Southwest Power Pool STRATEGIC PLANNING COMMITTEE … · Strategic Planning Committee Meeting January 17, 2008 SPP Balancing Authority Consolidation Update 2 The Strategic Planning

MINUTES NO. 53

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE MEETING

January 17, 2008

Embassy Suites Outdoor World, Grapevine, TX

• M I N U T E S •

Agenda Item 1 – Administrative Items

Chair Richard Spring (KCPL) called the meeting to order at 8:00 A.M. SPC members participating in person were Jim Eckelberger (Director); Josh Martin (Director); Harry Skilton (Director); Rob Janssen (Redbud); Ricky Bittle (AECC); Les Evans (KEPCo); Kevin Easley (GRDA); Tim Woolley (Xcel); Mel Perkins (OG&E); and Mike Palmer (EDE). SPP Staff participating in person or by teleconference included Michael Desselle, Nick Brown, Bruce Rew, Stacy Duckett, Lanny Nickell, Les Dillahunty, Emily Pennel, Derek Wingfield and Laura Haywood. Guests participating in person or by teleconference included; Tom Stuchlik (Westar); Ed Stoneburg (Trans-Elect); Carl Huslig (ITC Great Plains) and Jim Sorrels (AEP) (Attendance – Attachment 1).

Richard Spring referred to the October 18, 2007 minutes and asked for additions or corrections or a motion for approval (Minutes 10/18/07 – Attachment 2). Josh Martin moved and Mel Perkins seconded approval of the minutes as presented. The motion passed.

Agenda Item 2 – Review Past Action Items

Michael Desselle provided a review of past actions items.

Agenda Item 3 – Markets and Operations Policy Committee Update

Lanny Nickell provided a report on the MOPC activities. Balancing Authority: Lanny also provided an update on efforts to consolidate SPP Balancing Authorities (Balancing Authority Presentation – Attachment 3). After much discussion Lanny was advised to continue to develop the technical specifications for BA consolidation and further to communicate to the Future Markets Cost Benefit Task Force that they should include in their evaluations the cost and benefits of BA consolidation as an element of the future market costs/benefits. Separately, in the May/June time frame (in advance of the July Board meeting) when the BA consolidation technical specifications have been finalized, decisions and recommendations to the Board and membership would be made to move forward with BA consolidation on a contract service basis or on a “rolled-in” service basis.

Transmission Ownership/Construction Task Force: Les Dillahunty provided the Transmission Ownership/Construction Task Force update (TOCTF Report – Attachment 4). The group discussed the Draft White Paper as well as the final TOCTF recommendations included in the White Paper. The discussion also focused on the timing and which groups would work to finalize the TOCTF recommendations. It was decided that the MOPC was the appropriate committee to lead the effort and report back to the SPC on those efforts. Staff will develop a strawman to include the “who/what/where and when” for consideration by the MOPC and SPC. Mel Perkins moved that: The SPC approve the TOCTF recommendations as presented. The staff is to prepare a strawman proposal for each recommendation and submit to the appropriate working group/s (including a proposed timeline) for further action with copy to the Chair of SPC. Les Evans seconded the motion, which was approved. The TOCTF is now disbanded.

Strategic Planning Committee January 17, 2008

Agenda Item 4 – Strategic Plan Items

Richard Spring led discussions on the status of several Strategic Plan items. • SPP Strategic Plan Status Report – (Strategic Plan Status – Attachment 5). • Communication/Education Strawman – Nick Brown discussed the need to assess what is

expected of the SPP to accomplish the Strategic Plan item Communications/Education. To gain some sense of direction in the development of a strawman proposal for this Strategic Plan item a matrix was developed to assess the SPC’s “market intelligence”. A matrix survey was distributed to those present and it sought to assess two questions of the group: Where is SPP today? and, Where should SPP be in the near future? The group ranked items as to where SPP is today (T) or should be addressed in the future (S) (Communications Strategy Report & Summary – Attachment 6). In summary, the survey responses indicated that SPP needs to increase its efforts in Communication/Education compared to where it is today for each constituency (Industry, Regulators, Legislators, Other Stakeholders, and the General Public) at least one level, and for certain constituencies two levels. The results also indicated that SPP’s Communication/Education efforts should rise from the Active/Reactive level to the Proactive level for the Industry, Legislators and Other Stakeholders constituencies and to the integrated level for the Regulator and General Public constituencies. Based on the group’s feedback, the SPP Communication Department will develop a strawman Communication/Education proposal for consideration by the SPC at its May retreat.

• Contract Services Update – Bruce Rew provided a Contract Services update (Contract Services –

Attachment 7). Mr. Rew reviewed the Independent Coordinator of Transmission (ICT) for Entergy – Annual Performance Report and The ICT’s Report on Entergy’s Transmission System and Transmission Pricing. The group decided that there should be future discussion on the risks of the ICT and that SPP should evaluate the LLC structure for contract service offerings to shield the Organization from risk.

• Membership Development Update – Nick Brown reported on a series of recent meetings with

potential new members and noted that SPP is optimistic regarding additional membership or contract services. The majority of the potential new members seem to be interested in full membership or contract services with provision to transition into full membership.

Agenda Item 5 – Discussion Item: Process seeking member input on items of strategic importance

Richard Spring led a discussion on seeking member input on items of strategic importance. Several suggestions were identified during the discussion, including: retirement issues and exploring and accommodation of wind generation. A process to solicit input was discussed and finalized. SPP staff will develop a strawman to be provided to the SPC for circulation via e-mail. The SPC would finalize the strawman via e-mail and then Staff would distribute the proposed strawman to the MOPC/BOD/RSC and solicit their feedback. The feedback would be assimilated for inclusion into the April BOD background material. The Directors would discuss the strawman following the April Board meeting. Staff will assemble all the feedback into a package for consideration at the SPC’s May retreat.

Agenda Item 6 – Regulatory

Les Dillahunty provided a report and status update of SPP regulatory affairs activities which included: external generation, Order 890A, ETI Cost/Benefit study to determine if Entergy Transmission Inc should be in SPP or SERC, FERC’s Queuing NOPR status, and the Cost Allocation Working Group (CAWG) economic upgrades cost allocation efforts (SPP Regulatory Summary – Attachment 8). The CAWG will circulate a concepts paper for cost allocation for economic upgrades for projects at 345kV or higher using the portfolio approach and a region wide postage stamp approach.

Strategic Planning Committee January 17, 2008

Agenda Item 7 – Summary of Action Items

• Carry out Strategic Plan item feedback process. • Evaluate LLC structure for ICT/contract services. • Inform Future Markets Cost Benefit Task Force to include cost and benefits of BA Consolidation

efforts as a component of the study • Staff to develop strawman for Communication/Education strategic plan item for inclusion and

discussion at the SPC May retreat

Agenda Item 8 – Future Meetings

The remaining Strategic Planning Committee meeting dates for 2008 are:

May 12 – 14 (Retreat) Lake DeGray, AR July 17 Kansas City October 16 Tulsa

Respectfully Submitted, Michael Desselle Secretary

Southwest Power Pool, Inc. STRATEGIC PLANNING MEETING

January 17, 2008 Embassy Suites Outdoor World, Grapevine, TX

• A G E N D A •

8 a.m. – 3 p.m. (CST)

1. Call to Order and Administrative Items............................................................................. Richard Spring

2. Review of Past Action Items..........................................................................................Michael Desselle

3. MOPC Update .....................................................................................................................Lanny Nickell

a. Balancing Authority ..........................................................................................Lanny Nickell

b. Transmission Ownership/Construction Task Force ........................................... Mel Perkins

4. Strategic Plan Items ......................................................................................................... Richard Spring

a. Review SPP Strategic Plan Status Report

b. Communication/Education Strawman

c. Contract Services Update ................................................................................... Bruce Rew

d. Membership Development Update .....................................................................Nick Brown

5. Discussion Item: Process seeking member input on items of strategic importance ....... Richard Spring

6. Regulatory ......................................................................................................................... Les Dillahunty

a. Queuing NOPR

7. Summary of Action Items ..............................................................................................Michael Desselle

8. Future Meetings.............................................................................................................Michael Desselle

May 13 - 14 Lake DeGray, AR

July 17 Kansas City

October 16 Tulsa

MINUTES NO. 52

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE MEETING

October 18, 2007

Doubletree Hotel at Warren Place – Tulsa, Oklahoma

• M I N U T E S •

Agenda Item 1 – Administrative Items

Chair Richard Spring (KCPL) called the meeting to order at 8:00 A.M. SPC members participating in person were Jim Eckelberger (Director); Josh Martin (Director); Harry Skilton (Director); Rob Janssen (Redbud); Ricky Bittle (AECC); Les Evans (KEPCO); Tim Woolley (Xcel); Mel Perkins (OG&E); and Mike Palmer (EDE). SPP Staff participating in person or by teleconference included Michael Desselle, Nick Brown, Carl Monroe, Stacy Duckett, and Les Dillahunty. Guests participating in person or by teleconference included; Raj Rana (AEP); Ed Stoneburg (Trans-Elect); Bary Warren (EDE); Mark Rossi (Gestalt); Sam Loudenslager (APSC); Carl Huslig (ITC Great Plains);Cindy Holman (OMPA); Kelly Harrison (Westar); and Walter Wolfe (LPSC) (Attendance – Attachment 1).

Richard Spring referred to the July 12, 2007 minutes and asked for additions or corrections or a motion for approval (Minutes 7/12/07 – Attachment 2). Josh Martin moved and Les Evans seconded approval of the minutes as presented. The motion passed.

Agenda Item 2 – Review Past Action Items

Michael Desselle provided a review of past actions items.

Agenda Item 3 – Markets and Operations Policy Committee Update

Carl Monroe provided a report on the MOPC October meeting activities including items and discussion regarding:

• Future Market Design • Cost Benefit Study • Status of External Generation • Balancing Authority Consolidation: timeline, interest, and cost • Proposed working group reorganization including the new Change Working Group

Agenda Item 4 – Transmission Ownership/Construction Task Force Report

Mel Perkins reviewed the TOCTF report discussing current policy issues, responses, and recommendations (TOCTF Report & Recommendation – Attachment 3). Mel asked that the TOCTF term be extended through January 2008, which would allow greater specificity to the initial policy-level review and a sub-group to add an additional level of granularity on policy issues. Rob Janssen moved to extend the TOCTF term and Ricky Bittle seconded the motion. The motion passed.

Agenda Item 5 – Strategic Plan Items

Richard Spring provided an update on the Strategic Plan items (DR Materials – Attachment 4). The group discussed and agreed to develop a Communication Plan; agreed to ask Billy Berny (AEP) to chair the Demand Response Task Force; and held a discussion on the Senate Bill 2076.

Strategic Planning Committee October 18, 2007

Agenda Item 6 – Update on Organizational Metrics

Michael Desselle provided an update on the SPP Organizational Metrics (Operational Metrics – Attachment 5).

Agenda Item 7 – Update on ICT

Michael Desselle provided an update on the ICT.

Agenda Item 8 – Regulatory Update

Les Dillahunty provided a regulatory update report (Regulatory Update – Attachment 6). He reported on the number of active dockets, reviewed the Empire District waiver request, and discussed the status of the EGSIQPR/CREZ.

Agenda Item 9 – SPC Annual Self Assessment and Survey Results

Richard Spring reviewed the SPC Annual Self Assessment and Survey results (Assessment & Survey – Attachment 7).

Agenda Item 10 – Summary of Action Items

• Circulate the MOPC Reorganization Org Charts and • Develop a Communication Plan • Discuss with Billy Berny (AEP) the possibility of chairing the Demand Response/EE Task Force • Secure a date for the SPC Retreat

Agenda Item 12 – Future Meetings

The committee discussed the 2008 meeting schedule. Following discussion regarding the numbers of meetings, it was decided to hold three meetings and a retreat. The group will not meet in April as in the past. The remaining meeting dates for 2008 are:

May 13 – 14 (Retreat) Lake DeGray, AR July 17 Kansas City October 16 Tulsa

Respectfully Submitted, Michael Desselle Secretary

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www.spp.org 1

Strategic Planning Committee MeetingJanuary 17, 2008

SPP Balancing Authority Consolidation Update

www.spp.org 2

The Strategic Planning Committee has identified the offering of BA services by SPP as a high priority goal.

BA Consolidation is considered necessary for the implementation of the next market.

FERC requires SPP to study the feasibility of Consolidating BA’s and file a report within 15 months of the February 1, 2007 start of the EI Market.

Why SPP is Investigating BA Consolidation

www.spp.org 3

Progress Made to Date

A functional method of consolidation has been proposed

Costs and benefits have been estimated

An Implementation Plan including a high level timeline has been developed

The MOPC approved formation of the Consolidated Balancing Authority Steering Committee

www.spp.org 4

Estimated Costs-Additional SPP BA staff $1,350,000 (Annual)

and maintenance

SPP systems changes $1,800,000 (One Time) and Licenses

Current BA system changes $ 600,000 (One Time)

Potential “throwaway” cost $ 650,000

Costs of BA Consolidation

www.spp.org 5

Facilitation of Future Ancillary Service and Unit Commitment Markets

Transfer of Liability

Reduced Training and Certification Costs

Potential Staffing Reductions

Reduced Regulation Burden• Analysis performed based on actual data collected from last year indicated $3,800,000

to $19,000,000 annual settlement reduction (LIP * MWH reduction) would have resulted from using the proposed ACE diversity algorithm

• Many believe that the potential savings associated with reduced regulation will be even more dramatic as intermittent resources are added to the footprint

Benefits of BA Consolidation

www.spp.org 6

Project Implementation Assumptions

SPP will have a functional test bed with the required capability in place before testing begins.

Starting the detail design and coding stage with vendors is dependent on the cost/benefit report for future markets and an executed MOU.

The future markets cost/benefit report will be delivered in September, 2008. SPP will agree to future market development in early October, 2008. SPP will continue to develop the Balancing Authority technical details to describe

the tasks the BA will perform and how they will be accomplished.SPP will immediately begin to develop the requirements for the software changes

needed to operate the Balancing Authority Area. SPP will immediately begin to develop Operating Procedures for the Balancing

Authority. SPP will immediately begin necessary contractual design. There will be two meetings each month after January 2008 between SPP and

Participants to develop the Technical and Policy details.

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Project Implementation Risks

Any extended delays at AREVA, SPP, or Participants due to resource unavailability and/or scope change.

Regulatory process by states and FERCResource availability due to other projects. Scope pushes project implementation in to the

summer of 2009. If market footprint and BA footprint are not the same,

scope change is inevitable.

www.spp.org 8

High Level Timeline

Shown:• Development of technical details• Development of procedures• Development of contractual requirements• Filing of feasibility report to FERC• Decision point

Not Shown:• Software development and testing after decision point

It is estimated that software development and testing will take 11 months from “Go” decision

www.spp.org 9

Steering Committee

A Steering Committee is now needed to:• Provide formal reporting relation with MOPC• Facilitate meetings of subject matter experts• Oversee development of technical details, policies, and

agreements needed to implement • Ensure coordination with appropriate state and federal

regulatory agencies

Comprised of at least one member from each current BA in the SPP Market footprint and any other signatory to an MOU

MOPC approved charter at their January 15-16, 2007 meeting

January 14, 2008 i

TOCTF Report

Table of Contents

I. Introduction......................................................................................................................... 2 II. TOCTF Recommendations................................................................................................. 2 III. Pertinent Provisions from SPP’s Effective Governing Documents..................................... 3

IIIA. Definition of Transmission Owner ................................................................................... 3 IIIB. Provisions for Construction, Ownership and Financing .................................................. 4

IV. Reliability and Economic Upgrades.................................................................................... 9 IVA. Recommendation 2 ......................................................................................................... 9 IVB. Discussion ..................................................................................................................... 10 IVC. Other RTOs’ Approach to Similar Issues ...................................................................... 11

V. Construction of All Approved Projects.............................................................................. 12 VA. Recommendation 4 ....................................................................................................... 12 VB. Discussion ..................................................................................................................... 12

VI. Multiple Entities Involved in Project.................................................................................. 13 VIA. Recommendation 4 ....................................................................................................... 13 VIB. Discussion ..................................................................................................................... 13

VII. Guidance for Selecting a Qualified Entity to Construct .................................................... 14 VIIA. Recommendation 5 ....................................................................................................... 14 VIIB. Discussion ..................................................................................................................... 14 VIIC. Other RTOs’ Approach to Similar Issues ...................................................................... 15

VIII. New Qualified Entity Becoming a Transmission Owner................................................... 17 VIIIA. Recommendation 6 ....................................................................................................... 17 VIIIB. Discussion ..................................................................................................................... 17 VIIIC. Other RTOs’ Approach to Similar Issues ...................................................................... 17

IX. Transmission Interconnection........................................................................................... 18 IXA. Recommendation 1 ....................................................................................................... 18 IXB. Discussion ..................................................................................................................... 18 IXC. Other RTOs’ Approach to Similar Issues ...................................................................... 19

X. Ratings.............................................................................................................................. 19 XA. Recommendation 3 ....................................................................................................... 19 XB. Discussion ..................................................................................................................... 19

XI. Task Priority...................................................................................................................... 20 XIA. Priority A........................................................................................................................ 20 XIB. Priority B........................................................................................................................ 21 XIC. Priority C........................................................................................................................ 22

January 14, 2008 2

I. Introduction The Transmission Ownership/Construction Task Force (“TOCTF”) completed its initial policy level review of the allocation of rights and responsibilities associated with the ownership, construction and operation of transmission upgrades in its report dated October 18, 2007 (the “TOCTF Report”). The TOCTF Report included 10 recommendations. This document, prepared by the TOCTF Focus Group identified in recommendation 10 of the TOCTF Report, provides an additional level of granularity on recommendations 1 through 6. The intent of this additional level of granularity is (i) to aid in the assignment of responsibilities to implement these recommendations and (ii) to provide more detail regarding the assignment. Recommendations 7 through 10 do not require action by the TOCTF Focus Group. Section II of this document lists the 10 recommendations from the TOCTF Report. For ease of reference, Section III sets forth the pertinent provisions concerning transmission construction, ownership and financing which are contained in SPP’s effective governing documents. Sections IV through X provide a discussion of recommendations 1 through 6 from the TOCTF Report. Finally, Section XI prioritizes the tasks required to implement the recommendations from the TOCTF Report.

