc., 106 FERC ] 61,251, at P 56-57 (2004)). The
Commission noted that Midwest ISO and PJM had committed in a Joint
Operating Agreement to develop such a method for allocating the
costs of certain facilities through their joint regional planning
committee. Id. The Commission did not base the above-noted directive
on the existence of the Joint Operating Agreement, which Midwest ISO
and PJM developed in order to comply with a previous Commission
directive. See Alliance Cos., 100 FERC ] 61,137, at P 48, 53 (2002).
\157\ Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC
] 61,194, at P 10 (2005). See also Midwest Indep. Transmission Sys.
Operator, Inc., 122 FERC ] 61,084 (2008); Midwest Indep.
Transmission Sys. Operator, Inc., 129 FERC ] 61,102 (2009).
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145. These examples show that the Commission has asserted its
authority to allocate the costs of jurisdictional facilities to
beneficiaries whether or not those beneficiaries have entered into a
voluntary agreement with the public utility that is seeking to recover
those costs.
146. In addition, courts have affirmed that the cost causation
principle allows the Commission to allocate at least some types of
costs to beneficiaries that are not customers of the public utility
that is seeking to recover the costs in question. For example, the D.C.
Circuit addressed this issue in a case that involved a proposal for
Midwest ISO to recover administrative costs through a charge that would
apply to transmission loads subject to the Midwest ISO's tariff rates:
i.e., new wholesale loads and unbundled retail loads, but not bundled
retail loads and loads served pursuant to grandfathered contracts.\158\
Describing the core issue as whether the Commission's orders comported
with the cost causation principle, the D.C. Circuit found that the
Commission reasonably allocated the administrative costs more broadly
than Midwest ISO proposed.\159\ After stating that the subject costs
were the administrative costs of having an ISO, the D.C. Circuit found
that the Commission correctly determined that bundled and grandfathered
loads should share the cost of having an ISO because they drew benefits
from Midwest ISO.\160\
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\158\ Midwest ISO Transmission Owners, 373 F.3d 1361. The D.C.
Circuit stated that the subject costs ``are primarily MISO's startup
expenses--particularly those pertaining to the MISO Security
Center--and certain expenses pertaining to the creation and
administration of MISO's open access tariff.'' Id. at 1369.
\159\ Id. at 1370.
\160\ Id. at 1370-71.
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147. Thus, in applying the cost causation principle, the Commission
may allocate costs of a transmission facility to a beneficiary
identified through an appropriate process, such as a Commission-
approved transmission planning process, even if that beneficiary has
not entered a voluntary arrangement with the public utility that
[[Page 37904]]
is seeking to recover the costs of that facility. After satisfying this
standard with respect to beneficiary identification, the cost causation
principle also requires the Commission to ensure that the costs
allocated to a beneficiary under a cost allocation method are at least
roughly commensurate with the benefits that are expected to accrue to
that entity.\161\ On this point, the D.C. Circuit has explained that
``the cost causation principle does not require exacting precision in a
ratemaking agency's allocation decisions.'' \162\
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\161\ Illinois Commerce Commission, 576 F.3d at 476-77 (``We do
not suggest that the Commission has to calculate benefits to the
last penny, or for that matter to the last million or ten million or
perhaps hundred million dollars.''). See also Midwest ISO
Transmission Owners, 373 F.3d 1361 at 1369 (``we have never required
a ratemaking agency to allocate costs with exacting precision.'');
Sithe, 285 F.3d 1 at 5.
\162\ Midwest ISO Transmission Owners, 373 F.3d 1361 at 1371
(citing Sithe, 285 F.3d 1 at 5).
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2. Need for Reform
148. The Commission's responsibility under FPA sections 205 and 206
to ensure that transmission rates are just and reasonable and not
unduly discriminatory or preferential is not new, nor is the
Commission's recognition of the cost causation principle. However, the
circumstances in which the Commission must fulfill its statutory
responsibilities change with developments in the electric industry,
such as changes with respect to the demands placed on the transmission
grid.
149. The Commission has previously recognized changes in
circumstances that warranted changes in the manner by which public
utilities recover transmission costs. In the early 1990s, the
Commission identified ``dramatic changes which the electric industry
has faced, and will face in the near term,'' such as ``increased
reliance on market forces to meet power supply needs; new market
entrants such as exempt wholesale generators; a significant number of
utility mergers and combinations; more highly integrated operation of
various power pools; and substantial bulk power trading among electric
systems,'' as well as the initial filing of open access transmission
tariffs.\163\ To account for those developments and the industry's
changing needs, the Commission issued a policy statement that increased
flexibility with respect to transmission pricing.\164\
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\163\ See Notice of Technical Conference and Request for
Comments in Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities under the Federal
Power Act, 58 FR 36400, at 36401 (1993).
\164\ Policy Statement in Inquiry Concerning the Commission's
Pricing Policy for Transmission Services Provided by Public
Utilities under the Federal Power Act, FERC Stats. & Regs.,
Regulations Preambles January 1991-June 1996 ] 31,005 (1994).
---------------------------------------------------------------------------
150. Many of those changes have not only continued but also
accelerated in recent years. For example, as commenters stated in
response to the October 2009 Notice, the further expansion of regional
power markets has led to a growing need for new transmission facilities
that cross several utility, RTO, ISO or other regions. The industry's
continuing transition from relatively localized trading to larger
regional power markets also results, among other effects, in broader
diffusion of the benefits associated with transmission upgrades and new
transmission facilities.
151. Similarly, the increasing adoption of State resource policies,
such as renewable portfolio standard measures, has contributed to rapid
growth of location-constrained renewable energy resources that are
frequently remote from load centers, as well as a growing need for new
transmission facilities that cross several utility and/or RTO or ISO
regions. Transmission facilities that are needed to comply with State
renewable portfolio standard measures illustrate the increasing
potential for benefits associated with meeting public policy-driven
transmission needs.
152. More generally, as stated above, challenges associated with
allocating the cost of transmission appear to have become more acute as
the need for transmission infrastructure has grown. As noted above,
constructing new transmission facilities requires a significant amount
of capital. Therefore, a threshold consideration for any company
considering investing in transmission is whether it will have a
reasonable opportunity to recover its costs. However, there are few
rate structures in place today that provide both for analysis of the
beneficiaries of a transmission facility that is proposed to be located
within a transmission planning region that is outside of an RTO or ISO,
or in more than one transmission planning region, and for corresponding
allocation and recovery of the facility's costs. The lack of such rate
structures creates significant risk for transmission developers that
they will have no identified group of customers from which to recover
the cost of their investment. In addition, cost allocation within RTO
or ISO regions, particularly those that encompass several states, is
often contentious and prone to litigation because it is difficult to
reach an allocation of costs that is perceived as fair. Some comments
filed in response to the October 2009 Notice present these types of
concerns and state the resultant uncertainty regarding cost allocation
remains an impediment to development of needed transmission facilities.
153. The risk of the free rider problems associated with new
transmission investment that the Commission described in Order No. 890
is also particularly high for projects that affect multiple utilities'
transmission systems and therefore may have multiple beneficiaries.
With respect to such projects, any individual beneficiary has an
incentive to defer investment in the hopes that other beneficiaries
will value the project enough to fund its development. On one hand, a
cost allocation method that relies exclusively on a participant funding
approach, without respect to other beneficiaries of a transmission
facility, increases this incentive and, in turn, the likelihood that
needed transmission facilities will not be constructed in a timely
manner. On the other hand, if costs are allocated to entities that will
receive no benefit from a transmission facility, then those entities
are more likely to oppose inclusion of the facility in a regional
transmission plan or to otherwise impose obstacles that delay or
prevent the facility's construction.
154. In light of these challenges and recent developments affecting
the industry, the Commission is concerned that existing cost allocation
methods may not appropriately account for benefits associated with new
transmission facilities and, thus, may result in rates that are not
just and reasonable or are unduly discriminatory or preferential.
C. Proposed Reforms
155. The Commission proposes to amend its regulations to address
the concerns discussed above.
