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					PORTLAND GENERAL ELECTRIC PLANNING STRAWMAN –                                                   6/1/2007
(Revision #1)

Portland General Electric (“PGE”) has developed this strawman proposal for compliance with
each of the nine planning principles adopted in FERC Order 8901. This strawman also specifies
the region and sub-region in which PGE plans to perform coordinated planning. This strawman
has been developed with stakeholder input, received during an open meeting held on May 4,
2007, during which PGE discussed the new and existing forums and processes in which PGE
could participate to meet the nine planning principles. PGE held a second meeting on May 16,
2007, giving stakeholders and customers the opportunity to offer comments and suggestions on
the draft PGE strawman proposal. PGE considered the comments received at both meetings in
developing this strawman proposal.

PGE’s planning strawman proposal describes how PGE intends to conduct planning in a manner
that incorporates the nine planning principles adopted in Order 890. PGE believes the first three
planning principles identified in Order 890 -- coordination, openness and transparency -- are the
foundation upon which the remaining six planning principles rest. PGE’s proposal outlines the
processes and forums that we intend to use to address the latter six planning principles. It also
describes how we intend to satisfy the three foundational planning principles. Therefore we will
address the nine planning principles in the following order:

    1.   REGIONAL PARTICIPATION
    2.   ECONOMIC PLANNING STUDIES
    3.   INFORMATION EXCHANGE
    4.   COST ALLOCATION
    5.   DISPUTE RESOLUTION
    6.   COMPARABILITY
    7.   COORDINATION
    8.   OPENNESS
    9.   TRANSPARENCY




1
 Preventing Undue Discrimination and Preference in Transmission Service, 118 FERC ¶ 61,119 (2007) (“Order
890”).



PGE Planning Strawman 6/1/2007 (Revision #1)                                                  Page 1 of 12
1. REGIONAL PARTICIPATION
Because PGE’s proposal with regard to the principle of Regional Participation also describes the
broader regions in which PGE will conduct coordinated regional planning, we discuss this
principle first. PGE proposes that regional participation in the planning process take place on
three levels; regional, sub-regional and local.

       Regional
       Regional planning participation should take place at the Western Electricity Coordinating
       Council (“WECC”). The WECC has made great strides in the coordination of planning
       at a regional level for both reliability and economic issues. With the formation of the
       Transmission Expansion Planning Policy Committee (“TEPPC”), WECC provided a
       greatly needed, dedicated forum in which economic or congestion related projects can be
       discussed. The TEPPC was supplemental to the existing reliability forums and processes
       within the WECC which coordinated regional transmission plans. The pre-existing
       processes include the Annual Progress Reports, the annual Significant Additions Report,
       and the Regional Review Process, all facilitated by the Planning Coordination Committee
       (“PCC”). These processes provide a means by which market participants who are WECC
       members can review and comment on draft transmission plans.

       Sub-regional
       Due to physics and commerce, the entire Columbia River basin should be the smallest
       possible sub-regional planning footprint in the Northwest. While PGE is of the strong
       opinion that this in the proper footprint for transmission planning purposes, the current
       reality is the presence of two separate entities with diverse and adamant views regarding
       the geographic and operational scope of planning in the sub-region. Therefore, PGE
       proposes the formation of a broader, umbrella forum to facilitate the coordination of sub-
       regional planning among the NTTG, Columbia Grid, and other entities who are not
       members of either organization, including PGE, British Columbia Transmission
       Corporation and others until such time when convergence is achieved in the views of
       FERC jurisdictional and non-jurisdictional entities regarding sub-regional transmission
       planning and expansion. This new forum would provide meaningful planning coverage
       for the entire Columbia River Basin. It would include both members and non-members of
       existing planning forums in the planning process and result in more effective sub-regional
       planning participation and coordination. PGE envisions this process would coordinate all
       sub-regional plans in order to produce a single Northwest sub-regional plan for
       circulation and delivery to all stakeholders and to the regional planning organization, i.e.
       the WECC. PGE believes that the coordinating process should be facilitated by a new or
       existing organization with a wide sub-regional footprint. The Northwest Power Pool
       (“NWPP”) is well positioned to play such a role. PGE plans to approach the NWPP with
       a proposal to form a coordinating committee or subcommittee that would be open to all
       interested parties (including Columbia Grid, NTTG and other Northwest entities that
       have not joined either organization). PGE believes that, in the absence of such a
       coordinating forum, the existing approach of developing uncoordinated sub-regional
       plans for the Columbia River basin will be disjointed at best and ineffective at worst.