II. TOCTF Recommendations The 10 recommendations from the TOCTF Report are listed below. 1. SPP does need a process for transmission interconnection as has been done for

Generator Interconnections that go beyond the present Transmission Working Group (TWG) technical review to assess costs and impacts of the transmission interconnection.

2. The SPP OATT, Bylaws and Membership Agreement language may not be sufficient

or provide enough clarity to address both reliability and economic upgrades and this area should be reviewed.

3. SPP should support the development of operating criteria/facility ratings that insure a

consistent level of service across multiple utilities for major transmission projects. Operating criteria/facility ratings are distinct from construction standards.

4. While it is generally expected that the project financier, owner, and operator would be

the same entity; there should be nothing that prohibits a differentiation, such that financial partners or joint ventures could occur. Additionally, the SPP OATT should be reviewed to ensure that all projects approved by the SPP Board of Directors are constructed.

5. SPP’s governing documents should be supplemented to provide specific guidance to

direct the selection of a qualified entity should the incumbent Transmission Owner not carry out obligations arising from the approved STEP.

6. The governing documents should be reviewed to identify whether there are any

provisions that may need modification to allow a new, qualified entity to become a Transmission Owner under the OATT and Membership Agreement.

7. Should instances arise where current state laws or regulations inhibit the

development of the transmission system, SPP members should raise and address these issues.

January 14, 2008 3

8. There does not appear to be anything that prohibits non-incumbent utilities from pursuing the necessary state certifications for recognition as a utility.

9. Cost allocation should be associated with benefits, not the obligation to build. 10. The TOCTF has completed its initial policy level review; however, before assigning

responsibilities to specific working groups or task forces, greater specificity should aid and expedite the stakeholder process. To accomplish that goal, the TOCTF recommends that the term of the Task Force be extended through January 2008. A TOCTF sub-group comprised of Ricky Bittle (AECC), Charles Locke (KCPL), Pat Bourne (SPP) and Pam Kozlowski (Gestalt) will provide an additional level of granularity on these policy issues that will aid in the assignment of responsibilities. The sub-group will report to the TOCTF mid-term and again before the SPC’s January 2008 meeting in order for a final report of the TOCTF to be made at that time.

III. Pertinent Provisions from SPP’s Effective Governing Documents This section sets forth the pertinent provisions concerning transmission construction, ownership and financing which are contained in SPP’s effective governing documents. These are the primary provisions of SPP’s effective governing documents that will need to be reviewed and potentially modified in order to effect the recommendations from the TOCTF Report, including allowing entities other than traditional Transmission Owners to own, finance and construct transmission facilities.

IIIA. Definition of Transmission Owner

1. SPP Bylaws 1.15 Transmission Owning Member: A Member that has placed more than 500 miles of non-radial facilities operated at or above 60 kV under the independent administration of SPP for the provision of regional transmission service as set forth in the Membership Agreement.

2. SPP Membership Agreement 1.25 Transmission Owner: A signatory to this [Membership] Agreement which transfers functional control related to the rates and conditions of the OATT to SPP by executing this [Membership] Agreement or appoints SPP under another agreement to provide service under the Transmission Tariff over Transmission Facilities which it owns or controls. 1.14 Non-Transmission Owner: A Member that is not a Transmission Owner. A Non-Transmission Owner that owns or controls Tariff Facilities may have its status changed to a Transmission Owner under this [Membership] Agreement upon notice to SPP and execution of this [Membership] Agreement as a Transmission Owner.

3. SPP Tariff 1.45a Transmission Owner: Each member of SPP whose transmission facilities (in whole or in part) make up the Transmission System and has executed a membership agreement as a Transmission Owner. Those Transmission Owners that are not regulated by the Commission shall not become subject to Commission regulation by virtue of their status as

January 14, 2008 4

Transmission Owners under this Tariff; provided, however, that service over their facilities classified as transmission and covered by the Tariff shall be subject to Commission regulation.

IIIB. Provisions for Construction, Ownership and Financing

1. SPP Bylaws There are no provisions for construction, ownership or financing in the Bylaws.

2. SPP Membership Agreement – Rights, Powers and Obligations of SPP Section 2.1.1(j): SPP shall direct Transmission Owner pursuant to the provisions of Section 3.3 [Construction] to construct transmission facilities in accordance with coordinated planning criteria, or if necessary under the OATT. Section 2.1.5(b): As part of its planning activities, SPP shall be responsible for planning and directing or arranging, necessary transmission expansions, additions, and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service and to coordinate such efforts with the appropriate authorities.

3. SPP Membership Agreement – Commitments, Rights, Powers, and Obligations of Member Section 3.3 Construction: (a) As part of its planning activities, SPP shall be responsible for planning,

and for directing or arranging, necessary transmission expansion, additions, and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service and to coordinate such efforts with the appropriate state authorities. Transmission Owner shall use due diligence to construct transmission facilities as directed by SPP in accordance with the OATT and this [Membership] Agreement, subject to such siting, permitting, and environmental constraints as may be imposed by state, local and federal laws and regulations, and subject to the receipt of any necessary federal or state regulatory approvals. Such construction shall be performed in accordance with Good Utility Practice, applicable SPP Criteria, industry standards, Transmission Owner’s specific reliability requirements and operating guidelines (to the extent these are not inconsistent with other requirements), and in accordance with all applicable requirements of federal or state regulatory authorities. Transmission Owner shall be fully compensated to the greatest extent permitted by FERC, or other regulatory authority for the costs of construction undertaken in accordance with the OATT.

(b) After a new transmission project has received the required approvals and

been approved by SPP, SPP will direct the appropriate Transmission Owner(s) to begin implementation of the project. If the project forms a connection between facilities of a single Transmission Owner, that Transmission Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by multiple parties, all parties will be designated to provide their respective new

January 14, 2008 5

facilities. The parties will agree among themselves as to how much of the project will be provided by each entity. If agreement cannot be reached, SPP will facilitate the ownership determination process.

(c) A designated provider for a project can elect to arrange for a new entity

or another Transmission Owner to build and/or own the project in their place. If a designated provider(s) does not or cannot agree to implement the project in a timely manner, SPP will solicit and evaluate proposals for the project from other entities and select a replacement.

4. SPP Membership Agreement – Termination of Membership Section 4.4.3 of the SPP Membership Agreement addresses obligation to construct new facilities pursuant to an approved plan upon the Transmission Owner’s termination of membership. Section 4.3.3 Construction of Transmission Facilities: Any obligations relating to the construction of new facilities pursuant to an approved plan of SPP shall be renegotiated between SPP and the Transmission Owner prior to the Termination Date or promptly thereafter. If such obligations cannot be resolved through negotiations, they shall be resolved in accordance with the dispute resolution procedures in the Bylaws.

5. SPP Tariff – Firm Point-to-Point Transmission Service Section 15.4 Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: If the Transmission Provider determines that it cannot accommodate a Completed Application for Firm Point-To-Point Transmission Service because of insufficient capability on the Transmission System, the Transmission Provider and the affected Transmission Owner(s) will use due diligence to expand or modify the Transmission System to provide the requested Firm Transmission Service, consistent with its planning obligations in Attachment O, provided the Transmission Customer agrees to compensate the Transmission Provider for such costs pursuant to the terms of Section 27. The Transmission Provider and the affected Transmission Owner(s) will conform to Good Utility Practice and its planning obligations in Attachment O, in determining the need for new facilities and in the design and construction of such facilities.

6. SPP Tariff – Network Integration Transmission Service 1.19 Native Load Customer: The wholesale and retail power customers of the Transmission Owner(s) on whose behalf the Transmission Owner(s), by statute, franchise, regulatory requirement, or contract, has (have) undertaken an obligation to construct or operate the Transmission Owner's(s') system(s) to meet the reliable electric needs of such customers. In addition, Native Load Customers also may include the customers of the Federal Government on whose behalf the Government, by policy, statute, regulatory requirement, or contract, delivers Federal capacity and energy to meet all or a portion of the reliable electric needs of such customers.

Section 28.2 Transmission Provider and Transmission Owners Responsibilities: The Transmission Provider and Transmission Owners will plan, operate, and cause to be maintained its Transmission System in accordance with Good Utility Practice and its planning obligations in

January 14, 2008 6

Attachment O in order to provide the Network Customer with Network Integration Transmission Service over the Transmission System. The Transmission Owners, on behalf of their Native Load Customers, shall be required to designate resources and loads in the same manner as any Network Customer under Part III of this Tariff. This information must be consistent with the information used by the Transmission Provider to calculate available transfer capability. The Transmission Provider shall include the Network Customer's Network Load in Transmission System planning and shall, consistent with Good Utility Practice and Attachment O, endeavor to cause to be constructed and placed into service sufficient transfer capability to deliver the Network Customer's Network Resources to serve its Network Load on a basis comparable to the Transmission Owner(s') delivery of electric generating and purchased resources to Native Load Customers.

7. SPP Tariff – Attachment V – Large Generator Interconnection Article 11 Performance Obligation

Article 11.1 Interconnection Customer Interconnection Facilities. Interconnection Customer shall design, procure, construct, install, own and/or control Interconnection Customer Interconnection Facilities described in Appendix A, Interconnection Facilities, Network Upgrades and Distribution Upgrades, at its sole expense.

Article 11.2 Transmission Provider's Interconnection Facilities. Transmission Provider or Transmission Owner shall design, procure, construct, install, own and/or control the Transmission Provider's Interconnection Facilities described in Appendix A, Interconnection Facilities, Network Upgrades and Distribution Upgrades, at the sole expense of the Interconnection Customer.

Article 11.3 Network Upgrades and Distribution Upgrades. Transmission Provider or Transmission Owner shall design, procure, construct, install, and own the Network Upgrades and Distribution Upgrades described in Appendix A, Interconnection Facilities, Network Upgrades and Distribution Upgrades. The Interconnection Customer shall be responsible for all costs related to Distribution Upgrades. Unless Transmission Provider or Transmission Owner elects to fund the capital for the Network Upgrades, they shall be solely funded by Interconnection Customer.

Agreement for the Allocation of Responsibilities with Regard to the Large Generator Interconnection Procedure and Interconnection Agreement

Article III.1.0 Interconnection Service: The Parties recognize that the Transmission Provider will provide Interconnection Service pursuant to applicable terms of the SPP Tariff, and in particular, the Provisions of Attachment V, Standard Large Generator Interconnection Procedures and Agreement, as such provisions may be amended from time to time. Interconnection Service provides for the interconnection of the Interconnection Customer’s Generating Facility with the Transmission System. The Parties also recognize that while SPP is the Transmission Provider under the SPP Tariff, SPP does not own any Transmission Facilities, and Transmission Owners own the facilities to which Large

January 14, 2008 7

Generation Facilities are to be interconnected, and that the Transmission Owners may construct or modify facilities to allow the interconnection. While the Parties recognize that the Transmission Provider will be primarily responsible for undertaking Interconnection Studies and similar studies, and for transmission planning, Transmission Owners will be allowed to participate in these studies and activities to the extent consistent with the terms of the SPP Tariff. The Parties also recognize that construction activities and other construction-related matters may involve and be negotiated by the Transmission Provider, the applicable Transmission Owners, and by the Interconnection Customer. SPP shall not enter into any Interconnection Agreement with an Interconnection Customer that is contrary to these rights.

8. SPP Tariff – Attachment O – Transmission Planning and Expansion Procedures Introduction: …Transmission Owners are obligated to build facilities subject to regulatory approval under the provisions of this Tariff. The Transmission Provider will not build or own transmission facilities. These procedures neither obligate the Transmission Provider nor Transmission Owners to build or own facilities within another Transmission Owner’s area where a limit may exist. Transmission Owners may at any time voluntarily form associations and partnerships between Members or with non-Members to jointly construct and finance new transmission facilities provided such projects are subject to the assessment process of these Procedures. Section 3.0 Need for New Facilities: Undue limitation on the maintenance of the Transmission System and the provision of firm transmission service shall be deemed to create a need for new or upgraded facilities… This review can be initiated by any Member requesting firm transmission service under any applicable tariff… Approval of the reliability upgrades identified in the SPP Transmission Expansion Plan by the Board of Directors shall constitute approval for the appropriate Transmission Owners to begin implementation of projects for which financial commitment is required prior to the approval of the next SPP Transmission Expansion Plan.

Section 4.0 Construction:

(a) Each Transmission Owner shall use due diligence to construct transmission facilities as directed by the SPP Board of Directors subject to such siting, permitting, and environmental constraints as may be imposed by state, local and federal laws and regulations, and subject to the receipt of any necessary federal or state regulatory approvals. Such construction shall be performed in accordance with Good Utility Practice, applicable SPP Criteria, industry standards, each Transmission Owner’s specific reliability requirements and operating guidelines (to the extent these are not inconsistent with other requirements), and in accordance with all applicable requirements of federal or state regulatory authorities. Each Transmission Owner shall be fully compensated to the greatest extent permitted by The Commission, for the costs of construction undertaken by such Transmission Owner in accordance with this Tariff.

(b) After a new transmission project has been approved, the Transmission Provider will direct the appropriate Transmission Owners to begin implementation of the project. If the project forms a

January 14, 2008 8

connection between facilities of a single Transmission Owner, that Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by two different Transmission Owners or between a new facility and the facilities of a Transmission Owner, both entities will be designated to provide the new facilities. The two entities will agree between themselves how much of the project will be provided by each entity. If agreement cannot be reached, the Transmission Provider will facilitate the ownership determination process.

(c) A designated provider for a project can elect to arrange for another entity or another existing Transmission Owner to build and/or own the project in their place. If a designated provider or providers do not or cannot agree to implement the project in a timely manner, the Transmission Provider will solicit and evaluate proposals for the project from other entities and select a replacement designated provider.

9. SPP Tariff – Attachment O – Order 890 Compliance Filing The Order 890 compliance filing of Attachment O provides significant clarification of the planning and approval process for reliability and economic upgrades and authorization to construct such upgrades. However, the designation of the entity(ies) to construct upgrades, including the right of first refusal, remains the same in the compliance filing as in the effective Attachment O. Following are the approval and construction provisions from the Order 890 compliance filing of Attachment O to the SPP Tariff. VII. Approval of the SPP Reliability, Requested and Economic Upgrades 1) The annual list of reliability upgrades must be endorsed by the Markets

and Operations Policy Committee and approved by the SPP Board of Directors.

2) The annual list of potential Economic Upgrades and any Requested

Upgrades must be endorsed by the Markets and Operations Policy Committee and the SPP Board of Directors. When these upgrades have been endorsed they will be included in the SPP Transmission Expansion Plan.