156. First, we propose to more closely align transmission planning
and cost allocation processes. A transmission planning process includes
a facility in a transmission plan in order to achieve a specific
purpose or purposes, such as to avoid an impending violation of a
Reliability Standard, reduce congestion and thereby increase access to
lower-cost resources, or enable compliance with public policy
requirements established by State or Federal laws or regulations.
Because such purposes involve the identification of expected
beneficiaries--either explicitly or implicitly--establishing a closer
link between transmission planning and cost
[[Page 37905]]
allocation will address in part the Commission's concern that existing
cost allocation methods may not appropriately account for benefits
associated with new transmission facilities.
157. The Commission has previously suggested that transmission
planning at least on a regional basis is closely related to cost
allocation. As noted above, this premise underlies the Commission's
establishment in Order No. 890 of a transmission planning principle on
cost allocation for new transmission facilities. In addition, the
Commission has explained that it may be appropriate to have different
cost allocation methods for facilities that are planned for different
purposes or pursuant to different transmission planning processes. For
example, the Commission distinguished between existing facilities in
Midwest ISO and PJM for which it found that license plate rates are
appropriate, and new facilities in those regions for which it approved
broader cost allocation methods.\165\ The Commission found it
significant that Midwest ISO and PJM plan the construction of new
facilities based on each RTO's independent transmission planning
process, which helps to ensure that new projects are necessary to meet
the reliability and economic needs of each RTO's system as a whole. The
Commission also noted that Midwest ISO and PJM plan certain new
facilities pursuant to a joint RTO planning process under a Joint
Operating Agreement. By contrast, the Commission stated that decisions
to build existing facilities within Midwest ISO and PJM were not made
as part of any regional planning process.\166\
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\165\ Amer. Elec. Power Serv. Corp. v. Midwest Indep.
Transmission Sys. Operator, Inc., 122 FERC ] 61,083, at P 13-24
(2008).
\166\ Id. P 96.
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158. The Commission recognizes that identifying which types of
benefits are relevant for cost allocation purposes, which entities are
receiving those benefits, and the relative benefits that accrue to
various beneficiaries can be difficult and controversial. The
Commission believes that a transparent transmission planning process is
the appropriate forum to address these issues. In addition, addressing
these issues through the transmission planning process would increase
the likelihood that facilities included in transmission plans are
actually constructed, rather than being included in a transmission plan
only to later encounter cost allocation disputes that prevent their
construction.
159. Accordingly, the Commission proposes to require that every
public utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities that
are included in the transmission plan produced by the transmission
planning process in which it participates. If the public utility
transmission provider is an RTO or ISO, then the method or methods
would be required to be set forth in the RTO or ISO tariff. In other
transmission planning regions, each public utility transmission
provider located within the region would be required to set forth in
its tariff the method or methods for cost allocation used in its
transmission planning region.
160. An RTO or ISO or the public utility transmission providers in
a transmission planning region may have a single cost allocation method
for all new transmission facilities or different methods for different
types of facilities. For example, cost allocation methods may
distinguish among facilities that are driven by needs associated with
maintaining reliability, relieving congestion, and achieving public
policy requirements established by State or Federal laws or
regulations, all of which would be required to be considered in the
regional transmission planning process as explained elsewhere in this
Proposed Rule. The Commission recognizes that several transmission
planning regions that have different cost allocation methods by type of
project currently have transmission planning procedures and cost
allocation methods that refer only to the first two categories of
transmission projects. The Proposed Rule would permit a public utility
transmission provider or transmission planning region to distinguish or
not distinguish among these three types of transmission facilities, as
long as each of the three is considered in the transmission planning
process and there is a means for allocating the costs of each type of
facility to beneficiaries.
161. Second, we propose to require that each public utility
transmission provider within a transmission planning region develop a
method for allocating the costs of a new interregional transmission
facility between the two neighboring transmission planning regions in
which the facility is located or among the beneficiaries in the two
neighboring transmission planning regions.
162. Third, to ensure that the cost allocation method or methods
are just and reasonable and not unduly discriminatory or preferential,
we propose to assess each cost allocation method based upon the cost
allocation principles set out in the following sections, one set of
principles for intraregional facilities and another for interregional
facilities. To reiterate, we propose that the cost allocation method or
methods be applied to new transmission facilities included in the
transmission plan produced by the transmission planning process in
which the public utility transmission provider participates.
163. Finally, we note that under our proposals, public utility
transmission providers will have the first opportunity to develop cost
allocation methods for intraregional and interregional transmission
facilities in consultation with customers and other stakeholders. In
the event that no agreement can be reached, the Commission would use
the record in the relevant compliance filing proceeding as a basis to
develop a cost allocation method or methods that meets the Commission's
proposed requirements.
1. Intraregional Cost Allocation
164. An intraregional transmission facility is defined as a
transmission facility located entirely within the geographic boundaries
of one transmission planning region. As proposed here, each RTO or ISO
on behalf of its transmission owning members, or the individual public
utility transmission providers in a non-RTO or ISO transmission
planning region, would be required to demonstrate through a compliance
filing that it has a cost allocation method or methods that address
cost recovery for each new transmission facility included in its
regional transmission plan and that satisfy the following principles:
(1) The cost of transmission facilities must be allocated to those
within the transmission planning region that benefit from those
facilities in a manner that is at least roughly commensurate with
estimated benefits.\167\ In determining the beneficiaries of
transmission facilities, a regional transmission planning process may
consider benefits including, but not limited to the extent to which
transmission facilities, individually or in the aggregate, provide for
maintaining reliability and sharing reserves, production cost savings
and congestion relief, and/or meeting public policy
[[Page 37906]]
requirements established by State or Federal laws or regulations that
may drive transmission needs.\168\
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\167\ Illinois Commerce Commission, 576 F.3d at 476-77 (``We do
not suggest that the Commission has to calculate benefits to the
last penny, or for that matter to the last million or ten million or
perhaps hundred million dollars.''). See also Midwest ISO
Transmission Owners, 373 F.3d 1361 at 1369 (``we have never required
a ratemaking agency to allocate costs with exacting precision.'');
Sithe, 285 F.3d 1 at 5.
\168\ As discussed above, the Commission proposes to require
each public utility transmission provider to amend its OATT such
that its local and regional transmission planning processes
explicitly provide for consideration of public policy requirements
established by state or Federal laws or regulations that may drive
transmission needs.
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(2) Those that receive no benefit from transmission facilities,
either at present or in a likely future scenario, must not be
involuntarily allocated the costs of those facilities.
(3) If a benefit to cost threshold is used to determine which
facilities have sufficient net benefits to be included in a regional
transmission plan for the purpose of cost allocation, it must not be so
high that facilities with significant positive net benefits are
excluded from cost allocation. A transmission planning region or public
utility transmission provider may want to choose such a threshold to
account for uncertainty in the calculation of benefits and costs. If
adopted, such a threshold may not include a ratio of benefits to costs
that exceeds 1.25 unless the transmission planning region or public
utility transmission provider justifies and the Commission approves a
greater ratio.
(4) The allocation method for the cost of an intraregional facility
must allocate costs solely within that transmission planning region
unless another entity outside the region or another transmission
planning region voluntarily agrees to assume a portion of those
costs.\169\ However, the transmission planning process in the original
region must identify consequences for other transmission planning
regions, such as upgrades that may be required in another region and,
if there is an agreement for the original region to bear costs
associated with such upgrades, then the original region's cost
allocation method or methods must include provisions for allocating the
costs of the upgrades among the entities in the original region.
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\169\ In addition, the Commission preliminarily finds that this
principle does not affect the cross-border cost allocation methods
developed by PJM and the Midwest ISO in response to Commission
directives related to their intertwined configuration. Midwest
Indep. Transmission Sys. Operator, Inc., 113 FERC ] 61,194, at P 10
(2005); Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ]
61,084 (2008); Midwest Indep. Transmission Sys. Operator, Inc., 129
FERC ] 61,102 (2009).