PGE Planning Strawman 6/1/2007 (Revision #1)                                          Page 2 of 12
           Local
           PGE’s local planning will take place in two forums: one with interconnected transmission
           providers and one with PGE’s customers and other stakeholders.

           PGE proposes to coordinate local planning with interconnected systems in order to share
           system plans and ensure that they are simultaneously feasible and that they identify
           system enhancements that could relieve significant and recurring congestion at the local
           level.2 In PGE’s case, this local coordination would take place directly between PGE and
           its interconnected Transmission Providers (the Bonneville Power Administration and
           PacifiCorp) when the impacts of a planning issue effect only the interconnected, local
           utilities. Such issues may include local load service and reliability related items, requests
           for interconnection and transmission service, and others impacting only the three
           interconnected Transmission Providers. PGE envisions that participation and
           coordination in this planning process will continue to take place between members of the
           local planning staffs. However, as discussed below, PGE will post any studies, plans or
           proposed enhancements resulting from such coordination on its OASIS and will seek
           input on such items in its customer meetings.

           PGE also intends to meet with its customers and other stakeholders at least once per year
           to obtain timely and meaningful input on the development of local transmission plans and
           proposed enhancements, and to incorporate stakeholders into the PGE planning process.
           PGE may conduct additional transmission customer/stakeholder meetings at the request
           of transmission customers or stakeholders, or as needed to discuss local planning issues.
           These meetings will be open to all interested parties and PGE will post a notice of the
           meeting on OASIS at least one month prior to the meeting.

           The results of PGE’s local planning process will be provided to the sub-regional and
           regional level through the existing annual system data submission processes and by
           posting studies completed in response to service requests on OASIS. PGE will also
           submit results of its local planning to the WECC to incorporate into the base-case
           development process. PGE will publish local plans for project on the PGE system and for
           joint local projects at least annually on its OASIS.

2. ECONOMIC PLANNING STUDIES
PGE will prepare Economic Planning Studies which provide an analysis of significant and
recurring congestion and any upgrades needed to integrate new generation resources or loads on
an aggregated or regional basis. These studies will analyze and report on: (1) the location and
magnitude of the congestion, (2) possible remedies for the elimination of the congestion, in
whole or in part, (3) the associated costs of congestion, and (4) the cost associated with relieving
congestion through system enhancements (or other means).

PGE proposes to conduct economic planning studies in manner that is consistent with the
framework discussed above for Regional Participation. In other words, PGE will conduct local
Economic Planning Studies with input from other local Transmission Providers and sub-


2
    Order 890 at ¶ 523.


PGE Planning Strawman 6/1/2007 (Revision #1)                                               Page 3 of 12
regional/regional Economic Planning Studies will be performed by a regional organization with a
regional database and sub-regional/regional input.

       Local Economic Planning Studies
       PGE will conduct a local Economic Planning Study for areas of congestion that occur on
       a local basis on the PGE Transmission System, such as on an internal flowgate or path.
       In conducting the studies, PGE will study the costs of congestion only to the extent it has
       the information to do so. If stakeholders request that a particular congested area be
       studied, they must supply relevant data within their possession to enable PGE to calculate
       the level of congestion costs that is occurring or is likely to occur in the near future. To
       the extent that PGE’s merchant function possesses such information, it will provide that
       information to the extent necessary to conduct such studies. PGE will post requests for
       Economic Planning Studies and the responses to the requests on its OASIS, subject to
       confidentiality requirements. PGE will also provide the results of its Economic Planning
       Studies to the sub-regional planning groups.

       PGE will perform up to five local Economic Planning Studies per calendar year, the costs
       of which will be recovered by PGE as part of its overall OATT cost of service.
       Customers will have the right to request up to three local Economic Planning Studies and
       PGE Transmission may initiate two additional local studies. The scope and timing of any
       local studies initiated by PGE Transmission will be at PGE Transmission’s discretion.
       Customers may request additional local Economic Planning Studies. However, the costs
       of any additional studies will be charged to the requestor. All customer-requested studies
       will be performed on a first-come, first-served basis. PGE, at its discretion, may cluster
       or batch requests for Economic Planning Studies in order to perform the studies in the
       most efficient manner possible. As discussed below, any studies related to the California-
       Oregon Intertie (“COI”) will be coordinated on a sub-regional or regional basis. Because
       the remainder of PGE’s Transmission System is primarily used to deliver to load and not
       to facilitate system transfers, PGE anticipates a limited number of requests for local
       Economic Planning Studies that will not affect the region.

