September 30, 2011
Practice Group:
Order No. 1000: The Next Frontier in
Transmission Planning and Cost Allocation
Energy
By Donald A. Kaplan, William M. Keyser, Andrew B. Young, Molly Suda
The Federal Energy Regulatory Commission (“Commission”) issued its highly anticipated final rule
on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities on July 21, 2011 (“Order No. 1000”). This landmark rulemaking dramatically changes the
electric transmission planning process by requiring all transmission providers to: (1) eliminate from
Commission-jurisdictional tariffs any incumbent transmission owner right of first refusal (“ROFR”)
for transmission construction and adopt procedures to allow for the submission of new regional
transmission projects; (2) require the consideration in the transmission planning process of
transmission needs driven by public policy requirements; (3) participate in a regional planning process
that has a regional cost allocation methodology; and (4) coordinate with neighboring regions to
develop an interregional planning process and cost allocation methodology. However, rather than
include specific mechanisms that transmission providers must adopt to implement these changes,
Order No. 1000 instead establishes principles for regional and interregional transmission planning
processes and cost allocation, leaving a substantial amount of flexibility for industry stakeholders to
negotiate and develop the specific tariff provisions and procedures that will govern transmission
planning and cost allocation for their region. Additionally, at Order No. 1000 informational
conferences on September 12-13, 2011, Commission staff stressed the flexibility under Order No.
1000 to negotiate and propose varied and innovative processes that the Commission can review upon
the submission of compliance filings. Commission staff was reluctant to suggest or comment on
specific details that would satisfy compliance obligations. The intended flexibility of Order No. 1000,
combined with its lack of specificity, will likely result in significant controversy in the development of
compliance tariff filings as competing groups argue over what satisfies the Commission’s
requirements. The Commission is also currently processing more than 60 separate requests for
rehearing, and appellate challenges are likely. Thus, stakeholders should recognize that issuance of
the rule is only the first step in what is sure to be a long, arduous negotiation and implementation
process that will likely be subject to a variety of legal challenges along the way.
I. Required Compliance Filings
Order No. 1000 places a number of new requirements on jurisdictional transmission providers, which
must be satisfied in one of two compliance filings to be filed with the Commission by either October
11, 2012 (one year after Order No. 1000’s effective date) or April 11, 2013 (18 months after the
effective date).
By October 11, 2012, transmission providers must submit compliance filings to the Commission that:
 Remove from Commission-jurisdictional tariffs and agreements any ROFR to construct
transmission facilities that are included in a regional plan for the purposes of cost allocation;1
1
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 76 Fed. Reg.
49,842, at P 313 (Aug. 11, 2011).
Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
 Include criteria to evaluate whether entities, specifically non-incumbent transmission developers
(i.e., those without a retail distribution territory or those proposing transmission outside of their
territory), qualify to propose projects for inclusion in the regional transmission plan, together with
procedures for submission of proposed projects and a transparent process for the evaluation of
those projects;2
 Reflect participation in a regional transmission planning process that produces a regional
transmission plan;3
 Provide procedures for the transmission provider and interested stakeholders to identify
transmission needs driven by public policy requirements (e.g., renewable portfolio standards) and
to evaluate transmission enhancements and solutions to address such requirements;4 and
 Include a method or set of methods for allocating the costs of new transmission facilities selected
in the regional transmission plan (“regional cost allocation”) consistent with the following six cost
allocation principles: (1) costs must be allocated roughly commensurate with benefits; (2) those
who do not receive any benefit must not be involuntarily allocated any of the costs; (3) any benefit
to cost threshold ratio employed may not exceed 1.25 absent Commission approval; (4) costs must
be allocated only within the transmission planning region(s) unless voluntarily assumed; (5) cost
allocation methods must be transparent and documented; and (6) different cost allocation methods
may be used for different types of facilities.5
By April 11, 2013, transmission providers must submit compliance filings to the Commission that
include:
 A common set of procedures developed with each neighboring transmission planning region to
identify and evaluate interregional transmission facilities, including a description of the type of
transmission studies that will be conducted and a timeframe within which regions must jointly
evaluate interregional transmission projects, as well as specific obligations for sharing planning
data and information;6 and
 A method or set of methods for allocating the costs of new interregional transmission facilities that
are consistent with the six cost allocation principles (described above) and that two or more
neighboring transmission planning regions determine resolve the individual needs of each region in
an efficient and cost-effective manner (“interregional cost allocation”). The tariffs of all public
utility transmission providers in a region must include the same cost allocation method or methods
adopted by the region.7
II. Potential Issues during the Compliance Filing Process
To satisfy Order No. 1000’s compliance filing obligations, transmission providers and industry
stakeholders will need to engage in substantial negotiation, which will undoubtedly give rise to
contentious debates. The informational conferences held in September 2011 reiterated the fact that the
2
Id. at P 323.