3) The list of projects shall be posted on the SPP website by the

Transmission Provider. The Transmission Provider shall, in addition to the posting, e-mail notice of such posting to the stakeholders at least ten days prior to a meeting at which the SPP Board of Directors is expected to take action on accepting or modifying the list.

4) The list of reliability upgrades, Economic Upgrades and Requested Upgrades may be modified throughout the year by the SPP Board of Directors provided that such action shall be posted and noticed pursuant to this section.

IX. Construction of Transmission Facilities

1) The Transmission Provider shall not build or own transmission facilities.

The Transmission Provider, with input from the Transmission Owners

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and other stakeholders, will designate in a timely manner within the SPP Transmission Expansion Plan one or more Transmission Owners to construct, own, and/or finance each project in the plan.

2) Each Transmission Owner shall use due diligence to construct

transmission facilities as directed by the SPP Board of Directors subject to such siting, permitting, and environmental constraints as may be imposed by state, local and federal laws and regulations, and subject to the receipt of any necessary federal or state regulatory approvals. Such construction shall be performed in accordance with Good Utility Practice, applicable SPP Criteria, industry standards, each Transmission Owner’s specific reliability requirements and operating guidelines (to the extent these are not inconsistent with other requirements), and in accordance with all applicable requirements of federal or state regulatory authorities. Each Transmission Owner shall be fully compensated to the greatest extent permitted by the Commission for the costs of construction undertaken by such Transmission Owner in accordance with this Tariff.

3) A specific endorsed Economic Upgrade or endorsed Requested Upgrade

will be deemed approved for construction upon execution of a contract that financially commits a Project Sponsor to such upgrade or when such upgrade is otherwise funded pursuant to the Tariff.

4) After a new transmission project has been approved for construction in the SPP Transmission Expansion Plan, required pursuant to a Service Agreement, or required pursuant to an interconnection agreement, the Transmission Provider will authorize the appropriate Transmission Owners to begin implementation of the project for which financial commitment is required prior to the approval of the next update of the SPP Transmission Expansion Plan. If the project forms a connection between facilities of a single Transmission Owner, that Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by two different Transmission Owners or between a new facility and the facilities of a Transmission Owner, both entities will be designated to provide the new facilities. The two entities will agree between themselves how much of the project will be provided by each entity. If agreement cannot be reached, the Transmission Provider will facilitate the ownership determination process.

5) A designated provider for a project can elect to arrange for another entity

or another existing Transmission Owner to build and/or own the project in their place. If a designated provider or providers do not or cannot agree to implement the project in a timely manner, the Transmission Provider will solicit and evaluate proposals for the project from other entities and select a replacement designated provider.

IV. Reliability and Economic Upgrades

IVA. Recommendation 2 The SPP OATT, Bylaws and Membership Agreement language may not be sufficient or provide enough clarity to address both reliability and economic upgrades and this area should be reviewed.

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IVB. Discussion The SPP Membership Agreement and Attachment O to the SPP Tariff need to be clarified and made consistent concerning the rights, powers and obligations of both SPP and the Members in regard to reliability and economic upgrades. The Order 890 compliance filing of Attachment O provides significant clarification of the planning and approval process for reliability and economic upgrades and authorization to construct such upgrades. Section 2.1.1(j) of the SPP Membership Agreement states that SPP shall direct Transmission Owner pursuant to the construction provisions of the Agreement (Section 3.3) to construct transmission facilities in accordance with coordinated planning criteria, or if necessary under the OATT. Section 3.3(a) of the Agreement and Section 4.0(a) of Attachment O to the SPP Tariff state that each Transmission Owner will use due diligence to construct transmission facilities as directed by SPP; however, neither provision specifically states what types of upgrades that SPP can direct the Transmission Owners to construct.

Sections 2.1.5(b) and 3.3(a) of the SPP Membership Agreement state that as part of the planning activities, SPP is responsible for planning and directing or arranging, necessary transmission expansions, additions, and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service. These two sections refer only to upgrades to provide efficient, reliable and non-discriminatory transmission service and do not specifically address upgrades needed for interconnection service, upgrades needed to satisfy zonal reliability criteria or upgrades that have been shown to provide customers access to generation options such that the potential energy savings exceed the cost of the proposed upgrade (economic upgrades). The obligation to construct these types of upgrades (or upgrades identified in the SPP Transmission Expansion Plan) needs to be made consistent between Attachment O and the SPP Membership Agreement. Section 3.0 of Attachment O to the SPP Tariff specifies the trigger for a Transmission Owner to implement (construct) a reliability upgrade: “approval of the reliability upgrades identified in the SPP Transmission Expansion Plan by the Board of Directors shall constitute approval for the appropriate Transmission Owners to begin implementation of projects for which financial commitment is required prior to the approval of the next SPP Transmission Expansion Plan.” The effective SPP Tariff does not provide the trigger for a Transmission Owner (or other entity) to construct an economic upgrade. However, a trigger for constructing an economic upgrade is addressed in the Order 890 compliance filing of Attachment O (Section IX.3: A specific endorsed Economic Upgrade or endorsed Requested Upgrade will be deemed approved for construction upon execution of a contract that financially commits a Project Sponsor to such upgrade or when such upgrade is otherwise funded pursuant to the Tariff.). Section 3.3 of the SPP Membership Agreement and Section 4.0 of the effective Attachment O to the SPP Tariff both address construction. These effective provisions are essentially the same. Section IX of the Order 890 compliance filing of Attachment O provides significant clarification regarding the authorization to construct upgrades, including both reliability and economic upgrades. Section 3.3 of the SPP Membership Agreement needs to be reviewed and potentially updated to ensure that this Section and Section IX of the Order 890 compliance filing of Attachment O are consistent. Another approach would be to consider having the construction provision in only one governing document to avoid potentially having the two construction provisions getting out of sync.

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The Regional Tariff Working Group (RTWG) should be assigned the task of clarifying the appropriate sections of the SPP Membership Agreement and Attachment O to the SPP Tariff. There are several approaches to this assignment: (i) a limited approach fixing the existing pertinent sections of the governing documents; (ii) eliminating duplication of provisions, where appropriate, to avoid conflict if a provision gets modified in the future and a similar provision is not modified; or (iii) a major re-write. This Task Force recommends the limited approach of fixing the existing pertinent sections of the governing documents and possibly eliminating duplication of provisions to avoid conflict. A major re-write of Attachment O is not necessary, as the Order 890 compliance filing of Attachment O provides significant clarification regarding economic and other upgrades.

IVC. Other RTOs’ Approach to Similar Issues

1. PJM Schedule 6 of the PJM Operating Agreement is the Regional Transmission Expansion Planning Protocol for the PJM Region. Article 4.2 of the PJM Consolidated Transmission Owners Agreement sets forth the obligation for parties designated as the appropriate entities to construct, own or finance enhancements or expansions specified in the Regional Transmission Expansion Plan (RTEP) or required to expand or modify the transmission facilities pursuant to the PJM Tariff to construct and own or finance such facilities or to enter into appropriate contracts to fulfill its obligations. Although the provision in Article 4.2 does not specifically state reliability and economic-based enhancements and expansions, pursuant to Schedule 6 of the PJM Operating Agreement, the RTEP includes both reliability-based and economic enhancements and expansions.

2. ISO-NE Section II.48 of the ISO-NE Tariff is the Regional System Planning (RSP) Process for New England. The RSP identifies reliability and market efficiency upgrades. Schedule 3.09(a) of the ISO-NE Transmission Operating Agreement sets forth the obligation for each Participating Transmission Owner to own or construct (or cause to be constructed) any transmission upgrades that is designated in the RSP as necessary and appropriate for system reliability or economic efficiency. The provision in Schedule 3.09(a) specifically refers both reliability and economic upgrades. The Participating Transmission Owner may enter into contracts to fulfill any obligations associated with the ownership and construction of such upgrades.

3. MISO Attachment FF of the MISO Tariff is the Transmission Expansion Planning Protocol for MISO. Article 4.C of the MISO Transmission Owners Agreement sets forth the obligation to construct transmission facilities as directed by MISO. Section VI.C of Attachment FF requires the affected Transmission Owner(s), or other designated entity(ies), to make a good faith effort to design, certify, and build the designated facilities to fulfill the approved MISO Transmission Expansion Plan (MTEP). Based on the definition of MTEP in the MISO Tariff and the provisions of Attachment FF, the MTEP includes expansions or enhancements to support competition in bulk power markets (economic upgrades) and to maintain reliability.

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V. Construction of All Approved Projects

VA. Recommendation 4 Additionally, the SPP OATT should be reviewed to ensure that all projects approved by the SPP Board of Directors are constructed.

VB. Discussion The SPP governing documents should ensure that all projects approved by the SPP Board of Directors or required for the provision of service under the Tariff are constructed. Based on the discussion in this section, SPP’s effective governing documents, along with the Order 890 compliance filing of Attachment O to the Tariff, provide an obligation for the Transmission Owner, as designated in the SPP Transmission Expansion Plan or under the SPP Tariff, as appropriate, to construct upgrades. Therefore, the TOCTF concludes that the SPP Tariff does not need to be clarified or modified in this regard, with the possible exceptions of Section 28.2 of the SPP Tariff and of the “Agreement for the Allocation of Responsibilities with Regard to the Large Generator Interconnection Procedure and Interconnection Agreement” as described in Sections V.B.2 and V.B.3. A review should be performed by the RTWG to confirm whether these two clarifications should be made.

1. Reliability and Economic Upgrades The Order 890 compliance filing of Attachment O provides significant clarification of the planning and approval process for reliability and economic upgrades and authorization to construct upgrades, including reliability and economic upgrades. Refer to Sections III.B.9 and IV.B above.

2. Upgrades Required to Accommodate Transmission Service In accordance with Attachment Z to the SPP Tariff, SPP combines all long-term point-to-point and long-term designated network resource requests received during a specified period of time into a single Aggregate Transmission Service Study. Using this Aggregate Transmission Service Study process, SPP combines all requests received during an open season to develop a more efficient expansion of the transmission system that provides the necessary ATC to accommodate all such requests at the minimum total cost. The obligation to expand or modify the Transmission System for such long-term firm transmission service requests is provided for in Sections 15.4 and 28.2, respectively, of the SPP Tariff. (See Sections III.B.5 and III.B.6 above.) Pursuant to Section 15.4, for Firm Point-to-Point Transmission Service, if SPP determines that it cannot accommodate a Completed Application because of insufficient capability on the Transmission System, SPP and the affected Transmission Owner will use due diligence to expand or modify the Transmission System to provide the requested Firm Transmission Service, consistent with its planning obligations in Attachment O, provided the Transmission Customer agrees to compensate the Transmission Provider for such costs in accordance with the SPP Tariff. Pursuant to Section 28.2, for Network Integration Transmission Service, SPP will include the Network Customer's Network Load in Transmission System

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planning and, consistent with Attachment O, endeavor to cause to be constructed and placed into service sufficient transfer capability to deliver the Network Customer's Network Resources to serve its Network Load. Similar to the provision for Firm-Point-to-Point Transmission Service, Section 28.2 of the SPP Tariff should be clarified that the affected Transmission Owner will use due diligence to expand or modify the Transmission System to accommodate new or changed Designated Resources, consistent with Attachments O and Z1 to the SPP Tariff.

3. Upgrades Required to Accommodate Interconnection Service Articles 11.2 and 11.3 of the Large Generator Interconnection Agreement in Attachment V to the SPP Tariff provide an obligation for the Transmission Provider or Transmission Owner to design, procure, construct, install and own the Transmission Provider’s Interconnection Facilities and the Network Upgrades and Distribution Upgrades required to provide Interconnection Service, respectively. Article III.1.0 of the “Agreement for the Allocation of Responsibilities with Regard to the Large Generator Interconnection Procedure and Interconnection Agreement” clarifies that SPP does not own Transmission Facilities and that the Transmission Owners may construct or modify facilities to allow the interconnection. The phrase “may construct” does not convey that if the interconnection customer does not opt to construct required upgrades as identified in the interconnection agreement that there is an obligation for the Transmission Owner to construct such upgrades as agreed in the interconnection agreement. Although Attachment V provides for the term Transmission Provider to be read to include the Transmission Owner when the Transmission Owner is separate from the Transmission Provider, it should be made clear in the “Agreement for the Allocation of Responsibilities with Regard to the Large Generator Interconnection Procedure and Interconnection Agreement” that it is the Transmission Owner’s obligation to construct upgrades as agreed in the interconnection agreement.

VI. Multiple Entities Involved in Project

VIA. Recommendation 4 While it is generally expected that the project financier, owner, and operator would be the same entity; there should be nothing that prohibits a differentiation, such that financial partners or joint ventures could occur.

VIB. Discussion The provisions in SPP’s effective governing documents do not appear to preclude financial partners or joint ventures from constructing and financing transmission facilities; however, with one exception, SPP’s effective governing documents do not address this issue either. The introduction to Attachment O of the SPP Tariff states that Transmission Owners may at any time voluntarily form associations and partnerships between Members or with non-Members to jointly construct and finance new transmission facilities provided such projects are subject to the assessment process of Attachment O. In the Order 890 compliance filing of Attachment O this language was not retained. The TOCTF recommends that the RTWG consider whether

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the appropriate SPP governing document needs to specifically address whether partnerships and joint ventures to construct and finance transmission facilities are allowed and to specify any requirements of such partnerships or joint ventures.

VII. Guidance for Selecting a Qualified Entity to Construct

VIIA. Recommendation 5 SPP’s governing documents should be supplemented to provide specific guidance to direct the selection of a qualified entity should the incumbent Transmission Owner not carry out obligations arising from the approved STEP.

VIIB. Discussion SPP needs to develop a process and rules to assign or select a qualified entity to construct and own approved projects from the SPP Transmission Expansion Plan or from the Aggregate Transmission Service Study process for which the incumbent Transmission Owner does not or cannot carry out its obligations. Such rules need to be included in the SPP Tariff. The process to determine a qualified entity could use various approaches, such as (i) SPP designating a qualified entity or (ii) SPP selecting a qualified entity based on responses to a request for proposal. Developing the process and the associated rules should be assigned to a sub-group of the RTWG. After the rules are developed, SPP Tariff provisions should be drafted by the RTWG. The rules need to address:

• Requirements to provide notice that a qualified entity is going to be

sought to construct a project;

• Requirements to safeguard the confidential nature of information;

• Technical and financial requirements of a qualified entity;

• Process to select a qualified entity (i.e. seeking volunteers, inviting entities to respond to a formal request for proposal, etc.); and

• Criteria used to select a qualified entity and its proposal.

The evaluation criteria to select a qualified entity and its proposal may consider factors such as:

• Technical and financial qualifications of the entity that would be

responsible for building the project, including ability to obtain capital in a reasonable timeframe, existing sources of liquidity and any limitations on use of capital;

• Management of qualified entity, including length of tenure, experience

with financing and/or constructing transmission projects, and reputation within the industry;

• Based on the transmission and generation outage schedules required to

accommodate the construction proposal, estimated financial and

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reliability impacts on Transmission Customers and load during construction and installation of the project and on generators (for example, a proposal might minimize outages by performing hot line work or might minimize impact of outages by performing work requiring outages on weekends);

• Ability to meet project milestones;

• Timing for completion of the project; and

• Assurance that the entity responsible for building the project is able to perform.

VIIC. Other RTOs’ Approach to Similar Issues

1. PJM Schedule 6 of the PJM Operating Agreement governs the process by which the Regional Transmission Expansion Plan (RTEP) is developed. Section 1.4 of Schedule 6 provides that the RTEP will include a designation of the Transmission Owner(s) or other entity that will construct, own and/or finance each transmission enhancement and expansion in the RTEP. However, no details are provided regarding how PJM makes the designation. In the event the entity designated as responsible for construction, owning or financing a new economic-based enhancement or expansion declines to construct, own or finance such expansion, the expansion will not be included in the RTEP. A report will be filed with the FERC in order to permit the FERC to determine what action, if any, it should take. This report also will include information regarding PJM Board approved accelerations of reliability-based enhancements or expansions that an entity declines to accelerate (Sections 1.5.6.c.iii and 1.7.d of Schedule 6). Schedule 6 does not address the event that an entity designated as responsible for construction, owning or financing a new reliability-based enhancement or expansion declines or is unable to construct, own or finance such expansion.