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(5) The cost allocation method and data requirements for
determining benefits and identifying beneficiaries for a transmission
facility must be transparent with adequate documentation to allow a
stakeholder to determine how they were applied to a proposed
transmission facility.
(6) A transmission planning region may choose to use a different
cost allocation method for different types of transmission facilities
in the regional plan, such as transmission facilities needed for
reliability, congestion relief, or to achieve public policy
requirements established by State or Federal laws or regulations. Each
cost allocation method must be set out clearly and explained in detail
in the compliance filing for this rule.
165. In proposing these principles, the Commission does not intend
to prescribe a uniform approach to cost allocation for new
intraregional transmission facilities. To the contrary, we recognize
that regional differences may warrant distinctions in cost allocation
methods among transmission planning regions. Therefore, this Proposed
Rule would allow the public utility transmission providers in each
transmission planning region to develop a transmission cost allocation
method that best suits the needs of that transmission planning region.
166. However, the Commission proposes that, if the public utility
transmission providers in a transmission planning region, in
consultation with customers and other stakeholders, cannot agree on a
cost allocation method for new intraregional transmission facilities
that satisfies these principles, the Commission would use the record in
the relevant compliance filing proceeding as a basis for applying these
principles to develop a cost allocation method that meets the
Commission's requirements. Consistent with the Commission's intention
not to prescribe a uniform approach, this cost allocation method would
not necessarily be the same for every transmission planning region
where the public utility transmission providers are unable to agree on
a cost allocation method that satisfies the principles.
167. The Commission recognizes that several approaches to cost
allocation may satisfy the proposed principles. For example, a postage
stamp cost allocation method may be appropriate where all customers
within a specified transmission planning region are found to benefit
from the use or availability of a facility or class or group of
facilities (e.g., all transmission facilities at 345 kV or higher),
especially if the distribution of benefits associated with a class or
group of facilities is likely to vary considerably over the long
depreciation life of the facilities amid changing power flows, fuel
prices, population patterns, and local economic developments.
Similarly, other methods that propose cost allocation to a narrower
class of beneficiaries may be appropriate, provided that the method
reflects an evaluation of beneficiaries and is adequately defined and
supported by the transmission planning region.
168. In addition, the principles proposed in this rulemaking do not
foreclose the opportunity for a transmission developer or individual
customer to voluntarily assume the costs of a new transmission
facility. In other words, the proposed principles would not prohibit
voluntary participant funding. However, if a transmission developer
believes that others in the transmission planning region may benefit
from a new transmission facility and want to seek broader cost
allocation, then that developer must be permitted to propose its
project in the regional transmission planning process that will
evaluate the project's beneficiaries. If the facility is included in
the regional transmission plan, the costs of that facility must be
eligible for allocation pursuant to the Commission-approved method for
allocating the cost of a new transmission facility in that plan.\170\
As stated above, a cost allocation method that relies exclusively on a
participant funding approach, without respect to other beneficiaries of
a transmission facility, exacerbates the free rider problem that the
Commission described in Order No. 890. Such a cost allocation method
would not satisfy the proposed principles.
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\170\ However, certain transmission developers may seek to
participate in the regional transmission planning process only for
coordination purposes (e.g., to perform a reliability check for a
participant-funded or merchant transmission project), in which case
the transmission plan would not include a cost allocation for such
projects.
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169. With regard to a new transmission facility that is located
entirely within one transmission owner's service territory, a
transmission owner may not unilaterally invoke the regional cost
allocation method to require the allocation of the costs of a new
transmission facility to other entities in its transmission planning
region. However, if the regional transmission planning process
determines that a new facility located solely within a transmission
owner's service territory would provide benefits to others in the
region, allocating the facility's costs according to that region's
intraregional cost allocation method would be permitted.
2. Interregional Cost Allocation
170. An interregional transmission facility is one that in located
within two or more transmission planning regions. In the past, most
transmission upgrades
[[Page 37907]]
were planned and constructed to meet the needs of customers within a
given transmission planning region. However, new transmission
facilities located within multiple transmission planning regions are
now being considered by transmission providers in various parts of the
nation. For example, as discussed above, development of renewable
energy resources is increasing rapidly, in part in response to State
renewable portfolio standard requirements. However, many of these
resources are located far from load centers. New transmission
facilities located within multiple transmission planning regions may be
necessary to deliver the output of these renewable energy resources.
171. There are few rate structures in place today that provide for
the allocation and recovery of costs of interregional transmission
facilities. We are concerned that the absence of clear cost allocation
rules for interregional transmission facilities could impede the
development of such facilities, because of uncertainty regarding
recovery of associated costs. In addition, the combined size of the
multiple transmission planning regions in which an interregional
facility would be located may increase the potential for both free
ridership and the allocation of costs to those that receive no benefit
from a facility.
172. Therefore, we propose to require that the public utility
transmission providers located in each pair of neighboring transmission
planning regions develop a mutually agreeable method for allocating
between the two transmission planning regions the costs of a new
transmission facility that is located within both regions and that is
eligible for interregional cost recovery pursuant to the region's
interregional transmission planning agreement developed in accordance
with the requirement proposed above. In an RTO or ISO region, we
propose that the method must be filed to become a part of the relevant
tariffs. In other transmission planning regions, we propose that the
cost allocation method be filed as part of the OATT of each public
utility transmission provider in the region.
173. A group of three or more transmission planning regions within
an interconnection--or all of the transmission planning regions within
an interconnection--may agree on and file a common method for
allocating the costs of a new interregional transmission facility.
However, the Commission does not propose to require such agreements
among more than two neighboring transmission planning regions.
174. Each cost allocation method filed in accordance with this
proposal would be required to comply with the following principles:
(1) The costs of a new interregional facility must be allocated to
each transmission planning region in which that facility is located in
a manner that is at least roughly commensurate with the estimated
benefits of that facility in each of the transmission planning regions.
In determining the beneficiaries of interregional transmission
facilities, transmission planning regions may consider benefits
including, but not limited to, those associated with maintaining
reliability and sharing reserves, production cost savings and
congestion relief, and meeting public policy requirements established
by State or Federal laws or regulations that may drive transmission
needs.\171\
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\171\ As discussed above, the Commission proposes to require
each public utility transmission provider to amend its OATT such
that its local and regional transmission planning processes
explicitly provide for consideration of public policy requirements
established by state or Federal laws or regulations that may drive
transmission needs.
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(2) A transmission planning region that receives no benefit from an
interregional transmission facility that is located in that region,
either at present or in a likely future scenario, must not be
involuntarily allocated any of the costs of that facility.\172\
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\172\ For example, a DC line that runs from a first transmission
planning region, through a second transmission planning region, and
into a third transmission planning region, with no tap in the second
region, may not provide any benefits to the second region.
---------------------------------------------------------------------------
(3) If a benefit-cost threshold ratio is used to determine whether
an interregional transmission facility has sufficient net benefits to
qualify for interregional cost allocation, this ratio must not be so
large as to exclude a facility with significant positive net benefits
from cost allocation. The public utility transmission providers located
in the neighboring transmission planning regions may choose to use such
a threshold to account for uncertainty in the calculation of benefits
and costs. If adopted, such a threshold, may not include a ratio of
benefits to costs that exceeds 1.25 unless the pair of regions
justifies and the Commission approves a higher ratio.
(4) Costs allocated for an interregional facility must be assigned
only to transmission planning regions in which the facility is located.
Costs cannot be assigned involuntarily under this rule to a
transmission planning region in which that facility is not located.
However, the interregional planning process must identify consequences
for other transmission planning regions, such as upgrades that may be
required in a third transmission planning region and, if there is an
agreement among the transmission providers in the regions in which the
facility is located to bear costs associated with such upgrades, then
the interregional cost allocation method must include provisions for
allocating the costs of the upgrades within the transmission planning
regions in which the facility is located.