3
Id. at P 146.
4
Id. at P 203.
5
Id. at PP 558, 603.
6
Id. at P 396.
7
Id. at PP 578, 603.
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Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
Commission is looking to the regions to resolve disputes over the compliance filings as part of the
stakeholder process to implement the requirements of Order No. 1000. Rather than provide further
interpretation of how Order No. 1000 should be implemented, the Commission staff’s presentations
focused more on reiterating the criteria set forth in Order No. 1000 that must be addressed in the
compliance filings. Thus, the burden is on the stakeholders in each of the different regions to reach
consensus on how the criteria should be interpreted and implemented. Some of the major areas in
which controversy among stakeholders can be expected are summarized below.
A. Development of Specific Criteria Regarding ROFR Removal and Inclusion of
Public Policy Projects despite the Commission’s Lack of Guidance
1. Right of First Refusal
As part of compliance with the requirement to remove ROFR provisions from Commissionjurisdictional tariffs, transmission providers must develop criteria that entities must satisfy to be
eligible to submit projects for consideration in the regional planning process. Development of these
criteria will likely entail significant disagreements and controversy between incumbent transmission
owners that support continuation of the ROFR and non-incumbent transmission developers that
support its removal. Incumbent transmission owners will likely push for criteria that restrict the pool
of potential applicants that qualify to propose projects for inclusion in the regional transmission plan,
while non-incumbent developers will advocate for more lenient criteria to ensure that they are not
excluded from the transmission planning process. Also, many ROFR supporters believe that the
Commission’s arguments supporting its authority to eliminate the ROFR are weak and have sought
rehearing of this issue. There is a reasonable likelihood that no consensus will be reached, and
competing sets of criteria and implementation details will be filed for the Commission’s consideration.
Thus, the cloud of uncertainty will likely hang over the compliance process until appeals of Order No.
1000 are ultimately resolved by the courts.
2. Public Policy Projects
The Commission required consideration of public policy requirements in the transmission planning
process over strong opposition. However, the Commission provided limited guidance on specific
procedures to identify and evaluate transmission enhancements and solutions driven by public policy
requirements. This lack of guidance will likely result in contentious debate among industry
stakeholders. As in the case of the ROFR, stakeholders that opposed the inclusion of public policy
requirements in the planning process may seek to use the compliance process as a means to
significantly reduce the effect of this requirement in their respective regions. In large regional
planning areas, stakeholders’ perceived need for and support of public policy requirements will vary
greatly. Transmission providers, especially regional transmission organizations (“RTO”) or
independent system operators (“ISO”), often span several states, not all of which have adopted
renewable portfolio standards. Transmission providers will need to address these differing
perspectives as they develop comprehensive planning requirements for inclusion of public policy
requirements that will govern the entire region. This divide will be further exacerbated as
transmission providers seek to develop cost allocation methodologies for public policy transmission
projects that properly identify the entities that benefit from and should therefore bear the costs for
large transmission projects driven by public policy requirements. Customers in states without
renewable portfolio standards will likely oppose bearing any costs for transmission projects required
to accommodate the interconnection of qualified renewable projects. Moreover, in response to
questions during the informational conference, Commission staff indicated that the transmission
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Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
planning regions could look to the state regulatory bodies to identify the public policy initiatives that
transmission providers must address. Regions adopting this approach will provide a greater role for
state agencies in the regional planning process, which may further complicate compliance.