2. ISO-NE Section II.48 of the ISO-NE Tariff governs the process by which the Regional System Plan (RSP) is developed. Section II.48.6 provides that the RSP will include a designation of the Transmission Owner(s) or other entity that will construct and own or finance reliability and market efficiency transmission upgrades in the RSP. However, no details are provided regarding how ISO-NE makes the designation. Schedule 3.09(a) of the ISO-NE Transmission Operating Agreement allows the Participating Transmission Owner to enter into contracts to fulfill any obligations associated with the ownership and construction of such upgrades. In the event a Participating Transmission Owner designated by ISO-NE (i) does not construct or indicates in writing that it does not intend to construct an upgrade (reliability or market efficiency) in the RSP; or (ii) demonstrates that it has failed to obtain necessary approvals or property rights, ISO-NE will file a report with the FERC on the results of the planning process. The report will include a report from the Participating Transmission Owner responsible

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for the planning, design or construction of the upgrade, in order to permit the FERC to determine what action, if any, it should take. (Section II.48.6.a of the ISO-NE Tariff.) Prior to ISO-NE becoming an RTO in February 2005, the New England Power Pool Tariff, which ISO-NE administered, contained a provision to allow ISO-NE to develop and circulate a request for proposals inviting any entity, including Transmission Owners, to build an upgrade included in the NEPOOL Transmission Plan. The provision is Attachment A to this document. The provision was not included in the ISO-NE Tariff when ISO-NE became an RTO.

3. MISO Ownership and construction of upgrades in the MISO Transmission Expansion Plan (MISO) is addressed in Appendix B to the MISO Transmission Owners Agreement. Ownership and the responsibility to construct facilities which are connected:

(a) to a single Owner’s system belong to that Owner; (b) between two or more Owners’ facilities belong equally to each other,

unless the Owners otherwise agree; and (c) between the Owner(s)’ system and a system or systems that are not

part of the MISO belong to the Owner(s) unless the Owner(s) and the non-MISO party(ies) otherwise agree.

If the designated Owner is financially incapable of carrying out its construction responsibilities or would suffer demonstrable financial harm from such construction, alternate construction arrangements may be identified. Depending on the specific circumstances, alternate arrangements may include solicitation of other Owners or others to take on financial and/or construction responsibilities. Appendix B does not provide any details regarding how such a solicitation would be performed. Also, Appendix B states that third-parties are permitted and encouraged to participate in the financing, construction and ownership of new transmission facilities specified in the MISO Transmission Expansion Plan (MTEP). But again, provides no details regarding how this would be accomplished. Appendix B also provides that in the event interest among the other Owners and entities is not sufficient to proceed with a project in the MTEP, all Owners, subject to applicable regulatory requirements, are responsible for sharing in the financing of the project and/or hiring contractor(s) to construct the needed transmission facility; provided, however, the Owners; obligations under this sentence are subject to the Owners being satisfied that they will be compensated fully for their investments and will not be subject to additional regulatory requirements, unless the Owners otherwise agree to waive either or both of these requirements. However, Appendix B does not specify whether “needed transmission facility” means a reliability upgrade, an economic upgrade or either type of upgrade in the MTEP.

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VIII. New Qualified Entity Becoming a Transmission Owner

VIIIA. Recommendation 6 The governing documents should be reviewed to identify whether there are any provisions that may need modification to allow a new, qualified entity to become a Transmission Owner under the OATT and Membership Agreement.

VIIIB. Discussion The SPP Membership Agreement, based on the definition of Non-Transmission Owner in the Membership Agreement, allows a Member that owns or controls Tariff Facilities to change its status to become a Transmission Owner under the Membership Agreement by providing notice to SPP and executing the Membership Agreement as a Transmission Owner. However, no additional detail is provided in the Membership Agreement. Consideration should be given as to whether additional clarification is needed beyond relying on the definition of Non-Transmission Owner as to how a new, qualified entity becomes a Transmission Owner. Also, the Membership Agreement should be clarified to indicate that a Transmission Owner may subcontract its functions under the Membership Agreement; but the ultimate responsibility for fulfilling obligations under the Membership Agreement remains with the Transmission Owner. This task should be assigned to the MOPC.

VIIIC. Other RTOs’ Approach to Similar Issues

1. PJM Article 3.1 of the PJM Consolidated Transmission Owners Agreement provides that any entity that: (i) owns, or, in the case of leased facilities, has rights equivalent to ownership in, Transmission Facilities; (ii) has in place all equipment and facilities necessary for safe and reliable operation of such Transmission Facilities as part of the PJM Region; and (iii) has committed to transfer functional control of its Transmission Facilities to PJM shall become a Party to the Agreement. Transmission Facilities are those facilities that: (i) are within the PJM Region; (ii) meet the definition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have been classified as transmission facilities in a ruling by FERC addressing such facilities; and (iii) have been demonstrated to be integrated with the Transmission System of the PJM Region and integrated into the planning and operation of such to serve the power and transmission customers within the PJM Region.

2. ISO-NE In accordance with Article 11.06 of the ISO-NE Transmission Operating Agreement, any owner of transmission facilities in New England may become a Participating Transmission Owner under the Agreement and a party to the Agreement by executing a counterpart to the Agreement with the consent or approval of ISO-NE; consent or approval of the other Participating Transmission Owners is not required. Merchant facilities are not subject to the Agreement. Also, an Independent Transmission Company cannot be a Participating Transmission Owner under

January 14, 2008 18

the Agreement. The role of an Independent Transmission Company would be set forth in a separate agreement between ISO-NE and the Independent Transmission Company.

3. MISO In accordance with Section V.A.2 of the MISO Transmission Owners Agreement, a new Member may join as an Owner, provided that it (i) owns, operates, or controls facilities used for the transmission of electricity in interstate commerce (as determined by the MISO in applying the 7 factor test) that are physically interconnected with the facilities of an existing Owner; (ii) agrees to sign the Agreement, to be bound by its terms, and to make any and all payments or contributions required by the Agreement; and (iii) agrees to sign the Funds Trust Agreement, to be bound by all its terms, and to make any and all payments or contribution required under the Funds Trust Agreement if and/or when the Member receives revenues from transmission service, and prior to existence of any right of the Member to receive revenues from transmission service under the Transmission Tariff executes the Funds Trust Agreement. Upon fulfillment of the above conditions, and upon completion of any physical integration of the new Owner’s facilities with the Transmission System, the MISO Board shall allow the new Member to become a signatory to the Agreement. In general, an Owner must own, operate, or control interstate transmission facilities; however, on a case-by-case basis, the MISO Board may waive the requirement that such facilities be physically interconnected if allowing the Member also to become an Owner will result in significant net benefits to the MISO and its Members.

IX. Transmission Interconnection

IXA. Recommendation 1 SPP needs a process for transmission interconnection as has been done for Generator Interconnections that go beyond the present Transmission Working Group (TWG) technical review to assess costs and impacts of the transmission interconnection.

IXB. Discussion SPP may need to develop a more formal process for review of transmission interconnections. Attachment V to the SPP Tariff provides a detailed formal process for review and implementation of generator interconnections. The existing TWG process for review of transmission interconnection is not as detailed as the generator interconnection process and primarily takes place outside the regular TWG meetings which may limit stakeholder participation in the process. Also, the existing TWG process does not address disputes between affected parties. The TOCTF recommends that (i) the TWG develop the process, including specifying any technical requirements that need to be included in the pro forma transmission interconnection agreement; and (ii) the RTWG develop the tariff language for the process and for the pro forma transmission interconnection agreement.

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IXC. Other RTOs’ Approach to Similar Issues

1. PJM Section VI of the PJM Tariff provides a clear process for merchant transmission facilities to interconnect. This process is similar to the generator interconnection procedure. The details of the process are contained in the PJM Manuals. PJM added the provisions for merchant transmission interconnections to its Tariff in response to protests.

2. ISO-NE Section I.9 of the ISO-NE Tariff provides for review of Market Participants, including Transmission Owners, proposed plans. Each Market Participant and Transmission Owner must submit to ISO-NE information, in a form prescribed in one of ISO-NE’s planning procedures, regarding (i) any new or materially changed plan for additions to, retirements of, or changes in the capacity of any supply and demand-side resources or transmission facilities rated 69 kV or above, and (ii) any new or materially changed plan for any other action to be taken by the Market Participant or Transmission Owner which may have a significant effect on the stability, reliability or operating characteristics of the Transmission Owner’s transmission facilities, the transmission facilities of another transmission owner, or the system of a Market Participant. A set of ISO-NE planning procedures describes the proposed plan application process and provides guidelines for conducting and evaluating proposed plan application analyses. Proposed plans requiring an application and review include transmission facilities identified in ISO-NE’s Regional System Plan. Section II.48 of the ISO-NE Tariff provides that any entity has the right to propose and construct the addition of merchant transmission facilities, subject to compliance with the Tariff and any other applicable requirements with respect to the interconnection of bulk power facilities with the New England Transmission System. The ISO-NE Tariff does not set forth a process for such interconnection.

X. Ratings

XA. Recommendation 3 SPP should support the development of operating criteria/facility ratings that insure a consistent level of service across multiple utilities for major transmission projects. Operating criteria/facility ratings are distinct from construction standards.

XB. Discussion For major transmission projects that cross multiple utilities, the facility rating should not change at the point of change of ownership or at some geographic point if the facility construction is the same on both sides of the point. A difference in operating criteria between multiple Transmission Owners along the same physical transmission line de-rates the entire facility. In order to optimize the value of a project, such as the EHV Overlay Project, there is a need for operating criteria associated with the project itself (or individual transmission lines or groups of transmission lines that are part of the project) to avoid situations where line ratings change between Transmission Owners simply

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because the individual Transmission Owner’s operating criteria are different and there is no difference in the electrical/physical characteristics of the line. The intent is to try to insure consistent line ratings across multiple utilities for major transmission projects as part of the planning process in Attachment O of the SPP Tariff. However, the actual treatment of facility ratings for a project or multi-owner facility needs to be addressed in the appropriate agreements among the Transmission Owners (and SPP) regarding the project or facility itself, such as an interconnection or operating agreement. The MOPC should consider whether it is appropriate to include trying to insure consistent line ratings across multiple utilities for major transmission projects as part of the planning process in Attachment O.

XI. Task Priority The TOCTF Recommendations could encompass substantial effort and changes to SPP governing documents. The Task Force considered prioritization of these tasks to aid those groups charged with multiple tasks in determining how and when they should address each issue. The tasks to be undertaken are summarized here as prioritized by the TOCTF with “A” being the highest priority and “C” being the lowest priority.

XIA. Priority A

1. Recommendation 2 TOCTF Recommendation: The SPP OATT, Bylaws and Membership Agreement language may not be sufficient or provide enough clarity to address both reliability and economic upgrades and this area should be reviewed. TOCTF Assignment and Prioritization: The SPP Membership Agreement and Attachment O to the SPP Tariff need to be clarified and made consistent concerning the rights, powers and obligations of both SPP and the Members in regard to reliability and economic upgrades. The RTWG should be assigned the task of clarifying the appropriate sections of the SPP Membership Agreement and Attachment O to the SPP Tariff. There are several approaches to this assignment: (i) a limited approach fixing the existing pertinent sections of the governing documents; (ii) eliminating duplication of provisions, where appropriate, to avoid conflict if a provision gets modified in the future and a similar provision is not modified; or (iii) a major re-write. The TOCTF recommends the limited approach of fixing the existing pertinent sections of the governing documents and possibly eliminating duplication of provisions to avoid conflict. A major re-write of Attachment O is not necessary, as the Order 890 compliance filing of Attachment O provides significant clarification regarding economic and other upgrades.

2. Recommendation 6 TOCTF Recommendation: The governing documents should be reviewed to identify whether there are any provisions that may need modification to allow a new, qualified entity to become a Transmission Owner under the OATT and Membership Agreement.

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TOCTF Assignment and Prioritization: The SPP Membership Agreement, based on the definition of Non-Transmission Owner in the Membership Agreement, allows a Member that owns or controls Tariff Facilities to change its status to become a Transmission Owner under the Membership Agreement by providing notice to SPP and executing the Membership Agreement as a Transmission Owner. However, no additional detail is provided in the Membership Agreement. Consideration should be given as to whether additional clarification is needed beyond relying on the definition of Non-Transmission Owner as to how a new, qualified entity becomes a Transmission Owner. Also, the Membership Agreement should be clarified to indicate that a Transmission Owner may subcontract its functions under the Membership Agreement; but the ultimate responsibility for fulfilling obligations under the Membership Agreement remains with the Transmission Owner. This task should be assigned to the MOPC.

XIB. Priority B

1. Recommendation 1 TOCTF Recommendation: SPP needs a process for transmission interconnection as has been done for Generator Interconnections that go beyond the present Transmission Working Group (TWG) technical review to assess costs and impacts of the transmission interconnection.

TOCTF Assignment and Prioritization: SPP may need to develop a more formal process for review of transmission interconnections as has been done for generator interconnections under Attachment V to the SPP Tariff, including developing a pro forma transmission interconnection agreement. The existing TWG process for review of transmission interconnection is not as detailed as the generator interconnection process and primarily takes place outside the regular TWG meetings which may limit stakeholder participation in the process. Also, the existing TWG process does not address disputes between affected parties. The TOCTF recommends that (i) the TWG develop the process, including specifying any technical requirements that need to be included in the pro forma transmission interconnection agreement; and (ii) the RTWG develop the tariff language for the process and for the pro forma transmission interconnection agreement.

2. Recommendation 3 TOCTF Recommendation: SPP should support the development of operating criteria/facility ratings that insure a consistent level of service across multiple utilities for major transmission projects. Operating criteria/facility ratings are distinct from construction standards TOCTF Assignment and Prioritization: The TOCTF recommends that the MOPC consider whether it is appropriate to include trying to insure consistent line ratings across multiple utilities for major transmission projects as part of the planning process in Attachment O.

3. Recommendation 5 TOCTF Recommendation: SPP’s governing documents should be supplemented to provide specific guidance to direct the selection of a qualified entity should the incumbent Transmission Owner not carry out obligations arising from the approved STEP.

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TOCTF Assignment and Prioritization: SPP needs to develop a process and rules to assign or select a qualified entity to construct and own approved projects from the SPP Transmission Expansion Plan or from the Aggregate Transmission Service Study process for which the incumbent Transmission Owner does not or cannot carry out its obligations. Such rules need to be included in the SPP Tariff. The process to determine a qualified entity could use various approaches, such as (i) SPP designating a qualified entity or (ii) SPP selecting a qualified entity based on responses to a request for proposal. The TOCTF recommends that a sub-group of the RTWG develop the process and the associated rules. After the rules are developed, the RTWG should develop the SPP Tariff provisions.

XIC. Priority C

1. Recommendation 4 TOCTF Recommendation (Part 1): While it is generally expected that the project financier, owner, and operator would be the same entity; there should be nothing that prohibits a differentiation, such that financial partners or joint ventures could occur. TOCTF Assignment and Prioritization: The provisions in SPP’s effective governing documents do not appear to preclude financial partners or joint ventures from constructing and financing transmission facilities; however, SPP’s effective governing documents do not address this issue either. The TOCTF recommends that the RTWG determine whether a specific provision (i) to allow financial partners and joint ventures should be included in the appropriate SPP governing document and whether requirements of such partnerships or joint ventures need to be specified in that document. TOCTF Recommendation (Part 2): Additionally, the SPP OATT should be reviewed to ensure that all projects approved by the SPP Board of Directors are constructed.

TOCTF Assignment and Prioritization: The SPP governing documents should ensure that all projects approved by the SPP Board of Directors or required for the provision of service under the Tariff are constructed. Based on the discussion Section VB of this document, SPP’s effective governing documents, along with the Order 890 compliance filing of Attachment O to the Tariff, provide an obligation for the Transmission Owner, as designated in the SPP Transmission Expansion Plan or under the SPP Tariff, as appropriate, to construct upgrades. Therefore, the TOCTF concludes that the SPP Tariff does not need to be clarified or modified in this regard, with possibly two exceptions. The TOCTF recommends that the RTWG determine whether the following clarifications need to be made: 1. Section 28.2 states that the Transmission Provider shall endeavor to

cause to be constructed and placed into service sufficient transfer capability to deliver the Network Customer's Network Resources to serve its Network Load on a basis comparable to the Transmission Owner(s') delivery of electric generating and purchased resources to Native Load Customers. Similar to the provision for Firm-Point-to-Point Transmission Service, should Section 28.2 of the SPP Tariff state that the affected Transmission Owner will use due diligence to expand or modify the

January 14, 2008 23

Transmission System to accommodate new or changed Designated Resources, consistent with Attachments O and Z1 to the SPP Tariff?