       Sub-regional/Regional Economic Planning Studies
       A sub-regional/regional Economic Planning Study would be performed on congested
       areas that have an impact on regional transmission and availability, such as the COI.
       PGE proposes that these sub-regional/regional Economic Planning Studies be performed
       at the by the WECC in the Transmission Expansion Planning Policy Committee
       (“TEPPC”) or by the new NWPP sub-regional coordinating committee. Subcommittees
       within the TEPPC have access to the necessary data and tools to perform a regional
       Economic Planning Study and the sub-regional committee will have access to that
       information as well interested parties within the region. PGE proposes to take up to five
       requests per calendar year for sub-regional/regional Economic Planning Studies to the
       appropriate group (either WECC or the sub-regional coordinating committee). For the
       portion of the PGE Transmission System that facilitates system transfers, PGE anticipates
       the need to coordinate these with other entities in the sub-region and region, and proposes
       to do so by performing the studies at the appropriate level.




PGE Planning Strawman 6/1/2007 (Revision #1)                                          Page 4 of 12
3. INFORMATION EXCHANGE
PGE’s network transmission customers must submit to PGE at least one time per year,
information on their projected network loads and network resources for the period of the
planning process (ten years). PGE will post all such information on its OASIS. The data will be
made available to anyone without OASIS access within 30 days of requesting such information,
subject to confidentiality requirements. PGE will incorporate the network load and resource
forecast data into its planning process, and may share it with interconnected utilities as part of
the local planning process. PGE will provide the forecast data to the sub-regional planning
groups upon request and will submit it to the regional planning group for inclusion in the
basecase development process.

PGE’s long-term firm point-to-point (“PTP”) customers must, at least once per year, submit
forecasts of their projected PTP usage through the PGE OASIS site. The data will be made
available to anyone without OASIS access within 30 days of requesting such information,
subject to confidentiality requirements. PGE will incorporate the PTP forecast usage data into its
planning process, and may share it with interconnected utilities as part of the local planning
process. PGE will provide the forecast data to the sub-regional planning groups upon request.

PGE will be developing business practices to describe the mechanics of how customers will
submit the required forecast information. These business practices will include direction on how
to submit information prior to the development of an OASIS mechanism and how to submit data
once the OASIS tools are available.

4. COST ALLOCATION
For projects identified in its planning process, PGE will use facility classifications similar to the
NTTG proposal for the classification of transmission configurations and cost types. That
proposal, as modified to apply to PGE, can be found in Attachment 1. PGE will also use
principles similar to the NTTG proposed principles for allocating project costs. That proposal, as
modified to apply to PGE, can be found in Attachment 2.

Customers may use the dispute resolution process discussed in this Planning Proposal to
challenge PGE’s allocation of the costs of a project.

5. DISPUTE RESOLUTION
PGE proposes two levels of dispute resolution for procedural and substantial planning issues
which are not otherwise subject to the existing dispute resolution procedures in PGE’s OATT.
The first level involves an informal meeting between senior level personal from PGE and the
disputing party to attempt to resolve the disputed issues. The meeting will be held at an
independent site, will last no more than four hours, and will provide no more than one and one
half for each party to present a position. The final hour will be reserved for group discussion and
agreement of next steps. If the parties cannot agree on the next steps n and/or the dispute is not
resolved during the informal discussion, either party can initiate a formal dispute resolution
process.

PGE proposes to adopt a formal dispute resolution process modeled on the existing WECC
Dispute Resolution Procedure (available at www.wecc.biz). The WECC Dispute Resolution



PGE Planning Strawman 6/1/2007 (Revision #1)                                            Page 5 of 12
Procedures provides for meditation, negotiation, and arbitration. The WECC Dispute Resolution
Procedures were developed to deal with planning and operating related issues, and provide a
process in which to deal with both procedural and substantive planning issues.

6. COMPARABILITY
PGE’s proposal for addressing the planning principles of regional participation, economic
planning studies, information exchange, cost allocation, and dispute resolution provide processes
that meet the specific service requests of its transmission customers and treats similarly situated
customers comparably in transmission system planning. PGE’s similarly situated transmission
customers will have comparable access to the planning information, including:

       -   Forecast load and resource data from network customers via OASIS
       -   Forecast PTP service needs for the planning horizon via OASIS
       -   Local transmission system plans via OASIS
       -   Sub-regional transmission plans via the open seams process
       -   Regional transmission plans via participation in the WECC organization

Similarly situated customers will also have comparable treatment in PGE’s planning processes,
including:
       - Access to request and view economic planning studies
       - Comparable treatment in terms of cost allocation
       - Comparable treatment in terms of dispute resolution

In conducting its planning processes, PGE will consider demand resources on a comparable basis
to the service provided by comparable generation resources, where appropriate.