B. Effect on Existing Transmission Planning Processes and Cost Allocation
Reforms
In Order No. 1000, the Commission repeatedly rejected requests to address whether existing tariff
procedures and provisions would satisfy the new transmission planning and cost allocation
requirements. Rather, the Commission required each transmission provider to demonstrate in a
compliance filing how those policies satisfy Order No. 1000. Many RTOs/ISOs have recently
reformed their cost allocation mechanisms. The status of several of these reforms is described below.
 MISO: The Midwest Independent System Operator, Inc.’s (“MISO”) current transmission
planning process, which includes cost allocation for public policy projects (referred to as Multi
Value Projects) to all load in and exports from MISO (with the exception of exports to serve load
in PJM Interconnection, L.L.C. (“PJM”)) on a postage-stamp basis, was accepted by the
Commission and is currently pending before the Commission on rehearing.8
 PJM: Cost allocation rules for transmission facilities above 500 kV are back before the
Commission on remand from the Seventh Circuit. The Commission has established paper hearing
procedures and requested additional information from PJM regarding its proposal, which provides
for postage stamp cost allocation for new transmission facilities at or above 500 kV, but does not
include provisions to address cost allocation for public policy initiatives.9 The issues have been
fully briefed and are awaiting a decision from the Commission.
 SPP: The Commission has accepted Southwest Power Pool, Inc.’s Integrated Transmission Plan
(“ITP”).10 The ITP employs the Highway/Byway cost allocation, which is based on voltage level
in which high voltage facilities (300 kV and above) are allocated 100% to the regional rate, midtier facilities (100 kV-300kV) are allocated 1/3 to the regional rate and 2/3 on a zonal basis, and
low voltage facilities (at or below 100 kV) are allocated entirely to the zonal rate. Rehearing of the
Commission’s approval of the specifics of the Highway/Byway cost allocation method is
pending.11
 CAISO: The California Independent System Operator Corporation (“CAISO”) planning process,
which allows for the identification of policy-driven transmission facilities needed to meet state or
federal policy requirements or directives, was accepted by the Commission subject to
compliance.12 As is currently done with reliability projects and economically-driven elements, the
costs of policy-driven facilities that are included in the approved comprehensive transmission plan
will be socialized to all CAISO transmission customers through CAISO’s transmission access
charge. Requests for rehearing and clarification are pending before the Commission.
8
Midwest Indep. Transmission Sys. Operator, 133 FERC ¶ 61,221 (2010).
9
PJM Interconnection, L.L.C., 130 FERC ¶ 61,233 (2010); PJM Interconnection, L.L.C., Response of PJM
Interconnection, L.L.C. to Information Requests, Docket No. EL05-121-006 (filed Apr. 13, 2010).
10
Southwest Power Pool, Inc., 132 FERC ¶ 61,042 (2010); order on reh’g and clarification, 136 FERC ¶ 61,050 (2011).
11
Southwest Power Pool, Inc., 131 FERC ¶ 61,252 (2010), reh’g pending.
12
California Indep. Sys. Operator Corp., et al., 133 FERC ¶ 61,224 (2010).
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Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
 NYISO: The Commission has approved the proposal of the New York Independent System
Operator, Inc. (“NYISO”), which includes an economic planning process aimed at removing
transmission constraints that do not violate reliability criteria but impede efficient transmission and
a supermajority vote requirement for cost allocation and recovery.13 NYISO’s proposal does not
include provisions to address cost allocation for public policy initiatives.
 ISO-NE: The ISO New England Inc. (“ISO-NE”) regional system planning process providing for
the socialization of costs for reliability upgrades and the allocation of costs for economic upgrades
based on a beneficiary-pays approach was accepted by the Commission.14 ISO-NE’s proposal
does not include provisions to address cost allocation for public policy initiatives.
Order No. 1000 does not address the question of how much deference should be afforded to existing
policies or reforms based on prior Commission approvals or court decisions. Many of these recent
reforms did not receive unanimous stakeholder support. The Commission’s refusal to state whether
existing tariff procedures and provisions comply with the new rule may open the door to re-litigation
of previously accepted tariff provisions. While the RTOs/ISOs will likely defer to their current
transmission planning and cost allocation processes, stakeholders who opposed the current regime are
likely to view this as an opportunity to challenge the current regime. Thus, the development of
compliance filings may be very contentious and will likely result in more litigation as stakeholders
seek to challenge whether the existing mechanisms comply with the requirements of Order No. 1000.