2. Article III.1.0 of the “Agreement for the Allocation of Responsibilities with

Regard to the Large Generator Interconnection Procedure and Interconnection Agreement” states that SPP does not own Transmission Facilities and that the Transmission Owners may construct or modify facilities to allow the interconnection. The phrase “may construct” does not convey that if the interconnection customer does not opt to construct required upgrades as identified in the interconnection agreement that there is an obligation for the Transmission Owner to construct such upgrades as agreed in the interconnection agreement. Although Attachment V provides for the term Transmission Provider to be read to include the Transmission Owner when the Transmission Owner is separate from the Transmission Provider, should it be made clear in the “Agreement for the Allocation of Responsibilities with Regard to the Large Generator Interconnection Procedure and Interconnection Agreement” that it is the Transmission Owner’s obligation to construct upgrades as agreed in the interconnection agreement?

January 14, 2008 24

Attachment A New England Power Pool RFP Process

51.6 Request for Proposals (“RFP”) Process For Upgrades:

(a) Except as otherwise provided in subsections (e) or (f) of this Section 51.6 below, the System Operator shall circulate a request for proposals (“RFP”) inviting any entity or entities, including without limitation Transmission Owners, to build an Upgrade included in the NEPOOL Transmission Plan. The RFP shall be prepared by the System Operator which may, to the extent desired, consult with the Transmission Owner(s) to obtain necessary data, information and technical specifications that the System Operator requires to prepare the RFP. The RFP shall include appropriate requirements to safeguard the confidential nature of information provided to the System Operator in accordance with applicable commercial practices, the requirements of the NEPOOL Information Policy and the requirements of any applicable Commission order. Each such RFP shall require that respondents meet specified technical and financial qualifications and submit proposals (i) that conform with all the requirements of subsection (a) of Section 51.3 and reasonable Transmission Owner requirements and specifications identified in the RFP which are not inconsistent with Commission policy, (ii) that are consistent with other applicable accepted engineering practices, governmental, technical, and financial requirements, and (iii) that do not use a Transmission Owner’s facilities, rights-of-way or other property, provided that the affected Transmission Owner may voluntarily agree, in its own discretion, to the use of its property in connection with a proposal.

(b) The System Operator shall develop selection criteria and in doing so may consult with the

Transmission Expansion Advisory Committee and post the criteria on the System Operator’s website before it issues the RFP. The evaluation criteria may consider any or all of the following nonexclusive factors: (i) the qualifications of the entity that would be responsible for implementing the proposal to build the proposed Upgrade; (ii) the estimated financial and reliability impacts on Transmission Customers and load during and after construction and installation of the proposed Upgrade if the proposal is accepted and implemented; (iii) the timing for completion of the proposal; (iv) the assurance that the entity responsible for implementing the proposal is able to perform; and (v) the mobilization or demobilization of facilities affected by the building of the proposed Upgrade during construction and installation.

(c) The issuance of an RFP for an Upgrade shall not preclude the modification of a NEPOOL

Transmission Plan in accordance with Section 51.4(c), including, without limitation, a modification that eliminates such Upgrade from the recommended plan.

(d) Any entity whose proposal is accepted by the System Operator in accordance with

subsection (b) shall be compensated in accordance with the terms of its accepted proposal, without regard to whether the actual project cost for the Upgrade was less than or greater than the costs reflected in the accepted proposal.

(e) The System Operator in its discretion may exempt certain Upgrades from the RFP

requirements of this Section 51.6 pursuant to standards established by the System Operator. In such circumstances, the Transmission Owner or Owners on whose system(s) the proposed Upgrade in the Plan is located, or its/their designee(s), shall be designated as the appropriate entity responsible for completion of that Upgrade, in accordance with the requirements of Section 51.7.

(f) No proposed Merchant Transmission Facility and no Upgrade that uses the facilities,

rights-of-way or other property of a Transmission Owner, except as the affected Transmission Owner may voluntarily agree, in its own discretion, to such use, shall be the

January 14, 2008 25

subject of the RFP process of this Section 51.6. No provision of Section 51 affects any obligations to interconnect new customers to the PTF imposed by other provisions of this Tariff or the Federal Power Act.

Communications Strategy

Level 5 Aggressive

Linkages strengthened through trade associations to expand outreach.

Develop annual education program on electricity technologies and present to all new regulators.

Expand proactive efforts to selected state legislators (in cooperation with SPP members).

Expand efforts to establish joint projects with stakeholders to provide greater impact of issues (without compromising SPP objectivity and reputation).

Develop teams of spokespersons on various topics to present information to non-utility groups.

Level 4 Integrated

Organized across SPP sectors to provide holistic view of issues.

Develop an annual outreach plan for getting information / presentations to regulatory commissions and staff.

Develop long-term educational approach toward Hill staffers using local seminars and visits to SPP facilities.

Assign the equivalent of “account executives” to meet periodically with selected stakeholders to engage them in SPP outreach effort through their organizations’ communications channels.

Develop information papers for widespread distribution to media (and other targeted audiences). Support with expanded public information on SPP.org.

Level 3 Proactive

Report findings summarized and provided to industry journals, industry trade press (e.g. Energy Daily), and broader media (e.g. NY Times).

Provide information summaries to all state commissions and make them aware of SPP work on website.

Conduct SPP executive level visits with members of Senate/House. Conduct briefings to open audiences on the Hill.

Conduct personal visits (some at executive level) with stakeholder groups to inform them of SPP issues and activities.

Establish “campaigns” with key trade press and national media to inform them of SPP activities on key issues.

Level 2 Active

Report findings from individual programs summarized and provided to industry technical/science journals.

Seek opportunities to present at NARUC and other meetings.

Periodically meet with the relevant committees/staff to inform them of issues and activities. Provide report summaries on relevant issues and activities.

Conduct direct email campaigns to various groups to inform them of SPP issues. Provide report summaries on relevant issues.

Issue news releases on relevant issue results. Coordinate with members on regional/local releases as requested.

Level 1 Reactive

Issue information regarding activities to react to industry inquiries or on a selected topic only.

Provide information to members. Present to others only when requested.

Only respond to requests for information and make staff aware of SPP.org content.

Respond to inquiries for information and make aware of SPP.org content.

Maintain public content on SPP.org for interested parties searching for information.

Industry

Regulators

Legislators

Other Stakeholders

General Public

January 7, 2008

The Honorable Kimberly D. Bose, SecretaryFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426

Re: Entergy Services, Inc., Docket No. ER05-1065-000The ICT’s Annual Performance Report

Dear Secretary Bose:

The Southwest Power Pool, Inc. (“SPP”), as the Independent Coordinator of Transmission (“ICT”) for the Entergy Services, Inc. (“Entergy”) system, hereby submits the ICT’s First Annual Performance Report, in accordance with the Federal Energy Regulatory Commission’s orders approving the establishment of the ICT and section 7 of Attachment S in Entergy’s Open Access Transmission Tariff (“OATT”).1

The ICT will serve a copy of this report to all Interested Government Agencies and will make the report publicly available by posting it electronically on Entergy’s OASIS.

If there are any questions related to this matter, please contact the undersigned at the number listed above.

Respectfully submitted,

/s/ David S. Shaffer____David S. Shaffer

Counsel for the ICT

Attachments

K:\SPP-ICT\Annual Report\cover letter to ICT Annual Report 2008.doc

1 See Entergy Services, Inc., 115 FERC ¶ 61,095, order on reh’g, 116 FERC ¶ 61,275, order on compliance,

117 FERC ¶ 61,055 (2006), order on reh’g, 119 FERC ¶ 61,187 (2007).

Independent Coordinator of Transmission (ICT) for Entergy -

Annual Performance ReportNovember 17, 2006 to November 17, 2007

FERC ICT Annual Performance Report: November 17, 2006 - November 17, 2007

Table of Contents

I. INTRODUCTION AND OVERVIEW................................................................1

II. ASSESSMENT AND SELF-EVALUATION OFICT’S FUNCTIONS..............................................................................................3

1. Reliability Coordination ...........................................................................3

2. Tariff Administration................................................................................6

3. Planning and Tariff Studies......................................................................8

4. WPP ..........................................................................................................10

5. Stakeholder Process.................................................................................11

6. Users Group .............................................................................................13

7. ICT Stakeholder Survey .........................................................................14

III. ATTACHMENT S METRICS ...........................................................................16

IV. CONCLUSION ....................................................................................................20


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I. INTRODUCTION AND OVERVIEW

This report summarizes the first year of operations following the installation of the Southwest Power Pool, Inc. (“SPP”) as the Independent Coordinator of Transmission (“ICT”) for the Entergy system. This report complies with the requirements of the Commission’s April 24, 2006 Order, including the specific requirement of an annual assessment addressing the effectiveness of the ICT, and the compilation of performance metrics measuring the success of the ICT and the Weekly Procurement Process (“WPP”) as well as the reporting requirement of section 7 of Attachment S to Entergy’s Open Access Transmission Tariff (“OATT” or “Tariff”).1

As documented herein, the past year has presented numerous challenges and successes to the ICT, stakeholders and Entergy. Adding to the already formidable list of transitional issues were the compliance requirements associated with the Order Nos. 890 and 693 reforms, many of which directly implicated certain functional responsibilities of the ICT. The incremental workload and resource demands resulting from these reforms necessitated the significant expansion of ICT staff.

While there remains significant unfinished business, the first year of ICT operations delivered material improvements in several critical areas. Highlighting the ICT’s contributions and successes are the following:

• The ICT’s assumption of responsibility over the calculation of Available Flowgate Capability (“AFC”) and the processing of transmission service requests (“TSR”) resulted in improved identification and reporting of data handling errors and an ongoing, top-down, review of Entergy’s automated software resulting in thirty-eight (38) instances of reported corrections to the AFC methodology.

• The ICT’s transmission planning initiatives, including the completion of the ICT Strategic Transmission Expansion Plan (“ISTEP”), provided the platform for focused consideration of both reliability and economic expansion projects within the Entergy footprint.

• The ICT’s preparation of an engineering analysis offered a independent technical examination of long-standing load-pocket problems in the Acadiana area of Louisiana.

1 Entergy Services, Inc., 115 FERC ¶ 61,095, at P 299 (2006) (“ICT Approval

Order”).


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• The installation of a facility upgrade along the White Bluff to Keo transmission path, which was the direct result of numerous discussions by and between the ICT and Entergy, provided significant relief to chronic constraints in this area and reduced the future likelihood of Transmission Loading Relief (“TLR”) events.

• The dedication of significant resources ensured that the ICT met its obligations to actively oversee the design and testing of the WPP, including the ICT’s verification of system models and processes and the initiation of WPP market trials.

• Through ICT efforts, dialogue and interaction with stakeholders was improved, including efforts by the ICT to convene meetings between ICT management and individual stakeholders and/or small stakeholder groups, host representatives from some state regulatory commissions for on-site tours and one-on-one meetings, and organize and facilitate regularly-convened Stakeholder Policy Committee (“SPC”) and working group and task force meetings.

In addition, the past year has identified several high-priority action items for consideration in 2008. Among these items are:

• The implementation of the WPP following successful testing of all models and systems;

• Improved, streamlined procedures to facilitate more focused dialogue between stakeholders and the ICT;

• Continued efforts to improve AFC calculations and upgrade Entergy’s OASIS Automation (“OA”) software;

• Investigation of further remedial options to address TLRs;

• Development and refinement of transmission planning/expansion priorities: and,

• Further interaction with all state regulatory commissions.

The ICT looks forward to building on the accomplishments of the past year and working with Entergy and stakeholders to meet the challenges of the future.


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II. ASSESSMENT AND SELF-EVALUATION OF ICT’S FUNCTIONS

In accordance with section 7(a)(2) of Attachment S to Entergy’s OATT, the ICT provides the following assessment and self-evaluation of the ICT’s first year of operations. The ICT will report on each of the ICT’s functional areas of responsibility under the Entergy OATT and discuss the problems identified by transmission customers and stakeholders, achievements by the ICT, and areas for improvement as the ICT continues to work with Entergy and stakeholders to reform transmission service access on Entergy’s system.

1. Reliability Coordination

The ICT successfully assumed and implemented Reliability Coordination duties in a very short period of time, and a high level of system-wide reliability has been successfully maintained on the Entergy system through the first year of operation. The ICT was required to implement a greater number of TLRs during the first year compared to the prior year. As discussed in detail below, the ICT is taking action to identify the reasons for the increase and implementing steps to reduce the TLR events while maintaining a high standard of reliable operation on the Entergy system.

Throughout the first year of operation, the ICT has faced criticism of its role as Reliability Coordinator due to the increased number of TLR events, especially Level 5 TLR events, as well as the associated curtailment of firm transmission. The ICT has addressed this issue in its Quarterly Performance Reports and through the stakeholder process noting, among other things, record temperatures and peak load on the Entergy system as factors to the higher incidence of TLRs. Additionally, the ICT has explained that the increase in TLR 5 events can be traced to Entergy’s policy decision to no longer provide voluntary redispatch during a Level 4 TLR event. The increase in TLR events and other reliability related problems on Entergy’s system were neither caused by nor within the preventable control of, the ICT. At all times, the ICT acted within NERC guidelines and good utility practice when implementing the TLR process.

In recent months, the ICT has been pro-actively investigating solutions that could minimize the number and severity of TLR events on Entergy’s transmission system. As part of this effort, the ICT developed a Reliability Improvement Plan and presented this plan to stakeholders at the December SPC meeting. The plan incorporates a combination of generation redispatch, operational solutions, and planning solutions that should improve overall system reliability, thus reducing the number of TLRs in the future and creating new options for the ICT that will effectively address the reliability problems experienced during the past year.

The proposed generation redispatch solution focuses on three primary areas: defined load pockets within the Entergy system, the North/South Generation Ratio, and redispatch options associated with Network Native Load (“NNL”) responsibility during a


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TLR. During many of the circumstances that led to TLRs during the past year, the import limits for certain load pockets impacted flowgates located outside of the load pocket. Accordingly, the import limits for all load pockets within Entergy’s system should be established, enforced, and included in any evaluation of outages, transmission service request, or other changes to the transmission system. Moreover, the minimum generation requirements for load pocket areas must be adequately identified and respected in both real-time and in the reliability and planning models. The ICT further believes that there is a need to investigate a North/South Generation Ratio, whereby the network generation in each region is kept at a predefined ratio to prevent some of the reliability problems that were experienced this past year with flows traveling across the Entergy system. After a North/South Generation Ratio is accepted and implemented, the issues experienced with certain flowgates highly affected by North to South flows across the Entergy system should be more controlled and better managed. While the North to South issue is complicated by generation patterns of the neighboring Balancing Authorities in and around Entergy, the ICT believes that these generation patterns could be accounted for in the development of any ratio. Finally, when the Reliability Coordinator performs a reliability study for a given constraint, the amount of NNL responsibility and firm curtailments that will be required in the event of a Level 5 TLR are calculated and provided to the Balancing Authorities. The ICT believes that if the Balancing Authorities are given the opportunity to voluntarily redispatch generation to meet defined NNL responsibility levels, the likelihood of the ICT issuing a TLR Level 5 could be materially reduced.

The proposed operational solution developed by the ICT involves an increased use of Operating Guides in order to avoid the more blunt TLR process. These Operating Guides must be adequately studied and fully tested before implementation, but the ICT believes that, in certain circumstances, these guides could be used in the place of the TLR process. In addition, the Reliability Improvement Plan suggested that the ICT, Entergy, and stakeholders investigate the use of dynamic line/tension ratings and seasonal line ratings to avoid using the TLR process when a higher rating could be used in certain situations or seasons.

Finally, the proposed planning solution identified in the Reliability Improvement Plan involves the use of specific temporary flowgates created by the Reliability Coordinator to address certain short-term issues (e.g. planned transmission line outages) in the AFC calculation process. Currently, the AFC process only uses 300 permanently defined flowgates and the addition of these “temporary” flowgates to the AFC process may prevent transmission service from being sold if the Reliability Coordinator foresees a short-term reliability problem that can only be addressed by a temporary flowgate. Another planning solution identified in the Reliability Improvement Plan is the addition of Transmission Reliability Margin (“TRM”) and the Capacity Benefit Margin (“CBM”) to AFC calculations. No TRM or CBM is currently used in the AFC process. Finally, the Reliability Coordinator will increase its coordination with the ICT long-term planning


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group, especially with respect to the identification of upgrades or new construction options for the Entergy transmission system that could resolve potential or known reliability issues.