7. COORDINATION
PGE’s proposal for addressing the planning principles of regional participation, economic
planning studies, and information exchange include processes that provide transmission
customers, interconnected neighbors and stakeholders the opportunity to review and comment on
the PGE transmission plans. As discussed more fully above, transmission customers,
interconnection neighbors, and stakeholders will be involved in the planning process though:

       -   Transmission customer/stakeholder meetings, held no less than one time per year or
           as noticed by PGE or interested parties
       -   Open seam coordinating committee or subcommittee meetings that would be open to
           all interested parties
       -   Existing forums and processes within the WECC including the Annual Progress
           Reports, the annual Significant Additions Report, and the Regional Review Process
       -   The ability to request both local and regional Economic Planning Studies, and the
           OASIS posting of any completed Economic Planning Studies
       -   Coordination of forecast load and usage data with interconnected utilities through the
           local planning participation
       -   Coordination of forecast data submission to the sub-regional planning groups upon
           request and to the region for inclusion into the basecase development process




PGE Planning Strawman 6/1/2007 (Revision #1)                                          Page 6 of 12
8. OPENNESS
PGE’s proposal for addressing the planning principles of regional participation, economic
planning studies, and information exchange provide open forums, meetings and exchange of
information. As discussed more fully above, all affected parties will be able to able to participate
in the planning process via:

       -   Transmission customer/stakeholder meetings, held no less than one time per year or
           as noticed by PGE or interested parties
       -   Open seam coordinating committee or subcommittee meetings
       -   Existing forums and processes within the WECC
       -   The ability to request both local and regional Economic Planning Studies, and the
           OASIS posting of any completed Economic Planning Studies
       -   Access to information regarding forecast load and usage data via OASIS postings for
           forecast demand on the PGE Transmission System

9. TRANSPARENCY
PGE’s proposal for addressing the planning principles of regional participation, economic
planning studies, and information exchange provide transparency to all customers and other
stakeholders on the basic criteria, assumptions and data that underlie the PGE system plans. As
discussed more fully above, all customers and other stakeholders will have access to the basic
criteria, assumptions and data via:

       -   Posted local transmission system plans
       -   Posting of all completed local and regional Economic Planning Studies
       -   Access to information regarding forecast load and usage data via OASIS postings for
           forecast demand on the PGE Transmission System




PGE Planning Strawman 6/1/2007 (Revision #1)                                           Page 7 of 12
ATTACHMENT 1: NTTG proposal for classification of transmission configurations and
cost types

      The following classification scheme is built around the costs related to the end-use
      characteristics of the transmission line. Because transmission lines might be built and
      owned by multiple parties, each of whom may have different uses in mind, any given
      transmission line could, in fact, include multiple types of costs.

      For purposes of developing the Draft Cost Allocation Principles, the types of
      transmission line costs are:

      Type 1 transmission line costs are those related to the provision of retail service to the
      transmission owner’s native retail load, including the following sub-types:
             • Type 1-A: costs incurred by a single load serving entity for its native load within
             a single state.
             • Type 1-C: costs incurred by more than one load serving entity for native load
             within one state.
             • Type 1-E: costs incurred to provide service for, to lower the costs of, or to
             increase the quality of service for a specific retail customer or specifically
             identifiable group of retail customers. While there may be some “generic” benefit
             to other retail customers, those benefits would be incidental to the primary
             purpose of the line.

      Type 1 costs might be incurred to:
      a. Provide capacity needed to serve load; or,
      b. Fulfill reliability or other technical operating requirements, the benefits of which
         generally inure to the consuming public; or,
      c. Lower costs for the general consuming public (e.g. congestion relief that provides
         access to cheaper, remote generation); or,
      d. Fulfill requirements related to state or federal environmental or other policies.