C. Unique Challenges for Regional Planning Areas Outside of an RTO
Many of the regional planning areas outside of the RTOs that were formed in response to Order No.
890 are, by design, not as well developed as the more structured RTO regional planning processes.
These regions may not have developed a regional planning process that produced a regional plan and
instead have relied upon the transmission owners and stakeholders in the region to propose regional
projects for consideration. Similarly, rather than adopt structured regional cost allocation
methodologies, many of these regions have instead relied upon a participant funding-based structure
that mirrors their cost allocation methodologies for planning local transmission projects. However,
Order No. 1000 requires each region to develop a regional planning process that produces an annual
transmission plan. The order rejected use of participant funding for regional and interregional cost
allocation. Thus, the transmission owners outside of an RTO will now need to grapple with many of
the same controversies that have been plaguing the RTOs in recent years. This process will be further
complicated by the lack of an independent central transmission planning body and the fact that
transmission providers and, in turn, their customers may be faced for the first time with costs for
projects that are built by other transmission owners in other parts of their planning region.
These issues are magnified in areas where non-jurisdictional utilities play a major role in the
transmission planning process. In the Pacific Northwest, the Bonneville Power Administration, which
owns almost 80 percent of all high-voltage transmission in the region, has indicated that it will
independently determine whether it will receive the benefits and pay the costs of a transmission
facility selected for cost allocation in a regional transmission planning process. This will make it
13
New York Indep. Sys. Operator, Inc., 125 FERC ¶ 61,068 (2008), order on reh’g, 126 FERC ¶ 61,320 (2009), order
denying late intervention and dismissing request for rehearing, 127 FERC ¶ 61,136 (2009), reh’g denied, 129 FERC ¶
61,045 (2009), order on compliance, 129 FERC ¶ 61,044 (2009), order on compliance, 132 FERC ¶ 61,028 (2010), order
on compliance, 132 FERC ¶ 61,188 (2010).
14
ISO New England Inc., 123 FERC ¶ 61,161 (2008), order denying late intervention and dismissing request for
rehearing, 124 FERC ¶ 61,097 (2008), order on compliance, 127 FERC ¶ 61,170 (2009).
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Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
difficult, if not impossible, for transmission providers in the Pacific Northwest to develop a regional
transmission planning process that complies with the requirements of Order No. 1000.
D. Distinction between Interregional Transmission Facilities and Transmission
Facilities with Interregional Benefits
Order No. 1000 requires neighboring transmission planning regions to coordinate and develop a
common method for allocating the costs of a new interregional transmission facility among the
beneficiaries of that transmission facility in the regions where the facility is located. However, the
Commission also explained that a public utility may not allocate any costs of a transmission facility
that is located entirely within the utility’s transmission planning region (but that potentially has
interregional benefits) to a neighboring transmission region involuntarily using the interregional cost
allocation methodology adopted by the two regions. Rather, the transmission provider must reach
agreement with the potential beneficiaries in the neighboring region to accept the costs before
allocating costs to them. This differential treatment of interregional transmission facilities that
physically bridge transmission planning regions, on the one hand, and transmission facilities with
interregional benefits but that are located within a single transmission planning region, on the other
hand, may complicate discussions with industry stakeholders.
III. Conclusion
Building from prior Commission orders, Order No. 1000 is a major next step in the evolution of
transmission planning and cost allocation, and is sure to have a lasting and widespread effect.
However, the details that will determine the specific impact of Order No. 1000 on individual industry
stakeholders remain largely undefined and subject to substantial negotiation and legal challenge at the
Commission and in the courts. Thus, stakeholders in each of the various planning regions across the
country should be prepared to participate in contentious proceedings over the next several years as
transmission providers attempt to reach stakeholder consensus on their compliance filings.
Authors:
Donald A. Kaplan
donald.kaplan@klgates.com
+1.202.661.6266
William M. Keyser
william.keyser@klgates.com
+1.202.661.3863
Andrew B. Young
andrew.young@klgates.com
+1.202.778.9125
Molly Suda
molly.suda@klgates.com
+1.202.778.9452
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Order No. 1000: The Next Frontier in Transmission
Planning and Cost Allocation
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