Document ID: FERC-2010-0912-0001
Agency: ferc
Document Type: Proposed Rule
Title: Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities
Posted Date: 2010-06-30T04:00Z

[Federal Register: June 30, 2010 (Volume 75, Number 125)]
[Proposed Rules]               
[Page 37883-37916]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30jn10-21]                         

[[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

[[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

[[Page 37885]]

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

[[Page 37887]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \42\ PJM Interchange, News Release, May 14, 2010.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \43\ E.g., Baltimore Gas and Electric, Eastern PJM Governors, 
ITC Holdings, LS Power, National Grid, Old Dominion, PJM, and Trans-
Elect.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \47\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 441.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \50\ Id. P 524.
    \51\ Id. P 528.
    \52\ Id. P 526.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \60\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 542.
    \61\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \64\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 547-48.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \65\ Id. P 574.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \78\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 479, 
n.274.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \79\ October 2009 Notice at 3.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \80\  Id. at 4.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \83\ E.g., Green Energy Express, ITC Holdings, Pattern 
Transmission, and Starwood.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \85\ E.g., Ameren, MidAmerican, and Midwest ISO Transmission 
Owners.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \87\ Transmission Agency of Northern California at 3.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \88\ E.g., Green Energy Express and Pattern Transmission.
    \89\ E.g., Indicated Partners and Startrans.
    \90\ E.g., Indicated Partners.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \91\ Exelon at 12.
    \92\ E.g., Allegheny Companies, Dominion, Large Public Power 
Council, and SPP.
    \93\ E.g., Indicated Partners.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \94\ EEI at 9-10.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \114\ San Diego Gas & Electric at 5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \115\ Pioneer Transmission at 1-2.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \123\ Id. P 558.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \124\ Id. P 559.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \141\ E.g., AEP, ITC Holdings, and Exelon.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
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    (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\
---------------------------------------------------------------------------

    \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: 
DataClearance@ferc.gov, 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: oira_submission@omb.eop.gov. 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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

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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