      Type 2 transmission line costs are those related to the sale or purchase of power at
      wholesale not directly for the benefit of native load, or on behalf of or at the request of a
      wholesale generator or a wholesale transmission customer. Type 2 transmission line costs
      will typically be FERC-jurisdictional and not subject to state review. However, to the
      extent that the physical transmission line associated with these costs might also have
      Type 1 characteristics, a state or states may allocate costs to retail rate payers, and project
      developers should therefore be prepared to bring the project before PGE. State regulators
      have three ways to include transmission costs in retail rates (bundled, functionally
      unbundled, functionally and service (retail versus wholesale) unbundled). Depending on
      the method used, either the utility shareholders or the utility customers bear the risk of
      differences in FERC and state cost recovery decisions. The proposed Principles for
      allocation costs are designed to minimize the possibility of incomplete allocation of
      appropriate project costs while not imposing unwarranted costs on retail ratepayers.




PGE Planning Strawman 6/1/2007 (Revision #1)                                           Page 8 of 12
      Type 3 costs are those incurred specifically as alternatives to (or deferrals of)
      transmission line costs (typically Type 1 projects), such as the installation of distributed
      resources (including distributed generation, load management and energy efficiency).
      Type 3 costs do not include demand-side projects which do not have the effect of
      deferring or displacing Type 1 costs.

      For purposes of these Cost Allocation Principles, it is critical to keep in mind the
      distinction between transmission projects and transmission cost types. Any given
      transmission project may have multiple transmission cost types. For example, a
      transmission line may be jointly owned by owners who utilize the line for different
      purposes (one owner may utilize the line for native load, while another utilizes the line
      for access to wholesale markets); and even for a single owner, the line may serve multiple
      purposes (part native load and part direct off-system sales or out of region export sales to
      another transmission user). These principles are built around the characteristics of the
      associated costs. Therefore, transmission project developers, working with PGE, are
      obligated to develop the allocation of costs for projects using the cost types identified
      above and the Principles described below.




PGE Planning Strawman 6/1/2007 (Revision #1)                                           Page 9 of 12
ATTACHMENT 2: Principles for allocating project costs

Below are the PGE Cost Allocation Principles. A discussion of each individual principle
follows:

       Principle 1:
       “As a matter of equity, cost allocations will reflect the classic principles that ‘cost causers
       should be cost bearers’ and that ‘beneficiaries should pay’ in amounts that are reflective
       of the benefits received.”
       Principle Type:
       Equity (Applies to all Transmission Cost Types)
       Discussion:
       This principle is consistent with traditional utility cost recovery principles historically
       applied by utility commissions. However, the “cost causer” and “beneficiary” concepts
       are not necessarily identical. That is, there may be situations where the project
       construction or the problem being solved is “caused” by one party, but where the solution
       being applied also provides benefits to others or increases costs to others. As such,
       application of this principle necessarily implies a balancing of these interests3. This
       principle presumes that the term “benefit” includes transmission service allocation
       (meaning transmission rights, whether physical or financial) and that allocation of service
       rights is consistent with cost allocation. Further, given the characteristics of the Western
       Interconnection and the development of electricity markets to date, the party funding a
       project should retain its rights as market structure, e.g., formation of an ISO, evolves.

       Principle 2
       “Projects brought forward for consideration of cost recovery will be shown not to be in
       conflict with state and federal IRP, Competitive Bidding, RPS (Renewable Portfolio
       Standard), siting, certification and other policy and planning requirements affecting
       transmission development, to the extent they are applicable to the project. Selecting an
       efficient portfolio of remote generation, in-state generation and demand-side solutions
       requires that the proposed allocation of transmission project costs be known with clarity.
       Therefore, this cost allocation process will encourage efficient and stable resource
       planning processes by which the project developer identifies the extent of cost allocation
       consensus for a proposed transmission project as soon as practical in the project life
       cycle, allowing the states to evaluate the proposed project for compliance purposes and to
       understand costs relative to other resource options. Regional and subregional planning
       resources should be utilized and the results demonstrated.”
       Principle Type:
       Efficiency (Applies to all Transmission Cost Types)
       Discussion:



3
  For example, in the SPP, for “Base Funded” projects, this is addressed through the use of an
arbitrary allocation of costs. One third of the cost is allocated on a region-wide basis and the
balance is allocated to the identified zone or zones that benefit from the project, using an
“incremental MW mile” approach.