(5) The cost allocation method and data requirements for
determining benefits and identifying beneficiaries for an interregional
facility must be transparent with adequate documentation to allow a
stakeholder to determine how they were applied to a proposed
transmission facility.
(6) The public utility transmission providers located in
neighboring transmission planning regions may choose to use a different
cost allocation method for different types of interregional facilities,
such as transmission facilities needed for reliability, congestion
relief, or to achieve public policy requirements established by State
or Federal laws or regulations. Each cost allocation method must be set
out and explained in detail in the compliance filing for this rule.
175. As with intraregional cost allocation, we are not proposing to
require a uniform method of cost allocation for interregional
transmission facilities. There may be legitimate reasons for the public
utility transmission providers located in neighboring transmission
planning regions to adopt different cost allocation methods. The
Commission recognizes that several approaches to cost allocation may
satisfy the proposed principles.\173\
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\173\ For the reasons discussed above with respect to cost
allocation for intraregional transmission facilities, a cost
allocation method that relies exclusively on a participant funding
approach, without respect to other beneficiaries of a transmission
facility, would not satisfy the proposed principles for
interregional cost allocation.
---------------------------------------------------------------------------
176. Therefore, we propose to allow methods for allocating the
costs of new interregional facilities to differ among pairs of
transmission planning regions, as long as each method satisfies the
proposed interregional cost allocation principles listed above.
Moreover, the method used for allocating interregional transmission
facility costs between any two transmission planning regions may be
different from the method used by the public utility transmission
providers located in either of those transmission planning regions to
allocate the costs of new intraregional facilities. In addition, the
cost allocation method used by the
[[Page 37908]]
public utility transmission providers located in a transmission
planning region to allocate the costs of new intraregional facilities
could be different from the cost allocation method by which the public
utility transmission providers in the same transmission planning region
further allocate costs to be borne by that transmission planning region
pursuant to an agreed-upon method for allocating the costs of
interregional facilities.
177. Similar to our proposal for intraregional transmission
facilities, we propose that if the public utility transmission
providers in coordination with their customers and other stakeholders
in a pair of neighboring transmission planning regions cannot agree on
a cost allocation method for new interregional transmission facilities
that satisfies these principles, then the Commission would use the
record in the relevant compliance filing proceedings as a basis for
applying the principles to develop an interregional cost allocation
method that meets the Commission's requirements. Such a cost allocation
method would not necessarily be the same for every pair of neighboring
transmission planning regions that is unable to agree on a cost
allocation method that satisfies the principles.
178. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule. In
particular, we seek comment on the appropriateness and application of
the proposed cost allocation principles with respect to new
intraregional and interregional transmission facilities. If commenters
believe that additional principles should apply to cost allocation for
either intraregional or interregional transmission facilities, the
Commission asks commenters to submit and explain the need for those
principles.
VI. Compliance Filings
179. The Commission proposes that each public utility transmission
provider must comply with the requirements of this Proposed Rule. With
the exception of the proposed requirements with respect to
interregional transmission planning agreements and an interregional
cost allocation method or methods, the Commission proposes to require
each public utility transmission provider to submit a compliance filing
within six months of the effective date of the final rule in this
proceeding revising its OATT or other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
proposed requirements set forth in this Proposed Rule.\174\ The
Commission proposes to require each public utility transmission
provider to submit a compliance filing within one year of the effective
date of the final rule in this proceeding to demonstrate that it meets
the proposed requirements set forth in the Proposed Rule with respect
to interregional transmission planning agreements. The Commission
proposes to require each public utility transmission provider to submit
a compliance filing within one year of the effective date of the final
rule in this proceeding revising its OATT as necessary to demonstrate
that it meets the proposed requirements set forth in this Proposed Rule
with respect to an interregional cost allocation method or methods.
---------------------------------------------------------------------------
\174\ See Appendix B for the proposed pro forma Attachment K
consistent with this NOPR.
---------------------------------------------------------------------------
180. The Commission would assess whether each compliance filing
satisfies the proposed requirements and principles stated above and
issue additional orders as necessary to ensure that each public utility
transmission provider meets the requirements of this Proposed Rule.
181. The Commission proposes that transmission providers that are
not public utilities would have to adopt the requirements of this
Proposed Rule as a condition of maintaining the status of their safe
harbor tariff or otherwise satisfying the reciprocity requirement of
Order No. 888.\175\
---------------------------------------------------------------------------
\175\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------
VII. Information Collection Statement
182. The following collection of information contained in this
Proposed Rule is subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\176\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\177\ The Commission
solicits comments on the Commission's need for this information,
whether the information will have practical utility, the accuracy of
the burden estimates, ways to enhance the quality, utility and clarity
of the information to be collected or retained, and any suggested
methods for minimizing respondents' burden, including the use of
automated information techniques.
---------------------------------------------------------------------------
\176\ 44 U.S.C. 3507(d).
\177\ 5 CFR 1320.11.
---------------------------------------------------------------------------
Burden Estimate: The estimated public reporting burdens for the
proposed reporting requirements are as follows:
----------------------------------------------------------------------------------------------------------------
Total annual
FERC-917--Proposed reporting Annual number Annual number Hours per Total annual hours in
requirements in RM10-23 of respondents of responses response hours in year subsequent
(Filers) 1 years
----------------------------------------------------------------------------------------------------------------
Participation in a transparent 134 134 100 hrs. in Year 13,400 6,700
and open intraregional 1; 50 hrs. in
transmission planning process subsequent
that meets transmission years.
planning principles, includes
consideration of public
policy requirements,
identifies and evaluates
facilities to meet needs,
develops cost allocation
method, and produces an
intraregional transmission
plan that describes and
incorporates a cost
allocation method that meets
the Commission's principles.
[[Page 37909]]
Coordination, development, and 134 134 125 hrs. in Year 16,750 6,700
filing with the Commission of 1; 50 hrs. in
interregional planning subsequent
agreements that meet the years.
Commission's requirements,
that include consideration of
public policy requirements,
and that incorporate cost
allocation methods that meets
the Commission's principles;
provide or post ongoing
communications, and provide
annual data exchange.
Conforming tariff changes for 134 134 50 hrs. in Year 6,700 3,350
local transmission planning, 1; 25 hours in
including those related to subsequent
consideration of public years.
policy requirements; and
conforming tariff changes for
intraregional and
interregional planning.
---------------------------------------------------------------------------------
Total Estimated Additional .............. .............. ................ 36,850 16,750
Burden Hours, Proposed
for FERC-917 in NOPR in
RM10-23.
----------------------------------------------------------------------------------------------------------------
Cost To Comply: The Commission has projected costs of compliance
for the reporting requirements as follows:
Year 1: $4,200,900 [36,850 hours x $114 per hour \178\]
---------------------------------------------------------------------------
\178\ The estimated cost of $114 an hour is the average of the
hourly costs of: attorney ($200), consultant ($150), technical
($80), and administrative support ($25).
---------------------------------------------------------------------------
Subsequent Years: $1,909,500 [or 16,750 hours x $114 per hour]
OMB's regulations require it to approve certain information collection
requirements imposed by an agency rule. The Commission is submitting
notification of this Proposed Rule to OMB. The Commission proposes to
make the reporting requirements mandatory.
Title: FERC-917.
Action: Proposed Collection.
OMB Control No. 1902-0233.
Respondents: Electric Utility Transmission Providers. RTOs and ISOs
also may file some materials on behalf of their members.
Frequency of responses: Initial filing and subsequent filings.
Necessity of the Information:
183. Building on the reforms in Order No. 890, the Federal Energy
Regulatory Commission is proposing amendments to the pro forma OATT to
correct certain deficiencies in transmission planning and cost
allocation requirements for public utility transmission providers. The
purpose of this proposed rulemaking is to strengthen the pro forma
OATT, so that the transmission grid can better support wholesale power
markets and ensure that Commission-jurisdictional services are provided
at rates, terms and conditions that are just and reasonable and not
unduly discriminatory or preferential. We propose to achieve this goal
by reforming electric transmission planning requirements and
establishing a closer link between cost allocation and regional
transmission planning processes.