The Reliability Improvement Plan has been presented to stakeholders and is currently undergoing stakeholder review and comment. The ICT intends to finalize the plan and implement the solutions identified therein over the next few months.


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2. Tariff Administration

During the first year of operations, the ICT successfully managed a significant increase in TSRs compared to the prior year. As detailed below, the ICT made multiple improvements to assist in its Tariff Administration duties as well as addressed many software system issues on the programs used to process transmission service requests. In addition, the ICT, in conjunction with Entergy, developed and implemented many new processes in response to the regulatory requirements associated with Tariff Administration functions identified in Order No. 890.

The ICT has analyzed and responded to AFC modeling problems and transmission constraints in connection with the ICT’s Tariff Administration responsibilities and, specifically, the duty to evaluate TSRs on a non-discriminatory basis. In addition, the ICT has continued to implement the AFC Audit recommendations designed to make improvements to Entergy’s AFC process. The ICT has also helped implement various tariff changes that implicate Entergy’s AFC process, including the Negative Generation Solution and Order 890 requirements. Further, the ICT has facilitated stakeholder discussion to examine ways to make the AFC process more accurate and efficient, including new transmission products, the modeling of external control areas, the posting of additional information on OASIS, and the creation of a Base Case Overload Task Force to explore ways to possibly eliminate base case overloads. Finally, the ICT is currently engaged with Entergy in a “top-down” review of Entergy’s OASIS Automation software systems, with the goal of minimizing future incidence of data handling errors by enhancing software documentation, testing, and monitoring. This review includes a complete analysis of input and output assumptions, results and data in the Operating, Planning and Study Horizons. This review also includes the development of flow charts for related procedures in the RFCalc process. In short, the ICT has taken several affirmative steps to improve system operations and Entergy’s AFC software and modeling.

Despite these initiatives by the ICT, stakeholders’ comments to prior Quarterly Reports have raised various concerns about the ICT’s performance. In particular, stakeholders have complained that there has been a large increase in the number of TSRs in “study” status and there are systematic problems with Entergy’s AFC software and models as evidenced by the large number of error reports filed by Entergy regarding lost, inaccurate, or mismanaged data. In the ICT’s view, these criticisms are misplaced.

The large number of Long-Term TSRs in “study” status is neither contrary to Entergy’s OATT nor inconsistent with Commission policy. The ICT has consistently processed TSR studies in a timely manner and within the established deadlines under Entergy’s OATT. See infra Section III.8. Further, the ICT has performed in this function even though there has been a dramatic increase in demand for service since the ICT was


7

installed.2 Consequently, the increase in the number of TSRs in “study” status is directly related to the increased number of TSRs received by the ICT that require either a System Impact Study (“SIS”) and/or Facilities Study (“FS”).

The ICT’s proactive monitoring of Entergy’s OASIS Automation functions and AFC process has, on numerous occasions, identified some of the data handling errors that were subsequently reported to the Commission. Consequently, as a result of the ICT’s actions (and the subsequent filing of error reports by Entergy), steps have been taken to make corrections that have improved Entergy’s AFC models and software. Therefore, and notwithstanding stakeholder criticisms, the filing of these error reports serves as a meaningful indication that the ICT has been fulfilling its independent oversight obligations, as contemplated by the Commission.

2 Since the ICT has been installed, the ICT has received approximately 17,350

more TSRs than compared to Entergy in 2006, and approximately fifty-eight (58) more TSRs that required a SIS and/or FS than compared to Entergy in 2006. SeeICT Quarterly Performance Report, Docket No. ER05-1065-000, Figures 7 and 10, filed March 9, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 5, filed June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 5, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 5, filed December 31, 2007.


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3. Planning and Tariff Studies

During the first year of operation, the ICT worked diligently to process requests for long-term and interconnection service on Entergy’s system. In so doing, the ICT evaluated those requests and performed any necessary studies in accordance with the requirements of Entergy’s OATT. As demonstrated herein, the ICT has consistently performed requested SIS and, if needed, FS for transmission requests in a timely manner and within the established study deadlines under Entergy’s OATT. See infra Section III. 8. The ICT also performed requested Feasibility Studies, SIS and FS for interconnection requests, but experienced some delays in completing these studies. See id.3

In addition, the ICT has been actively engaged in long-term planning for the Entergy system. As part of its charge, the ICT developed Base Plans for use in the evaluation of transmission upgrade cost allocation. The ICT finalized the 2007 Interim Base Plan that recommended ten (10) additional projects and the accelerated implementation of four (4) projects to increase reliability on Entergy’s system. The ICT also solicited stakeholder comments at the Transmission Planning Summit this year which were incorporated into the draft 2008 Base Plan. Under the draft plan, the ICT has identified thirty-two (32) projects in addition to those originally identified in Entergy’s Construction Plan. The ICT anticipates finalizing and posting the current Base Plan on OASIS in early 2008 and holding a stakeholder meeting to discuss and evaluate the details of the plan.

Apart from its mandated planning obligations, the ICT, on its own initiative,developed the ISTEP as a comprehensive review and report on the ICT’s long-term expansion plan for the Entergy transmission system. This report evaluated both reliability and economic upgrades and included twenty (20) potential upgrade projects designed to relieve constrained flowgates and improve load-serving capability, inter-regional transfer capability and load pockets/load centers. The upgrades in this report are presented at a high-level, with the intent that these projects be further developed through stakeholder involvement in the coming months. The ICT will consider all stakeholder feedback, conduct further studies and analysis, and present the preliminary results in July of 2008, with final results in September of 2008. A second report will be issued on the ISTEP in November of 2008, following a stakeholder review.

3 The delays in the interconnection studies were due, in large part, to certain

interconnection requests involving exceptionally complex nuclear studies that required offsite nuclear analysis and modifications to specifications that required re-study of the nuclear facilities. Under Entergy’s OATT, all SIS are studied in queue order. Consequently, the delays in completing these studies earlier in the queue caused subsequent interconnection study requests to also be delayed.


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Further, the ICT has taken a leadership role in regional and inter-regional planning activities. In this regard, the ICT has participated in a number of studies and planning processes with adjacent transmission systems to improve communication, coordination, and planning with other regions. The ICT has also continued its work with transmission providers in the Acadiana area of southern Louisiana. In particular, the ICT completed a preliminary report on the Acadiana Load Pocket. The report contained anevaluation of reliability in the Acadiana Load Pocket, a proposed expansion plan for the area, and the results of an economic evaluation of the proposed expansion plan. In the coming year, the ICT will continue to work with Entergy and customers in the Acadiana area to find a solution to the congestion problems in that area.


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4. WPP

In the ICT Approval Order (at P 296), the Commission recognized the linkage between the Commission’s approval of the ICT and the success of the WPP proposal. The Commission expressed its expectation that WPP operations would commence approximately fourteen (14) months from the date of the order.

Under the time table established by the ICT Approval Order, the WPP was anticipated to be operational by the time of the filing of this report. Accordingly, the Commission in the ICT Approval Order (at P 299) directed the ICT to include in its Annual Report an assessment of how the ICT and the WPP are remedying problems that have been identified by transmission customers and other stakeholders and metrics for measuring the success of the ICT and the WPP.

However, as reported in the ICT’s Quarterly Reports, start-up of the WPP has been delayed, largely due to ongoing efforts to complete the development and testing of the vendor software for the WPP. In addition, Entergy recently determined that certain WPP modeling changes will require amendment to, and Commission approval of, portions of Attachment V to Entergy’s OATT.

In comments to the ICT’s Quarterly Reports, stakeholders have expressed concern with the WPP-related delays. The ICT understands the stakeholders’ frustration. However, the ICT is charged with overseeing the development and implementation of the WPP and, consistent with the proper discharge of these responsibilities, the ICT will not endorse the start-up of the WPP until all WPP software models and processes have been fully developed and tested.

Despite the reported delays, progress continues toward implementation of the WPP. Over the past year, the ICT has worked closely with Entergy and provided critical support in both the design of the WPP software and process documentation as well as active participation in the testing and market trials for the WPP. As a result of these efforts, the ICT has identified modeling and process errors that have been corrected, leading to the installation of various safeguards to facilitate the successful launch of the WPP. In addition, due to the efforts of the ICT, independent generators have been able to actively participate in the market trials and have gained valuable operational experience with WPP systems and processes.

In addition, the ICT and stakeholders have formed a WPP Issues Working Group (“WPPIWG”) expressly focused on the WPP. The WPPIWG has provided the stakeholders with regular information on the development and progress of the WPP. The stakeholders have also recommended improvements to the WPP, some of which have been accepted and implemented.

The ICT will continue to keep stakeholders informed of the progress of the WPP through the WPPIWG and the Quarterly Reports.


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5. Stakeholder Process

In accordance with its duties under the Entergy OATT and the ICT Agreement, the ICT has a defined stakeholder committee and working group structure. The SPC is the highest level of the stakeholder group structure with four working groups and various ad hoc task forces that focus on specific areas. This organizational structure allows all interested stakeholders the opportunity to participate in the process. Each committee and working group holds meetings at which information is exchanged and stakeholders, Entergy, and the ICT are allowed to share ideas and concerns. Further, a voting process was approved by the stakeholders to permit them to establish stakeholder recommendations on key issues. Under this structure, the ICT is in constant communication with the stakeholders through meetings and email exploders. The ICT has also developed a dedicated ICT web site that contains ICT related documents, calendar of events, and other meeting materials and information to improve stakeholder engagement in the ICT’s activities and processes.

Over the past year, the ICT has convened seven (7) SPC meetings and participated in over forty-five (45) working group and task force meetings. During this same period, the ICT acted on five (5) recommendations of the SPC, covering a wide range of issues and discussions. In addition, the stakeholder process was utilized to conduct initial comprehensive reviews of Entergy’s Criteria Manuals (i.e., Attachments C, D, and E) and Order No. 890 Attachment K and the consideration of numerous stakeholder comments and suggested edits.

A formal and informal ICT communication process was also established and approved by the stakeholders. The ICT records and summarizes in its quarterly performance reports all formal stakeholder communications to the ICT. During the first year of ICT operations, approximately fifteen (15) formal communications were received by the ICT. In addition to reporting such communications, the ICT provides a written response to any stakeholder submitting a formal communication.

The ICT is a unique, first-of-its-kind, arrangement. As a result, there have been understandable differences between how the ICT views its roles and responsibilities versus how the stakeholders view the ICT’s roles and responsibilities. These different perspectives often play out in stakeholder pleadings to the Commission where the ICT is criticized for lacking leadership and/or sufficient resources to respond to stakeholder concerns. See, e.g., “Comments in Response to the ICT’s Third Quarterly Performance Report and Request for Technical Conference by the Lafayette Utilities System,” Entergy Services, Inc., Docket No. ER05-1065-000, filed November 16, 2007. Similar sentiments appear in the recent survey responses submitted by certain stakeholders. See Attachment 1.


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Having neither section 205 filing rights nor any delegated regulatory authority, the ICT evaluates stakeholder requests and recommendations in the context of the existing regulatory framework. The ICT does not consider itself free to ignore prior Commission orders, effective OATT terms, or the requirements of the Commission-approved ICT Agreement. As the ICT understands its role, it is not enough for the ICT to conclude that a stakeholder proposal may, in a general sense, have merit, if the substance of the proposal has already been considered and rejected by the Commission or is inconsistent with the terms of Entergy’s currently effective tariff provisions. The Commission has made clear that the ICT’s transmission oversight responsibility is “…limited to implementing criteria, standards and policies developed by Entergy.”

The ICT interprets its FERC-imposed charter as requiring the performance of specific functional responsibilities independently and consistent with the Commission’s open-access, non-discrimination policies. Absent a demonstrable change in circumstances, or compelling new evidence, the ICT will not second-guess the judgment of the Commission, endorse a change in an approved tariff provision, or support an action that is contrary to Commission policy. Stakeholder recommendations that do not implicate prior Commission findings/orders will be considered by the ICT based on an independent evaluation.


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6. Users Group

The ICT Approval Order provided for the formation of a stakeholder group comprised of users of Entergy’s transmission and data systems “to assess how the Entergy transmission and data (IT) systems are performing.”4 Consequently, as part of the ICT’s initial formation of the SPC, the ICT established the Users Group to address specific IT and data system issues and conduct assessments of Entergy’s data system with respect to data access, data quality, and data retention. In addition, the Users Group conducted an evaluation of Entergy’s IT systems and IT resource allocations to measure their efficiency.

Over the past year, the ICT has conducted a quarterly assessment of Entergy’s backup and archiving processes and, with consultation from the Users Group, provided detailed recommendations to Entergy regarding documentation and process-related improvements. The ICT also reported Entergy’s progress on implementing the various recommendations at each Users Group and SPC meeting as well as in the QuarterlyReports filed in Docket No. ER05-1065.

In addition to the assessments and improvements to Entergy’s data archiving processes, the ICT provided the Users Group with detailed presentations on the multiple error reports filed by Entergy in Docket No. ER05-1065 and has kept the Users Group apprised of any IT or data related solutions used to address these errors. As discussed in Section II.2. above, the ICT, in conjunction with the Users Group and stakeholders, has been instrumental in discovering and reporting errors in the AFC and posting software, and has worked with Entergy’s IT staff to devise solutions to these errors.

4 See ICT Approval Order at P 109.


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7. ICT Stakeholder Survey

In the ICT Approval Order (at P 300), the Commission directed the ICT to perform a survey of Entergy’s transmission customers prior to submitting the ICT’s Annual Reports. While the Commission did not dictate how the survey should be conducted, the Commission did state that the survey should be sufficiently comprehensive and meaningful to obtain stakeholders’ views on how the ICT and Entergy are performing.

In accordance with the Commission’s directive, the ICT sent a Stakeholder Survey to over 100 recipients who had previously participated in ICT stakeholder activities. The survey requested stakeholders to share their experiences and opinions of the ICT’s performance in areas including Reliability Coordination, Tariff Administration, Transmission Planning, WPP, and Stakeholder processes. The survey also asked stakeholders to rate the current services being performed by the ICT relative to the same services provided by Entergy prior to the implementation of the ICT. By the conclusion of the survey period, i.e., November 23, 2007, the ICT received 30 stakeholder responses.

The ICT Approval Order did not explicitly require the ICT to include the results of the Stakeholder Survey with the Annual Report. Nonetheless, the ICT believes the Commission intended the survey results to be made available as another measure of the ICT’s performance. Therefore, the ICT has compiled the stakeholder responses to the survey and provides the results herein. See Attachment 1.

The ICT is greatly disappointed with the volume of negative responses from stakeholders. These responses largely ignore the numerous improvements achieved under the ICT’s watch and appear to misconstrue the specific roles and responsibilities of the ICT. Stakeholder perceptions and expectations must be viewed through the prism of FERC precedent and policy, as well as the terms of Entergy’s currently-effective OATT and the Commission-approved ICT Agreement. Dissatisfaction with the ICT’s general unwillingness to endorse stakeholder proposals that conflict with Commission orders and/or approved and effective tariff provisions does not, as certain stakeholders suggest, reflect the ICT’s passivity and/or lack of independence, but rather the regulatory and legal framework in which the ICT operates.

Ultimately, the ICT does not view its Commission-mandated role as an advocate for stakeholder interests any more than it views itself as an advocate for Entergy interests. It is not clear whether stakeholders subscribe to this perspective, nor is it clear that stakeholders would acknowledge the regulatory constraints that, in the ICT’s view, require the ICT’s adherence to Commission precedent and approved tariff provisions, absent changed circumstances or new evidence. Nonetheless, the ICT will carefully consider the survey responses and will designate, as high-priority action items for 2008, potential improvements to address stakeholder comments in areas such as


15

communications, transparency, reliability coordination, and transmission planning. The ICT will provide reports to the stakeholders during the next year on these activities.


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III. ATTACHMENT S METRICS

In the ICT Approval Order (at P 304), the Commission required that the ICT report certain metrics in its periodic reports to measure the ICT’s effectiveness during the initial term. Entergy memorialized these metrics as part of Attachment S to the EntergyOATT in its January 16, 2007 compliance filing. In accordance with the ICT’s reporting responsibilities under Section 7(a)(2) of Attachment S to the Entergy Tariff and the ICT Approval Order, the ICT presents the following metrics:

1. The accuracy rate of posted AFC data compared to that experienced before the ICT was installed.

At this time, the ICT is unable to report on the number of instances of inaccurate postings of AFC data during the year prior to ICT operations.5 During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT is aware of thirty-eight (38) instances of inaccurate AFC data that was used to calculate an undeterminable number of AFC data postings.6

2. The number of times, if any, Entergy or the ICT lost data during the initial term of the ICT.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT is not aware of any instances of lost data.7

5 The data for this metric is currently unavailable. The ICT is diligently working to

compile the data for this metric and will supplement the current Annual Report as soon as the ICT’s analysis is complete.