PGE Planning Strawman 6/1/2007 (Revision #1)                                           Page 10 of 12
      Transmission projects should support applicable state and federal resource choice policies
      and regulatory requirements and should result in efficient transmission development.
      Project developers should demonstrate how the project achieves these requirements and
      what the costs are, in real terms and relative to other resource choices. In reviewing
      project costs, the developer will show that non-transmission alternatives (e.g., demand
      side management, distributed resources and energy efficiency programs) have been fairly
      considered. Project developers should demonstrate how their proposals have been
      identified and assessed by WECC and by any other entities (e.g., groups planning
      interregional transmission projects such as the Trans West Express or the Frontier Line)
      which may be involved.

      Principle 3
      “Cost allocations will result in a reasonable opportunity for the transmission owner(s) to
      achieve full recovery of the costs of the project, but no more.”
      Principle Type:
      Fair and Full Cost Allocation (Applies to all Transmission Cost Types)
      Discussion:
      Order 890 recognizes this critical principle. Needed transmission projects will not be
      undertaken if there is no reasonable assurance that the project developers can obtain an
      appropriate recovery of costs. Type 1 or Type 3 project costs should all be fully
      recoverable from the appropriate ratepayers; and all of the costs of multi-state projects of
      Types 1-B and 1-D should be allocated to one or more utility systems for recovery. For a
      Type 2 project related solely to wholesale generation or transmission, this may not
      require action by PGE because (except for any system reliability case that might be
      made) there should be no expectation of recovery from ratepayers. In any situation, there
      should be no over- or under allocation of these costs.

      Historically, utilities have largely recovered multi-jurisdictional costs through allocation
      mechanisms that were, for the most part, sufficiently consistent to allow recovery of all
      costs. This has become less consistent as state policies and requirements bearing on
      electric utility infrastructure construction have diverged over time. While there are legal
      standards that support full cost recovery at the federal and individual state levels, there
      have never been formalized rules to assure this result. State and federal standards that
      provide for a reasonable opportunity to earn a return on the investment, and prohibit
      confiscatory rates to the utility or excessive rates to customers, demonstrate the careful
      balance that must be achieved in setting rates.

      Principle 3a
      “Transmission project costs should be directly assigned to a single transmission customer
      or allocated to multiple transmission customers or areas (or the entire region) based upon
      the distribution of benefits.”
      Principle Type:
      Cost Assignment Should Follow Benefits (Applies to all Transmission Cost Types)
      Discussion:
      To the greatest extent possible, transmission costs should be allocated to the customers or
      regions that receive the benefits of the project. This elaborates on the “beneficiaries



PGE Planning Strawman 6/1/2007 (Revision #1)                                         Page 11 of 12
      should pay” aspect of Principle 1. To provide reasonable assurance of cost recovery to
      project owners and to avoid post-construction cost allocation controversy, the project
      owner must identify its expectations for the allocation of costs early on in the review
      process and always prior to construction. While it is unlikely that any state would endorse
      “pre-approval” of cost recovery, especially in the regional or sub-regional context, it is
      important for the project owner to engage the states and the Transmission Provider early
      in the process so the expectations of the project owners and others will be clearly
      identified and understood during pre-construction review.

      Principle 3b
      “Upgrades and other projects proposed on the basis of economic or other benefits for
      specific transmission customers will be accommodated if [i] the customers and/or
      transmission owner accept responsibility for the associated costs; [ii] the project does no
      harm to the network; and [iii] the project otherwise has no adverse impact on regional
      transmission service.”
      Principle Type:
      Customer Specific Allocation (Applies to all Transmission Cost Types, most specifically
      Type 1-E)
      Discussion:
      Where transmission customers require specific projects that are not otherwise identified
      as having Type 1-E cost aspects, cost recovery should be limited to the affected customer
      or customers. Incidental benefits to other customers could be considered.

      Principle 4
      “For Type 2 project costs, the rest of the network and its customers will be held harmless
      and the transmission owner should look to its transmission customers for direct recovery
      of costs.”
      Principle Type:
      Allocation for wholesale and merchant project costs (Applies to Transmission Cost Type:
      Type 2)
      Discussion:
      These projects fall mostly outside the scope of regional or sub-regional cost allocation
      mechanisms, and the merchant transmission owner should look to its customers for
      recovery of costs. As a general rule, it is expected that Type 2 costs will be subject to
      FERC jurisdiction. Transmission Provider may apply its knowledge of sub-regional facts
      and circumstances to assist state and federal regulatory bodies in resolving conflicts in
      defining and adjudicating “harm” and ancillary benefits. Project developers may bring
      forward assertions of reliability benefits.




PGE Planning Strawman 6/1/2007 (Revision #1)                                       Page 12 of 12