184. Internal Review: The Commission has reviewed the proposed
changes and has determined that the changes are necessary. These
requirements conform to the Commission's need for efficient information
collection, communication, and management within the energy industry.
The Commission has assured itself, by means of internal review, that
there is specific, objective support associated with the information
requirements.
185. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, e-mail:
[email protected], Phone: (202) 502-8663, fax: (202) 273-0873. For
submitting comments concerning the collection of information and the
associated burden estimate(s), please send your comments to the contact
listed above and to the Office of Information and Regulatory Affairs,
Office of Management and Budget, 725 17th Street, NW., Washington, DC
20503 [Attention: Desk Officer for the Federal Energy Regulatory
Commission, phone: (202) 395-4638, fax: (202) 395-7285]. Due to
security concerns, comments should be sent electronically to the
following e-mail address: [email protected]. Please
reference OMB Control No. 1902-0233 and the docket number of this
proposed rulemaking in your submission.
VIII. Environmental Analysis
186. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\179\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Proposed Rule under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\180\
---------------------------------------------------------------------------
\179\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
\180\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------
IX. Regulatory Flexibility Act Analysis
187. The Regulatory Flexibility Act of 1980 (RFA) \181\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
This Proposed Rule applies to public utilities that own, control or
operate interstate transmission facilities other than those that have
received waiver of the obligation to comply with Order Nos. 888, 889
and 890. The total estimated number of public utility transmission
providers that, absent waiver, would have to modify their current OATTs
by filing the revised pro
[[Page 37910]]
forma OATT is 134. Of these public utility transmission providers, an
estimated 10 filers, or 7.3% percent, have output of four million MWh
or less per year.\182\ The Commission does not consider this a
substantial number and, in any event, each of these entities retains
its rights to waiver of these requirements. The criteria for waiver
that would be applied under this rulemaking for small entities is
unchanged from that used to evaluate requests for waiver under Order
Nos. 888, 889 and 890. Accordingly, the Commission certifies that the
proposed rule will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------
\181\ 5 U.S.C. 601-612.
\182\ A firm is ``small'' if, including its affiliates, it is
primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric
output for the preceding fiscal year did not exceed 4 million
megawatt hours. Based on the filers of the annual FERC Form 1 and
Form 1-F, as well as the number of companies that have obtained
waivers, we estimate that 7.3% of the filers are ``small.''
---------------------------------------------------------------------------
X. Comment Procedures
188. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due 60 days from publication in the
Federal Register. Comments must refer to Docket No. RM10-23-000, and
must include the commenter's name, the organization they represent, if
applicable, and their address in their comments.
189. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
190. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Office of the Secretary, 888 First
Street, NE., Washington, DC 20426.
191. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
XI. Document Availability
192. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
193. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
194. User assistance is available for eLibrary and the FERC's web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By direction of the Commission. Commissioner Moeller is
concurring with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
In consideration of the foregoing, the Commission proposes to amend
part 35, Chapter I, Title 18, Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES AND TARIFFS
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 71-7352.
2. Amend Sec. 35.28 as follows:
a. Paragraph (c)(1) introductory text and (c)(1)(i) through
(c)(1)(iii) are revised.
b. Paragraph (c)(1)(vi) is revised.
c. Paragraphs (c)(3) introductory text, (c)(3)(i), and (c)(3)(ii)
are revised.
d. Paragraph (c)(4) is revised.
e. Paragraph (d) (1) is revised.
f. Paragraph (e)(1) introductory text, is revised.
Sec. 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(c) Non-discriminatory open access transmission tariffs.
(1) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce must have on file with the Commission a tariff of general
applicability for transmission services, including ancillary services,
over such facilities. Such tariff must be the open access pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036 (Final
Rule on Open Access and Stranded Costs), as revised by the open access
pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ]
31,241 (Final Rule on Open Access Reforms) and further revised in Order
No. ------, FERC Stats. & Regs. ] ------ (Final Rule on Transmission
Planning and Cost Allocation by Transmission Owning and Operating
Public Utilities), or such other open access tariff as may be approved
by the Commission consistent with Order No. 888, FERC Stats. & Regs ]
31,306, Order No. 890, FERC Stats. & Regs. ] 32,241, and Order No. ----
--, FERC Stats. & Regs. ] ------.
(i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised by the open access pro forma tariff contained in Order No. 890,
FERC Stats. & Regs. ] 31,241 and further revised in Order No. ------,
FERC Stats. & Regs. ] ------, and accompanying rates, must be filed no
later than 60 days prior to the date on which a public utility would
engage in a sale of electric energy at wholesale in interstate commerce
or in the transmission of electric energy in interstate commerce.
(ii) If a public utility owns, controls, or operates facilities
used for the transmission of electric energy in interstate commerce as
of [60 days after date of publication of the Final Rule in the Federal
Register], it must file the revisions to the pro forma tariff contained
in Order No. 890, FERC Stats. & Regs. ] 31,241, as amended by Order
No.------, FERC Stats. & Regs. ] ------, pursuant to section 206 of the
FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs ] ------.
(iii) If a public utility owns, controls, or operates transmission
facilities used for the transmission of electric energy in interstate
commerce as of [60 days after date of publication of the Final Rule in
the Federal Register], such facilities are
[[Page 37911]]
jointly owned with a non-public utility, and the joint ownership
contract prohibits transmission service over the facilities to third
parties, the public utility with respect to access over the public
utility's share of the jointly owned facilities must file the revisions
to the pro forma tariff contained in Order No. 890, FERC Stats. & Regs.
] 31,241 as amended by Order No. ------, FERC Stats. & Regs. ] ------,
pursuant to section 206 of the FPA and accompanying rates pursuant to
section 205 of the FPA.
* * * * *
(vi) Any public utility that seeks a deviation from the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised in Order No. 890, FERC Stats. & Regs. ] 31,241 and Order No. --
----, FERC Stats. & Regs. ] ------, must demonstrate that the deviation
is consistent with the principles of Order No. 888, FERC Stats. & Regs.
] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. --
----, FERC Stats. & Regs. ] ------.
* * * * *
(3) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce, and that is a member of a power pool, public utility holding
company, or other multi-lateral trading arrangement or agreement that
contains transmission rates, terms or conditions, must have on file a
joint pool-wide or system-wide open access transmission tariff, which
tariff must be the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff contained
in Order No. 890, FERC Stats. & Regs. ] 31,241 and further revised in
Order No. ------, FERC Stats. & Regs. ] ------, or such other open
access tariff as may be approved by the Commission consistent with
Order No. 888, FERC Stats. & Regs. ] 31,036, Order No. 890, FERC Stats.
& Regs. ] 31,241, and Order No. ------, FERC Stats. & Regs. ] ------.
(i) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed after [60 days after
date of publication of the Final Rule in the Federal Register], this
requirement is effective on the date that transactions begin under the
arrangement or agreement.
(ii) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed on or before [60 days
after date of publication of the Final Rule in the Federal Register], a
public utility member of such power pool, public utility holding
company or other multi-lateral arrangement or agreement that owns,
controls, or operates facilities used for the transmission of electric
energy in interstate commerce must file the revisions to its joint
pool-wide or system-wide open access transmission tariff consistent
with Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by Order
No.------, FERC Stats. & Regs. ] ------, pursuant to section 206 of the
FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs ] ------.
* * * * *
(4) Consistent with paragraph (c)(1) of this section, every
Commission-approved ISO or RTO must have on file with the Commission a
tariff of general applicability for transmission services, including
ancillary services, over such facilities. Such tariff must be the pro
forma tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036,
as revised by the pro forma tariff contained in Order No. 890, FERC
Stats. & Regs. ] 31,241 and further revised in Order No. ------, FERC
Stats. & Regs. ] ------, or such other open access tariff as may be
approved by the Commission consistent with Order No. 888, FERC Stats. &
Reg. ] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order
No. ------, FERC Stats. & Regs. ] ------.