6 This metric was developed by reviewing the Quarterly Performance Reports and recording the known instances of inaccurate modeling or posting problems. See infra Metric 3 and 4. The ICT, however, does not know how many AFC postings were inaccurate because of these known instances. As a result, the ICT is unable to provide an accuracy rate for this metric.

7 The ICT notes that on two (2) occasions certain data was not created, and therefore, was not considered to have been “lost” for purposes of this metric. SeeICT Quarterly Performance Report, Docket No. ER05-1065-000, section 8.3.2.2 at 40 and section 8.3.2.7 at 42, filed October 2, 2007. The ICT also notes that some OA log-files were lost for a period of time prior to the implementation of the ICT. This data loss was reported after the implementation of the ICT. SeeICT Quarterly Performance Report, Docket No. ER05-1065-000, section 3.3.1 at 11, filed March 9, 2007.


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3. The number of times, if any, users were given inaccurate or incomplete data.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT was aware of five (5) occasions in which users were given inaccurate or incomplete data.8 All instances of inaccurate or incomplete data postings were reported by the ICT in its Quarterly Performance Reports.9

4. The number of times, if ever, Entergy used inaccurate modeling

assumptions.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, Entergy used inaccurate modeling assumptions thirty-three (33) times.10 All instances of inaccurate modeling assumptions were reported to the Commission by Entergy in Docket No. ER05-1065 and/or in the ICT Quarterly Performance Reports.

8 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, section

8.3.1.7 at 39, section 8.3.2.2 at 40, section 8.3.2.4 at 41, and section 8.3.2.7 at 42, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 8.3.2.2 at 48, filed December 31, 2007.

9 This metric was developed by reviewing the Quarterly Performance Reports and recording the data issues that addressed inaccurate postings and/or malfunctions of software that is publicly available to users of Entergy’s transmission system. This metric in conjunction with Metric 4 covers all data issues that were reported by the ICT during the first year of operation.

10 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 3.3.2 at 12 and section 3.4.1 at 13, filed March 9, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 8.4.2.1 through 8.4.2.5 and sections 8.5.1 and 8.5.2 at 38-42, filed June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 8.3.1.1 through 8.3.1.6, sections 8.3.2.1 through 8.3.2.3, and sections 8.3.2.5 and 8.3.2.6 at 37-42, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 8.3.1.1, 8.3.2.2, 8.3.2.1, and 8.3.2.3 through 8.3.2.5 at 47-51, filed December 31, 2007.


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5. How frequently, if ever, Entergy failed to timely post or provide required data or posted inaccurate data.

During the Annual Reporting period from November 17, 2006 to November 17,

2007, the ICT is aware of three (3) instances where Entergy failed to timely post or provide required data or posted inaccurate data.11

6. The number of times transmission users complained that AFC is not available.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT received two (2) formal complaints from transmission users that AFC was not available.12

7. The number of times, if any, available AFC when needed was

different from posted AFC on OASIS.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT was aware of forty-seven (47) instances in which the Scenario Analyzer,

11 This metric identifies Entergy posting errors related to Order 890 OASIS

requirements. The ICT notes that arguably there are instances of posting errors referenced in metrics 3, 4, and 7 that fall within this metric. However, to avoid duplicate metrics the ICT only included those instances that were not captured in these other metrics. In addition to the instances where Entergy made posting errors, the ICT failed to post four (4) of Entergy’s error reports filed in Docket No. ER05-1065 within twenty-four (24) hours in accordance with the ICT Approval Order (at P 110). As soon as the ICT discovered the missed postings, the documents were immediately posted, and the ICT put procedures in place to prevent such occurrences in the future.

12 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 7.1.3 and 7.1.5 at 33-34, filed June 27, 2007. Consistent with the ICT Stakeholder Communication protocols outlined in the ICT Quarterly Performance Reports (section 7), all communications between stakeholders and the ICT are classified as formal or informal. If stakeholders desire to have their positions noted and documented in regulatory reports, the communication must follow the guidelines for formal communication. Under these guidelines, written communications must be conspicuously marked as formal and i) presented at stakeholder and working group meetings, ii) circulated through established exploder e-mail lists, or iii) sent directly to ICT management to be included in the ICT Quarterly Performance Reports and used in the Annual Report Metric.


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which is the tool used for posting of AFC, was malfunctioning or off-line.13 During the time the Scenario Analyzer is down AFC values are not posted.

8. The length of time it took to perform interconnection or transmission service studies.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT completed three (3) Feasibility Studies, two (2) SIS, and zero (0) FS related to generation interconnection requests. The ICT, on average, took approximately fifty-four (54) days to process the requested Feasibility Studies for generator interconnection requests and approximately 148 days to process the SIS for the generator interconnection requests. There were no FS completed during this reporting. Therefore, there are no statistics for the processing of FS.

During the Annual Reporting period from November 17, 2006 to November 17, 2007, the ICT performed 131 SIS in an average of fifty-nine (59) days and twenty-seven (27) FS in an average of fifty-nine (59) days related to TSRs.

13 The measurement for this metric was developed in order to report the instances of

inadequate posting of AFC. As noted in Attachment C to the Entergy OATT, the Scenario Analyzer is the formal tool used to post AFC to OASIS and is directly fed data from OA, which is used to grant or deny TSRs. However, inconsistencies between the Scenario Analyzer and OA can arise based on the time lapse between the time a customer uses the Scenario Analyzer, submits the request and the ICT operator acts on the request. During this time period, other TSRs are processed and decremented from the AFC calculation, which could cause the AFC posted (through the Scenario Analyzer) to differ from the AFC used to grant or deny the TSR. During the initial year of the ICT’s operation, 12,920 TSRs were refused in the Operating, Planning and Study Horizons, and, while the ICT has no accurate process to track whether the customers for these TSRs used the Scenario Analyzer, it is likely that many of the denied TSRs had differences between posted AFCs and AFCs used to evaluate the request. See ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 7 at 17, filed March 9, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 8 at 19, filed June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 8 at 20, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, Figure 8 at 23, filed December 31, 2007.


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IV. CONCLUSION

When the Commission approved the ICT concept and installed SPP as the ICT for Entergy, it expressed optimism that the ICT model could be successful and extended the amount of time for the ICT Agreement to allow the ICT a sufficient period to prove thevalue that independence and oversight would bring to the Entergy system.14 While the ICT has faced numerous challenges and implementation issues during its first year of operation (especially in light of Order No. 890 and 693), this self-evaluation and Performance Report demonstrates that, while much work remains, the ICT has delivered meaningful benefits and value to Entergy and its stakeholders. The ICT firmly believes that, after the initial term of the ICT Agreement is complete, the Commission will find that the ICT has significantly improved the provision of non-discriminatory service in the areas of Reliability Coordination, Tariff Administration, Transmission Planning and Expansion, and the WPP as well as added a new level of transparency and stakeholder involvement for all transmission-related processes.


ATTACHMENT 1

FERC Annual ICT Report: November 2006 – November 2007

1/7/2008 1

2007 ICT Stakeholder Survey

Needs Improvement Neutral Needs No

Improvement N/ A

Non-discrimination 24.1 31 6.9 17.2 13.8 6.9Transparency 31 31 10.3 10.3 3.4 13.8

0

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35

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Responses

Please rate the ICT'sperformance in the following areas?


1/7/2008 2

Worse Neutral Better N/ ANon-discrimination 10.3 3.4 51.7 24.1 6.9 3.4Transparency 24.1 6.9 24.1 24.1 10.3 10.3

0

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Comparedto the service you recieved prior to the ICT implementation,how would you rate improvement in the following

areas?


1/7/2008 3


Improvement N/ A

Congestion Management 41.4 24.1 10.3 6.9 0 17.2Short-termPlanning 44.8 24.1 10.3 6.9 0 13.8Communication 37.9 17.2 17.2 10.3 6.9 10.3

0

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Please rate the ICT'sprovison of the following Reliability services:


1/7/2008 4


1/7/2008 5


Improvement N/ A

TSR Planning 34.5 13.8 20.7 17.2 0 13.8Generation Interconnection

Process 10.3 10.3 20.7 3.4 0 55.2

Base Plan Process 36.7 30 16.7 10 0 6.7Model Building Process 30 23.3 30 6.7 0 10

0

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Please rate the ICT'sprovison of the following Transmission Planning and Studiesservices:


1/7/2008 6

Worse Neutral Better N/ ATSR Planning 20.7 3.4 37.9 17.2 6.9 13.8Generation Interconnection Process 3.4 3.4 37.9 3.4 6.9 44.8Base Plan Process 13.3 10 46.7 16.7 6.7 6.7Model Building Process 10 16.7 43.3 16.7 6.7 6.7

0

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Compared to the service you recievedprior to the ICTimplementation, how would you rate the improvement of the following Transmission Planning and

Studiesservices?


1/7/2008 7


Improvement N/ A

WPP Process 20.7 17.2 10.3 6.9 3.4 41.4

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Please rate your satisfaction with the ICT's communication to Stakeholders about the WPP implmenentation


1/7/2008 8


Improvement N/ A

Responsive tomy needs 27.6 13.8 17.2 17.2 3.4 20.7Provide accurate information 20.7 17.2 13.8 20.7 6.9 20.7Resolve to mysatisfaction 24.1 20.7 17.2 13.8 3.4 20.7

0

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30Pe

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Responses

Please rate the ICTTariff Adminstration staff'scustomer service performance:


1/7/2008 9


Improvement N/ A

Responsive to my needs 13.8 20.7 13.8 20.7 6.9 24.1Provide accurate information 13.8 17.2 20.7 20.7 3.4 24.1Resolve issuesto mysatisfaction 24.1 13.8 13.8 20.7 3.4 24.1

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Please rate the ICTReliability Coordination staff'scustomer service performance:


1/7/2008 10


Improvement N/ A

Responsive to my needs 21.4 3.6 21.4 10.7 3.6 39.3Provides accurate information 17.9 10.7 21.4 7.1 3.6 39.3Resolvesissuesto mysatisfaction 21.4 14.3 14.3 7.1 3.6 39.3

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Please rate the ICTWPP staff'scustomerservice performance:


1/7/2008 11


Improvement N/ A

Responsive to my needs 20 26.7 16.7 13.3 3.3 20Provides accurate information 20 26.7 20 13.3 3.3 16.7Resolves issuesto mysatisfaction 24.1 20.7 24.1 6.9 3.4 20.7

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Please rate the ICTTransmission Planningand Studiesstaff'scustomer service performance:


1/7/2008 12


Improvement N/ A

SPC 23.3 30 20 13.3 3.3 10LTTIWG 20.7 34.5 20.7 6.9 0 17.2NTTIWG 21.4 32.1 14.3 10.7 0 21.4WPPIWG 32.1 14.3 14.3 3.6 0 35.7User'sGroup 25 10.7 10.7 10.7 0 42.9

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Please rate the overall effectiveness of the following ICTStakeholder groups:

9.2.1 Additional Comments

Question: Please share other thoughts about your satisfaction with the ICT Reliability

Coordination staff.

“Although we significantly disagree with the policy decisions of Entergy/RC, we do believe that the personnel at the RC

have been responsive and professional while implementing the policy. RC staff did not resolve issues to our satisfaction not

because of a lack of effort, but rather a conflict in policy. We would like to see the ICT RC staff actually implement their

own independence rather than defer to Entergy's attorneys, who are clearly providing a discriminartoy bias to EMO under

the guise of an independent monitor. The end result is that the participants do not believe that ICT is truly independent.”

“Again, seem to be taking their direction from Entergy instead of exhibiting "independance". Example: Entergy changes a

LAP Procedure; doesn't even tell the RC. Then the RC just continues to implement as Entergy decided. The RC was then

reluctant to post the new Entergy LAP Procedure until Stakeholders became very vocal about Transparancy. Stakeholders

are STILL unaware of what specific improvements will be made for 2008 to resolve the many TLRs experienced in summer

2007.”


1/7/2008 13

“Lafayette's interaction with ICT Reliability Coordination (ICT-RC) staff has involved consideration of potential operating

solutions to security limit violations on Entergy flowgates in (or directly affecting) the Acadiana Load Pocket. ICT-RC staff

exhibited a strong preference for the adoption, and later the extension, of redispatch protocols designed to “avoid” the

declaration of Level 5 TLRs. The redispatch protocols in question had the effect of relieving the short-term loading on one

chronically congested Entergy flowgate but did not address or resolve the underlying deficiencies in the transmission

infrastructure. It appeared to Lafayette’s representatives that avoidance of Level 5 TLRs was viewed by ICT-RC staff as a

desirable end in itself, notwithstanding that the reporting obligations associated with Level 5 TLRs serve the salutary

function of making more “transparent” network deficiencies that otherwise would remain largely hidden to parties other

than the immediately involved operating personnel. Although Lafayette agreed to the adoption and extension of the

aforementioned redispatch protocol, it did so solely to put bounds around its own economic risk. Lafayette’s view is that

ICT-RC personnel should not treat the short-term “avoidance” of Level 5 TLRs as a goal unto itself, but rather should

promote necessary long-term infrastructure improvements.”

“The TLR process this summer grossly overstated the impact of interchange schedules on congested flowgates because it

did not include Entergy's short term DNRs when determining Entergy's redispatch obligation. The RC seemed unaware of

this until stakeholders pointed out, and has yet to provide an acceptable solution to this problem. Excessive firm

transmission was interrupted due to this error.”

“Based on a presentation by the ICT/RC at an Operations meeting on August 15, 2007, the training and knowledge of

procedures of the Reliability Coordinator is inadequate. Increased TLR events, understanding and communication of

Entergy’s Local Area Problem procedure is not acceptable. Curtailed transmission service based procedures that was not

posted and communicated to stakeholders until approximately 2 months after it was requested by stakeholders. The ICT

did not communicate TLR flowgates to AFC process while transmission service continued to be sold across congested

flowgates. Reliability Coordination Staff has demonstrated a reason for concern based on a lack of competence and

credibility (including being independent from Entergy). The ICT has not independently exercised its authority to execute

TLR procedures. The Reliability Coordinator has adopted the same criteria and procedures established by Entergy. The

simple adoption of the Entergy criteria and procedures demonstrates the ICT's reliance and dependence on Entergy.”

“Seems to be some confusion at times btwn what the RC is responsible for and what ENT is responsible for.”

Question: Please share any other thoughts about your satisfaction with the ICT Tariff

Administration staff.

“In general, once we can get ahold of the ICT engineers, they are very helpful. The biggest complaint is the response time

and lack of communication. Hopefully more personnel could help resolve this.”

“The staff is trying its best. But, the ICT is not being independent and proactive to improve transmission access. Market

Participants still find model errors and report; the ICT is still just "reacting" to those reports. AFC models indicating

"UNRELIABLE" 140-150% base case overloaded elements still exists, and the ICT seems to be taking their direction from

Entergy instead of changing model assumptions to reflect reality.”

“The ICT has failed to properly oversee the AFC process has recently been demonstrated by the continue numbers of

errors in the AFC software. The ICT has not adequately verified and validated model results. The ICT does not appear to be

challenging Entergy's dispatch of resources. Entergy is still providing inputs and assumptions. Continued to sell


1/7/2008 14

transmission service on flowgates on which TLR continued to be called which demonstrates that the AFC does represent

real time operations. Overloads that exist in the monthly AFC models continue to be accepted by the ICT. Stakeholders

have provided a recommendation regarding base case overloads the AFC models, but the ICT has not taken positive action

to permanently address this issue. The ICT under estimated the issues and concerns regarding the AFC process. The audit

performed was not accurate to capture the problems in the AFC process.”

“We haven't had any incidents recently, but in the past, the transmission desk has really struggled with consistency of

tariff administration, even tariff understanding. I feel that there has been improvement though. Another thought is

involving the running of the "numbers" or ATC/AFC's for any given period. There is very little clarity on what the ATC's are

at any given time on ALL the paths (without literally going and making each individual request and running the availability

- a ridiculously cumbersome task). I am also curious about the timing of the running of the ATC's - as at various times we

are successful or not successful getting next day transmission, and we can see no real pattern in this.”