(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff
contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by
Order No. ------, FERC Stats. & Regs. ] ------, pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs. ] ------.
(ii) If a Commission-approved ISO or RTO can demonstrate that its
existing open access tariff is consistent with or superior to the
revisions to the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff in Order
No. 890, FERC Stats. & Regs. ] 31,241 and further revised in Order No.
------, FERC Stats. & Regs. ] ------, or any portions thereof, the
Commission-approved ISO or RTO may instead set forth such demonstration
in its filing pursuant to section 206 in accordance with the procedures
set forth in Order No., FERC Stats. & Regs. ] ------.
(d) Waivers. * * *
(1) No later than [60 days after date of publication of the Final
Rule in the Federal Register], or
* * * * *
(e) Non-public utility procedures for tariff reciprocity
compliance.
(1) A non-public utility may submit a transmission tariff and a
request for declaratory order that its voluntary transmission tariff
meets the requirements of Order No. 888, FERC Stats. & Regs. ] 31,036,
Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. ------, FERC
Stats. & Regs. ] ------.
* * * * *
Note: The following appendices will not be published in the
Code of Federal Regulations.
Appendix A--List of Short Names of Commenters on the Federal Energy
Regulatory Commission's Notice of Request for Comments on Transmission
Planning Processes Under Order No. 890--Docket No. AD09-8-000, October
2009
------------------------------------------------------------------------
Short name or acronym Commenter
------------------------------------------------------------------------
3M..................................... 3M Company, High Capacity
Conductors.
AEP.................................... American Electric Power Service
Corporation.
Alabama PSC............................ Alabama Public Service
Commission.
Allegheny Companies.................... Allegheny Power and Trans-
Allegheny Interstate Line
Company.
Ameren................................. Ameren Services Company.
American Antitrust Institute........... American Antitrust Institute.
American Forest and Paper.............. American Forest & Paper
Association.
American Transmission.................. American Transmission Company
LLC.
APPA................................... American Public Power
Association.
AREVA T&D.............................. AREVA T&D Inc.
[[Page 37912]]
AWEA................................... American Wind Energy
Association.
Baltimore Gas and Electric............. Baltimore Gas and Electric
Company.
Barbara Luchsinger..................... Barbara Luchsinger.
Bay Area Municipal Transmission Group.. City of Santa Clara,
California; the City of Palo
Alto, California; and the City
of Alameda, California.
Bonneville............................. Bonneville Power
Administration.
BP Energy.............................. BP Energy Company.
The Brattle Group...................... Peter Fox-Penner, Johannes
Pfeifenberger, and Delphine
Hou.
California ISO......................... California Independent System
Operator Corporation.
Californians for Renewable Energy...... Californians for Renewable
Energy, Inc.
California PUC......................... California Public Utilities
Commission.
California State Water Project......... California Department of Water
Resources State Water Project.
Calvin Daniels......................... Calvin Daniels.
Chinook and Zephyr..................... Chinook Power Transmission, LLC
and Zephyr Power Transmission,
LLC.
Clean Line............................. Clean Line Energy Partners,
LLC.
Coalition To Advance Renewable Energy Coalition To Advance Renewable
Through Bulk Energy Storage. Energy Through Bulk Energy
Storage.
ColumbiaGrid........................... ColumbiaGrid.
Consolidated Edison, et al............. Consolidated Edison Company of
New York, Inc. and Orange and
Rockland Utilities, Inc.
Dayton Power and Light................. Dayton Power and Light Company.
Delaware Municipal and Southwestern Delaware Municipal Electric
Electric. Corporation, Inc. and
Southwestern Electric
Cooperative, Inc.
Dominion............................... Dominion Resources Services,
Inc.
Duke................................... Duke Energy Corporation.
Eastern Interconnection Planning Eastern Interconnection
Collaborative Analysis Team. Planning Collaborative
Analysis Team.
Eastern PJM Governors.................. Governors of New Jersey,
Delaware, Maryland, and
Virginia.
EEI.................................... Edison Electric Institute.
Electricity Consumers Resource Council. Electricity Consumers Resource
Council.
ENE (Environment Northeast)............ ENE Environment Northeast.
Energy Future Coalition................ Energy Future Coalition.
Entergy................................ Entergy Services, Inc.
E.ON................................... E.ON U.S. LLC.
E.ON Climate & Renewables North America E.ON Climate & Renewables North
America.
EPSA................................... Electric Power Supply
Association.
Exelon................................. Exelon Corporation.
Federal Trade Commission............... Federal Trade Commission.
FirstEnergy............................ FirstEnergy Affiliates.
Florida Transmission Providers......... Florida Power & Light, Progress
Energy Florida, Tampa Electric
Company, and JEA.
Georgia Transmission Corporation....... Georgia Transmission
Corporation.
Great River Energy..................... Great River Energy.
Green Energy Express................... Green Energy Express, LLC.
Illinois Commission.................... Illinois Commerce Commission.
Imperial Irrigation District........... Imperial Irrigation District
(CA).
Independent Power Producers Coalition- Independent Power Producers
West. Coalition-West.
Indicated Partners..................... Green Energy Express LLC;
Transmission Technology
Solutions LLC; SouthWestern
Power Group II, LLC; Nevada
Hydro Company; LS Power
Transmission, LLC; and Pattern
Transmission LP.
Integrys, et al........................ Wisconsin Public Service
Corporation, Upper Peninsula
Power Company, and Integrys
Energy Services, Inc.
ISO New England........................ ISO New England Inc.
ITC Holdings........................... ITC Holdings Corp.
Kelson Companies....................... Cottonwood Energy Company LP;
Dogwood Energy LLC; and
Magnolia Energy LP.
Large Public Power Council............. Austin Energy; Chelan County
Public Utility District No. 1;
Clark Public Utilities;
Colorado Springs Utilities;
CPS Energy (San Antonio); IID
Energy; JEA (Jacksonville,
FL); Long Island Power
Authority; Lower Colorado
River Authority; MEAG Power;
Nebraska Public Power
District; New York Power
Authority; Omaha Public Power
District; Orlando Utilities
Commission; Platte River Power
Authority; Puerto Rico
Electric Power Authority;
Sacramento Municipal Utility
District; Salt River Project;
Santee Cooper; Seattle City
Light; Snohomish County Public
Utility District No. 1; and
Tacoma Public Utilities.
Long Island Power Authority, et al..... Long Island Power Authority,
Consolidated Edison Company of
New York, Inc., and Orange and
Rockland Utilities, Inc.
Lorraine Fleming....................... Lorraine Fleming.
LS Power............................... LS Power Transmission, LLC.
[[Page 37913]]
Maine PUC and Public Advocate.......... Maine Public Utilities
Commission and the Maine
Office of the Public Advocate.
Massachusetts Attorney General......... Massachusetts Attorney General.
Massachusetts Departments.............. Massachusetts Department of
Public Utilities and
Massachusetts Department of
Energy Resources.
MEAG Power............................. MEAG Power.
MidAmerican............................ MidAmerican Energy Holdings
Company.
Midwest ISO............................ Midwest Independent
Transmission System Operator,
Inc.
Midwest ISO Transmission Owners........ Ameren Services Company (as
agent for Union Electric
Company, Central Illinois
Public Service Company,
Central Illinois Light Co.,
and Illinois Power Company);
City of Columbia Water and
Light Department (Columbia,
MO); City Water, Light & Power
(Springfield, IL); Great River
Energy; Hoosier Energy Rural
Electric Cooperative, Inc.;
Indiana Municipal Power
Agency; Indianapolis Power &
Light Company; (Minnesota
Power (and its subsidiary
Superior Water, L&P); Montana-
Dakota Utilities Co.; Northern
Indiana Public Service
Company; Northern States Power
Company (Minnesota and
Wisconsin corporations);
Northwestern Wisconsin
Electric Company; Otter Tail
Power Company; Southern
Illinois Power Cooperative;
Southern Indiana Gas &
Electric Company; Southern
Minnesota Municipal Power
Agency; Wabash Valley Power
Association, Inc.; and
Wolverine Power Supply
Cooperative, Inc.
Modesto Irrigation District............ Modesto Irrigation District.
NARUC.................................. National Association of
Regulatory Utility
Commissioners.
National Audubon Society, et al........ National Audubon Society;
Conservation Law Foundation;
Energy Future Coalition; ENE
(Environment Northeast);
Environmental Defense Fund;
Natural Resources Defense
Council; Piedmont
Environmental Council; Sierra
Club; Sustainable FERC
Project; and Union of
Concerned Scientists.
National Grid.......................... National Grid USA.
National Nuclear Security National Nuclear Security
Administration Service Center. Administration Service Center
in Albuquerque, New Mexico.
National Rural Electric Coops.......... National Rural Electric
Cooperative Association.
NationalWind........................... NationalWind.
NEPOOL Participants.................... New England Power Pool
Participants Committee.
Nevada Hydro........................... Nevada Hydro Company, Inc.
New England Clean Energy Council....... New England Clean Energy
Council.
New England States' Committee on New England States' Committee
Electricity. on Electricity.
New Jersey Board....................... New Jersey Board of Public
Utilities.
New York ISO........................... New York Independent System
Operator, Inc.
New York PSC........................... New York State Public Service
Commission.
NextEra................................ NextEra Energy Resources, LLC.
Northeast Utilities.................... Northeast Utilities Service
Company.
Northern Tier Transmission Group....... Northern Tier Transmission
Group.
Northwest State Commissions and Idaho Public Utilities
Consumer Counsel. Commission, Montana Consumer
Counsel, Montana Public
Service Commission, Public
Utility Commission of Oregon,
Utah Public Service
Commission, and Wyoming Public
Service Commission.
NRG.................................... NRG Energy, Inc.
Ohio Commission........................ Public Utilities Commission of
Ohio.
Old Dominion........................... Old Dominion Electric
Cooperative.
Organization of MISO States............ Organization of MISO States.
Pacific Gas and Electric............... Pacific Gas and Electric
Company.
Pattern Transmission................... Pattern Transmission LP.
Peter C. Luchsinger M.D................ Peter C. Luchsinger M.D.
PHI Companies.......................... Pepco Holdings, Inc.; Potomac
Electric and Power Company;
Delmarva Power & Light
Company; and Atlantic City
Electric Company.
Pioneer Transmission................... Pioneer Transmission, LLC.
PJM.................................... PJM Interconnection, LLC.
PPL.................................... PPL Electric Utilities
Corporation.
Progress Energy........................ Progress Energy, Inc.
PSEG Companies......................... Public Service Electric and Gas
Company; PSEG Power LLC; PSEG
Energy Resources & Trade LLC.
[[Page 37914]]
Public Interest Organizations & Alliance for Clean Energy New
Renewable Energy Groups. York; American Wind Energy
Association; Center for Energy
Efficiency & Renewable
Technologies; Citizens Utility
Board of Wisconsin;
Conservation Law Foundation;
Environmental Defense Fund;
Environmental Law & Policy
Center; Fresh Energy; National
Audubon Society; Natural
Resources Defense Council;
Northeast Energy Efficiency
Partnerships; Northwest Energy
Coalition; Office of the Ohio
Consumers' Counsel; Pace
Energy and Climate Center;
Piedmont Environmental
Council; Project for
Sustainable FERC Energy
Policy; Sierra Club; Southern
Alliance for Clean Energy;
Union of Concerned Scientists;
Western Grid Group; and Wind
on the Wires.
Public Power Council................... Public Power Council.
Renewable Energy Systems Americas...... Renewable Energy Systems
Americas Inc.
RRI Energy............................. RRI Energy, Inc.
Salt River Project..................... Salt River Project Agricultural
Improvement and Power
District.
San Diego Gas & Electric............... San Diego Gas & Electric
Company.
Solar Energy Industries................ Solar Energy Industries
Association.
South Carolina Electric & Gas.......... South Carolina Electric & Gas
Company.
Southern California Edison............. Southern California Edison
Company.
Southern Companies..................... Southern Company Services, Inc.
SPP.................................... Southwest Power Pool, Inc.
Startrans.............................. Startrans IO, LLC.
Starwood............................... Starwood Energy Group Global,
LLC.
State Representative Sloan............. State Representative Tom Sloan.
Sunflower and Mid-Kansas............... Sunflower Electric Power
Corporation and Mid-Kansas
Electric Company, LLC.
Trans-Elect............................ Trans-Elect Development
Company, LLC.
Transmission Access Policy Study Group. Transmission Access Policy
Study Group.
Transmission Agency of Northern Transmission Agency of Northern
California. California.
Transmission Dependent Utility Systems. Arkansas Electric Cooperative
Corporation, Golden Spread
Electric Cooperative, Inc.,
Kansas Electric Power
Cooperative, Inc., North
Carolina Electric Membership
Corporation, Old Dominion
Electric Cooperative, and
Seminole Electric Cooperative,
Inc.
Upper Great Plains Transmission Upper Great Plains Transmission
Coalition. Coalition.
WECC................................... Western Electricity
Coordinating Council.
WestConnect Planning Parties........... Arizona Public Service Company,
Basin Electric Power
Cooperative, Black Hills
Corporation, El Paso Electric
Company, Imperial Irrigation
District, NV Energy, Public
Service Company of Colorado,
Public Service Company of New
Mexico, Sacramento Municipal
Utility District, Salt River
Project Agricultural
Improvement and Power
District, Southwest
Transmission Cooperative,
Inc., Transmission Agency of
Northern California, Tri-State
Generation and Transmission
Association, Inc., Tucson
Electric Power Company.
WIRES.................................. Working Group for Investment in
Reliable and Economic Electric
Systems.
Xcel................................... Xcel Energy Services Inc.
------------------------------------------------------------------------
Appendix B: Pro Forma Open Access Transmission Tariff
Attachment K
Transmission Planning Process
Local Transmission Planning
The Transmission Provider shall establish a coordinated, open
and transparent planning process with its Network and Firm Point-to-
Point Transmission Customers and other interested parties to ensure
that the Transmission System is planned to meet the needs of both
the Transmission Provider and its Network and Firm Point-to-Point
Transmission Customers on a comparable and not unduly discriminatory
basis. The Transmission Provider's coordinated, open and transparent
planning process shall be provided as an attachment to the
Transmission Provider's Tariff.
The Transmission Provider's planning process shall satisfy the
following nine principles, as defined in the Final Rule in Docket
No. RM05-25-000: Coordination, openness, transparency, information
exchange, comparability, dispute resolution, regional participation,
economic planning studies, and cost allocation for new projects. The
planning process shall also include the procedures and mechanisms
for evaluating transmission projects proposed to achieve public
policy requirements established by State or Federal laws or
regulations consistent with the Final Rule in Docket No. RM10-23-
000. The planning process shall also provide a mechanism for the
recovery and allocation of planning costs consistent with the Final
Rule in Docket No. RM05-25-000.
The description of the Transmission Provider's planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for consulting with customers and neighboring
transmission providers;
(ii) The notice procedures and anticipated frequency of
meetings;
(iii) The methodology, criteria, and processes used to develop a
transmission plan;
(iv) The method of disclosure of criteria, assumptions and data
underlying a transmission plan;
(v) The obligations of and methods for Transmission Customers to
submit data to the Transmission Provider;
[[Page 37915]]
(vi) The dispute resolution process;
(vii) The Transmission Provider's study procedures for economic
upgrades to address congestion or the integration of new resources;
(viii) The Transmission Provider's procedures and mechanisms for
evaluating transmission projects proposed to achieve public policy
requirements established by State or Federal laws or regulations;
and
(ix) The relevant cost allocation method or methods.
Intraregional Transmission Planning
The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission solutions may be proposed and evaluated. The
regional transmission planning process also shall develop a regional
transmission plan that identifies the transmission facilities
necessary to meet the needs of transmission providers and
transmission customers in the transmission planning region. The
regional transmission planning process must not be unduly
discriminatory and must be consistent with the provision of
Commission-jurisdictional services at rates, terms and conditions
that are just and reasonable, as described in the Final Rule in
Docket No. RM10-23-000. The regional transmission planning process
shall be described in an attachment to the Transmission Provider's
Tariff.
The Transmission Provider's regional transmission planning
process shall satisfy the following seven principles, as set out and
explained in the Final Rule in Docket No. RM05-25-000: coordination,
openness, transparency, information exchange, comparability, dispute
resolution, and economic planning studies. The regional transmission
planning process shall also include the procedures and mechanisms
for evaluating transmission projects proposed to achieve public
policy requirements established by State or Federal laws or
regulations consistent with the Final Rule in Docket No. RM10-23-
000. The regional transmission planning process shall provide a
mechanism for the recovery and allocation of planning costs
consistent with the Final Rule in Docket No. RM05-25-000.
Nothing in the regional transmission planning process shall
include an unduly discriminatory process for transmission project
submission and selection. The regional transmission planning process
shall provide on a not unduly discriminatory basis for the sponsor
of a facility that is selected through the regional transmission
planning process for inclusion in the regional transmission plan to
have a right, consistent with State or local laws or regulations, to
construct and own that facility and to recover the cost of that
facility through the applicable regional cost allocation method.
The description of the regional transmission planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for consulting with customers;
(ii) The notice procedures and anticipated frequency of
meetings;
(iii) The methodology, criteria, and processes used to develop a
transmission plan;
(iv) The method of disclosure of criteria, assumptions and data
underlying transmission plan;
(v) The obligations of and methods for transmission customers to
submit data;
(vi) The dispute resolution process;
(vii) The study procedures for economic upgrades to address
congestion or the integration of new resources;
(viii) The procedures and mechanisms for evaluating transmission
projects proposed to achieve public policy requirements established
by State or Federal laws or regulations; and
(ix) The relevant cost allocation method or methods.
The regional transmission planning process must include a cost
allocation method or methods that satisfy the six principles set
forth in the final rule in Docket No. RM10-23-000.
Interregional Transmission Planning
The Transmission Provider, through its regional transmission
planning process, must coordinate with the public utility
transmission providers in each neighboring transmission planning
region within its interconnection to address transmission planning
issues related to interregional transmission facilities. This
coordination between each pair of transmission planning regions must
be reflected in an interregional transmission planning agreement
filed with the Commission. The interregional transmission planning
agreement must include a detailed description of the process for
coordination between public utility transmission providers in
neighboring transmission planning regions (i) With respect to each
interregional transmission facility that is proposed to be located
in both transmission planning regions and (ii) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently than separate intraregional
transmission facilities.
The Transmission Provider must ensure that the following
elements are included in any interregional transmission planning
agreement in which it participates:
(1) A commitment to coordinate and share the results of each
transmission planning region's regional transmission plans to
identify possible interregional facilities that could address
transmission needs more efficiently than separate intraregional
facilities;
(2) An agreement to exchange at least annually planning data and
information;
(3) A formal procedure to identify and jointly evaluate
transmission facilities that are proposed to be located in both
transmission planning regions; and
(4) A commitment to maintain a website or e-mail list for the
communication of information related to the coordinated planning
process.
The Transmission Provider must work with transmission providers
located in neighboring transmission planning regions to develop a
mutually agreeable method or methods for allocating between the two
transmission planning regions the costs of a new interregional
transmission facility that is located within both transmission
planning regions. Such cost allocation method or methods must
satisfy the six principles set forth in the final rule in Docket No.
RM10-23-000.
United States of America Federal Energy Regulatory Commission
Transmission Planning and Cost Allocation by Transmission Owning and
Operating Public Utilities
Docket No. RM10-23-000
Issued June 17, 2010.
MOELLER, Commissioner, concurring:
As I have repeatedly stressed in my years on this Commission,
promoting investment in our nation's transmission infrastructure has
been my top policy priority.\1\ Robust electric transmission
infrastructure is the ultimate ``enabling'' energy technology, as it
can provide a more efficient electric system, enhanced reliability,
increased access to less expensive and often cleaner resources, and
the ability to harness location-constrained renewable resources.
Conversely, the lack of adequate transmission investments often
disproportionately raises consumer rates due to congestion,
threatens the reliability of the nation's bulk power system, and
increases reliance on older and dirtier generating resources.
---------------------------------------------------------------------------
\1\ NSTAR Elec. Co., 125 FERC ] 61,313 (2008) (Moeller, Comm'r,
dissenting in part) (``* * * the Commission should do what it can to
encourage capital investment in needed transmission infrastructure
projects.''); Commonwealth Edison Co. and Commonwealth Edison Co. of
Indiana, 125 FERC ] 61,250 (2008) (Moeller, Comm'r, dissenting) (``*
* * now is not the time for this Commission to discourage investment
in needed transmission infrastructure.''); New York Indep. Sys.
Operator, Inc., 129 FERC ] 61,045 (2009) (Moeller, Comm'r,
dissenting) (``The main issue here is whether needed transmission is
being built * * * I have encouraged investment in transmission
infrastructure * * *''); Southern California Edison Co., 129 FERC ]
61,013 (2009) (Moeller, Comm'r, dissenting in part) (``The
transmission that is needed in this nation will not be built unless
the companies that build it can attract adequate investment
dollars.'')
---------------------------------------------------------------------------
While I am not certain that every policy in this proposed rule
will ultimately be adopted, I am certain that building needed
transmission lines is often the lowest-cost way to improve the
delivery of electricity service. Although the Commission could have
addressed regional cost allocation several years ago when it first
became apparent that the organized markets were not reaching
consensus on the issue, that wait is over and the Commission is now
considering specific proposals to resolve cost allocation.
Given that the U.S. Congress is examining cost allocation at
this time, our issuance of this proposed rule comes at a potentially
sensitive time. While Congress is now considering several measures
that deal directly with issues addressed in this proposed rule, I
expect that this Commission will defer to the legislative branch as
we move forward in our deliberations. This proposed rule, and the
comments to follow, will provide the Congress with the
[[Page 37916]]
framework of the issues that we consider relevant and the
opportunity for Congress to provide further guidance to us. Thus,
our action today is not intended to interfere with that process, but
rather to add helpful information and evidence that will be useful
in the formation of Federal legislation.
Also controversial will be the question of whether incumbent
utilities should retain rights of first refusal that were created
under the Commission's jurisdiction. Alas, the question of whether
transmission developers can compete on par with an incumbent
transmission-owning utility is no longer theoretical. In recent
cases, the Commission has been confronted with particular situations
where competitors could be discouraged (or altogether blocked) from
building a transmission project if the incumbent utility retains the
right of first refusal.\2\ While initial rulings have been rendered
in these cases, the generic issue is ready for further discussion in
this rulemaking.
---------------------------------------------------------------------------
\2\ Primary Power, LLC, 131 FERC ] 61,015 (2010) (reh'g pending)
and Cent. Transmission, LLC v. PJM Interconnection L.L.C., 131 FERC
] 61,243 (2010).
---------------------------------------------------------------------------
Resolving controversial issues is rarely easy and I expect
today's proposed rule to be both lauded and criticized. The changes
proposed here are significant, but the future success of the
organized markets and the nation's electric transmission system
depend on resolving these long-debated and controversial issues.
Staff's efforts here have resulted in a proposal that will lead
to a much needed conversation on how to best encourage needed
capital investment. This will not be an easy matter to address when
it comes before the Commission for a vote on the final rule, and for
that reason this Commission should carefully consider the comments
that we will receive. I will do my part to ensure that this
Commission does not lose sight of the ultimate goal: A final rule
that results in needed capital investment.
D. Moeller,
Commissioner.
[FR Doc. 2010-15735 Filed 6-29-10; 8:45 am]
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