“Often times it seems they simply serve as yet another hurdle to go through to get transmission service. Perhaps the I

should stand for Intermediary rather than Independent. Often times they seem to have to go back and ask Entergy in

cases where they should be forming their own opinion.”

“The bottom line is that there is less service available than prior to the ICT and there are more TLR's.”

Question: Please share other thoughts about your satisfaction with the ICT Transmission Planning

and Studies staff.

“Again, we believe that the root issue here is not the individuals at the ICT, but rather the bureaucratic process by which it

seems that ICT personnel are not given the level of authority that would seem to be required for the position. Poor

communication and a delayed reponse time are the result.”

“Same thoughts: just following Entergy's standard requirenments. No "TRUE" Independence! The "WELL KNOWN" (Mt

Olive-Hartburg, RayBax, McAdams Transformer, etc.) points of congestion in the Entergy System are being put in a

"secondary" group called "Strategic Plan". Stakeholders are not witnessing any "REAL" change to address major congestion

and meaningful transmission access.”

“Cannot get in touch with anyone on staff. Staff doesn't return phone calls when messages are left.”

“It is the perception of Lafayette personnel that the ICT Transmission Planning and Studies (ICT-TPS) group lacks the

resources required to perform the Transmission Planning and Study function in a timely and effective manner. Lafayette’s

primary interaction with ICT-TPS staff has involved the consideration of potential upgrades to transmission facilities in (and

directly affecting) the Acadiana Load Pocket. That interaction led Lafayette representatives to conclude that ICT-TPS staff

did not turn their attention to the issues being discussed until impending meeting dates forced ICT-TPS staff to do so. ICT-

TPS staff then produced an analysis of potential transmission upgrades that was flawed by a number of obviously faulty

assumptions. ICT-TPS staff expressed a willingness to receive Lafayette’s comments and to work with Lafayette personnel

to reach agreement on assumptions to be included in the next iteration of the analysis. ICT-TPS staff then published (and

posted on Entergy’s OASIS) the “Acadiana Load Pocket Transmission Reliability Study Report” before agreement on

assumptions had been reached. In fact, certain of the erroneous assumptions that marked the ICT-TPS staff’s earlier

analysis were carried over into the posted Study Report. Only after Lafayette made a written request did ICT-RC staff


1/7/2008 15

modify that posting to state that the Study Report was intended as a preliminary draft. In other contexts, Lafayette has

been concerned that ICT-TPS staff continue to rely heavily on expertise and assistance provided by Entergy’s planning

personnel. In the context of the Acadiana Study Report, it appears that ICT-TPS staff made a decision to undertake the

analysis on their own. While we believe the decision to undertake an independent analysis was absolutely the proper

course, the ICT-TPS staff’s subsequent performance exposed the serious lack of ICT resources that is undermining the

discharge of this crucially important function.”

“SPP is working on a "strategic" transmission plan that is being represented as addressing reliability enhancements and

economic upgrades. The models used for this study DO NOT include upgrades necessary to: 1) maintain long term firm

transmission service commitments; 2) maintain NITS commitments; 3) maintain the applicable level of integration of

generators that have already been qualified at the NRIS or NITS level; 4) maintain standards of safety and reliability

applicable to the Entergy region; and, 5) maintain firm transmission service commitments where the ability to honor such

commitments has been degraded due to events that are beyond the control of the TP. The models have numerous

significant overloads under n-1 conditions. Because the ICT is starting with a model that DOES NOT include those upgrades

necessary for Entergy to meet their long-term transmission service obligations, the benefits and benefactors of the

proposed upgrades is unidentifiable. This problem relates directly to the ICT’s interpretation that the Base Plan should only

contain upgrades that address reliability needs for the next 3 years and ignores Entergy's long-term transmission needs

and obligations. Because the ICT’s Strategic Plan is based on this same premise, PRE-EXISTING overloads in the models

that should be Entergy’s responsibility to address will be merged with other upgrades that may provide specific economic

or other benefits. To properly determine cost allocations for proposed upgrades in the Strategic Plan, the reliability

upgrades necessary for Entergy to meet their long-term obligations should be layered in prior to evaluating incremental

benefits of economic or other upgrades. This issue was brought up at the November LTTIWG meeting. The LTTIWG Chair

stated that the is was his opinion that the Base Plan should only have those upgrades necessary to meet Entergy’s

reliability needs for the 3 year period.”

“The ICT has failed to address the recurring transmission constraints on the Entergy system. The creation of the base case

model is based on Entergy inputs and assumptions, not independently developed by the ICT. The creation of the Base Plan

is based on inputs from the draft Entergy Construction Plan, not independently developed by the ICT. The ICT has

continued the Entergy practices and is using the same consultant to perform the studies interconnection studies. Base case

contingency overloads exist in long term models.”

“Adhered to tarrif imposed deadlines, ie System Impact Studies. Would like to see things done faster than those imposed

guidelines, including SIS results, rendering agreements for SIS and FS work.”

“Impressed with Strategic planning concept.”

“It has been a while since we have requested any short term transmission studies - for the reason that it is completely

fruitless. The most recent studies we have attempted have involved taking the DNR requests we have for specific units and

redirecting them to be based off IPP's within our control area, and in all our attempts, we have not been successful in

obtaining firm transmission in this manner.”

“Sometimes it is difficult to get staff to give difinite answers. They seem more concerned about keeping waters smooth and

making everyone feel good instead of giving direct answers or taking a stance that might stir criticism.”


1/7/2008 16

“The ICT staff do not appear with Entergys rampant and liberal use of "note 1b," but yet they either don't have the

authority or desire to force the issue. It seems the organization is more concerned about keeping their employeer

(Entergy) happy with their service than they are imposing what they believe are proper planning practices.”

Question: Please share other thoughts about your satisfaction with the WPP staff.

“We think the WPP speaks for itself. We do not believe that the failure of the WPP is the result of ICT however. That said,

the lack of quality control in the model, whether used for the WPP or regular TSR, is a very significant issue for us and

needs much more improvemnent before a WPP type service could ever be successful.”

“Again, no "take charge" attitude in being proactive to develop a fair and timely WPP. The ICT again seems to be just

looking to Entergy to answer the improvement suggestions of the Stakeholders; and Entergy's standard answer is no, "it

can't be done", or, "it's not in the Tariff". There seems to be no logical analysis as to whether the improvement suggestion

is a good/fair one. The answer is always Entergy's "NO". Example: why shouldn't the redispatch costs be resource specific

instead of socialized, and why isn't a resource that's providing counterflow being rewarded? The answer the Stakeholders

have been given is "we can't make improvements at this time; all resources are focused on meeting the "go live" date. Yet,

the "go live" date has been missed by more than 6 months now, and we still aren't SURE of a "go live" date. And, we

haven't incorporated ANY Stakeholder suggested improvements either.”

“A stronger leader of the ICT team is needed during the develoment and implementation phase of this project.”

“The recommendations from stakeholders on performance metrics were largely ignored.”

“The ICT WPP Staff has not adequately demonstrated its ability to communicate the WPP process to stakeholders without

significant input from Entergy. This provides concern regarding the independence of the WPP Staff. Delayed

implementation indicates ineffective execution of oversight responsibilities. It does not appear that the ICT designed the

WPP process or even provided adequate oversight in the “process” design. It is not clear how the ICT participated in the

design. It seems clear that Entergy has designed the WPP process and plans to operate the system. Transparency is

another area that is lacking in the WPP and the WPP Staff does not seem to accurately understand stakeholders concerns

expressed in the Transparency recommendation that was passed by the SPC and effectively denied by Entergy and the

ICT. The WPP Staff’s typical response to stakeholder requests is “That will require a tariff change.” Although the WPP is not

yet implemented, it is clear from metrics proposed by the ICT will not capture the benefits envisioned by the Commission’s

ICT Order (paragraphs 95 & 305). There is concern that the benefits will be overstated based on the metrics proposed by

the WPP Staff.”

Question: Please share other thoughts about your satisfaction with the ICT stakeholder

committees and working groups.

“The ICT staff continues to be in an extremely reactive mode and understaffed. Communication, timeliness of response,

and follow through are poor. The weakest part is follow-through and follow-up. It seems as if the stakeholders have to

keep track of what has been done and what has not been done. This is just a list taking exercise that should not be such

an effort for the ICT. Administration and organizational skills should be one of the strengths of a transmission organization

aside from reliability and non-discriminatory treatment. If the ICT is being stymied by Entergy, then the ICT should be

more proactive in getting its relationship with Entergy in better order. Honestly, it seemed easier working with Entergy


1/7/2008 17

directly prior to the implementation of the ICT. The dialogue also seemed more open. Furthermore, the absence of a

mentality for contingency planning is peculiar for a staff that supposedly comes from transmission planning and

coordination. For example, the delay in the implementation of the WPP is quite amazing given that at each of the the

original and revised deadlines, Entergy was quite adamant that the deadline would not be missed. Stakeholders continually

asked what if questions as to unknown factors that might cause delay, but Entergy and the ICT never seemed to

acknowledge those possibilities and what fallback plan would be used. Other than the WPPIWG, the other WGs do not

exhibit any sense of urgency or alarm when mistakes have been found that have imposed economic costs on the

stakeholders. After this past year, the atmosphere seems worse as the ICT SPC exhibited an extremely litigious stance on

stakeholder recommendations. Essentially, stakeholders need legal support to proffer recommendations that would meet

the ICT's stringent guidelines. Stakeholders might as well file with FERC.”

“See prior comments. The only major improvement made to the AFC modeling process has been to eliminate "Negative

Generation" in the model. And, this improvement actually was an outcome of the old AFC Working Group; not the ICT.”

“There needs to be more communication on what boundaries limit the ICT to produce recommended

changes/improvements in the way transmission planning, service and WPP processes are conducted. Too often, it seems a

"wall" becomes present long after teams work their way toward idea development and recommendation.”

“The ITC and SPC needs more implementable authority over Entergy's transmission planning processes.”

“ICT stakeholder processes have fallen into a pattern in which stakeholders and ICT staff exchange position papers without

engaging in much (if any) face-to-face dialogue on the issues. Often, very long intervals elapse between the presentation

of a stakeholder position paper and receipt of the ICT’s written response. An example of this pattern is the exchange

regarding elimination of Base Case overloads in the short-term and long-term models. Similarly, ICT-facilitated interactions

between Entergy and stakeholders have been characterized by exchanges of position papers over long periods of time,

with insufficient interactive dialogue to produce movement toward resolution. Stakeholders understand that they must

meet specified deadlines for their written submissions, but Entergy often fails to meet its deadlines without repercussion.

An example is the stakeholder process involving review of Entergy’s Transmission Criteria Manuals. Stakeholders provided

detailed comments on drafts of Attachments C, D and E several months ago. Entergy eventually provided a much-delayed

response to comments on Attachment E, but has failed to respond to comments on the other two documents. Lafayette

believes that the stakeholder process would be more timely, constructive and productive if the ICT moved the process

away from iterative exchanges of paper and toward more direct discussion and interaction on issues of concern. Apart from

accelerating the resolution of issues, direct dialogue also should reduce the amount of posturing that tends to characterize

written submissions(which, in turn, should increase the likelihood of negotiated resolutions).”

“The meetings are painful to attend. The working groups do the best they can, but there has been little or no progress.”

“The stakeholder process is functioning (malfunctioning) with the ICT as a facilitator at times and most often relies upon

Entergy to answer issues raised by stakeholders.”

“Little evidence of INDEPENDENCE. ICT responses mirror ETR, ie: base case overload respones, no written resonse to

specific Sch K mods, accepted ETR's 2 year budget. Minutes need more detail, meeting management needs improvement

see 18 below”


1/7/2008 18

“Responses in many areas seem to mirror ETR. Independence is critical.See Base Case Overload, Attachment K, esp with

ETR on Constbudget/basecase budget. Do something to facilitate accomodation. On the+RPTF is good effort.Finally,time

management of meetings needs vast improvement:dont bow to techs.”

“Too much time is wasted rehashing individuals pet issues. Stakeholders are often not provided enough time to develop

responses. ICT has the tendency to railroad issues through the working groups if they do not get an immediate response

instead of providing stakeholders time to formulate thoughts. Entergy does not provide timely responses. While Energy has

demanded that the stakeholders meet their deadlines they have dragged their feet when it comes to providing reponses to

the stakeholders. This is especially true if a FERC filing deadline is involved.”

“The stakeholder groups appear to have little authoirty & while they may completely agree with a certain issue, approach

or change... it's up to the ICT to decide after talking with Entergy whether or not it should be implemented.”

“Another reason why participants are actually worse off than prior to the ICT existance. We spend countless hours

debating, negotiating and vetting issues only to have Entergy to reject stakeholder recommendation. The ICT does not

weigh issues and develop their own view until after all is said and done. They appear to continually side with Entergy. If

participants aren't getting more service, than this process does not work.”

Question: Please share any remaining thoughts about your satisfaction with the SPP ICT.

“Deperately needed areas of improvement are 1) Communication, 2) Response time, 3) Quality control of the model, 4)

Better coordination with the market participants, 5) Independence from Entergy.”

“The lack of clear leadership and expertise is missing from the ICT. The ICT needs to take a more proactive role and not

rely so heavily on past practices. The ICT was created to be an independent entity and there has been complete

dependence on Entergy with no significant changes with no tangible benefits to the stakeholders.”

“ICT appears to be independent in name only. Staff only reacts to stakeholders inputs in a legalistic manner and

consistently come down on the side of Entergy's legal team. (especially in terms of transparency). Although none of the

stakeholders expected large scale changes we did not expect no change at all. It appears that the staff is only focused on

preparing for the inevitable litigation over adopting Entergy’s plan as opposed to listening to stakeholders and creating a

truly fair and independent transmission coordination system.”

“Need TRUE Independence. Thank you for allowing comments.”

“I would suggest the ICT enact a process that independently solicts comments from the stakeholders on a "one on one"

basis. This would show that SPP is working toward making the ICT a success.”

“Satisfied with ICT's performance to date, however ITC is in difficult position because Entergy clearly has too much

authority as compared to ICT.”

“The “quantitative” aspects of the ICT’s performance (e.g., number of TSRs processed, number of studies completed,

number of TLRs declared, etc.) have been addressed in the ICT’s Quarterly Performance Reports. Lafayette has filed

comments addressing certain of these quantitative metrics, and we will not repeat those comments here. Our focus in the


1/7/2008 19

following comments is on the “qualitative” aspects of the ICT’s performance. In their survey responses provided roughly

this time last year, a number of stakeholders harshly criticized the ICT’s responsiveness and overall performance. At the

time, Lafayette felt that much of that criticism was unfair because the ICT arrangement had been in effect for such a short

period. Now, however, enough time has elapsed that a more complete picture of ICT performance is available. That

performance leaves much to be desired in several areas. Our principal concern at this juncture is that, in accepting the ICT

engagement, SPP may have substantially misgauged both the nature of the assignment and the resources required to

provide the quality and scope of services expected by FERC and stakeholders. As a result of that miscalculation, the ICT

now appears to lack the resources, manpower and expertise needed to discharge its duties in a timely and effective

fashion. The resource deficiency problem is manifested in ways that have proven immensely counterproductive, including

the following: 1. The ICT continues to depend excessively on Entergy personnel for basic information and, in many

instances, expertise. The ICT’s continued reliance has led to a perception among many stakeholders that the ICT lacks

independence. Not unexpectedly, this perception has fostered a significant measure of mistrust or, at a minimum,

uncertainty among stakeholders about the ICT’s neutrality. Whether or not stakeholders are justified in their perception of

a lack of ICT independence, the perception exists nonetheless, and we believe it has adversely impacted the ICT's

effectiveness. 2. ICT staff often appears resistant to stakeholder requests that place additional demands on the ICT’s

limited resources. This resistance has created a perception among stakeholders that ICT staff members consider

stakeholders to be the ICT’s adversary, rather than (more accurately) customers of the ICT’s services. Another problem,

which appears unrelated to the resource deficiency issue, is a fundamental difference in view as to the ICT’s role in the

resolution of long-standing issues affecting the Entergy transmission system. In a nutshell, ICT personnel appear not to

view the ICT’s role as that of providing leadership in resolving transmission issues. ICT staff often avoid directly engaging

Entergy and stakeholders on the substance of issues, and appear too ready to retreat to a passive “facilitator” role (in

which ICT staff do little more than schedule meetings, produce an agenda, chair the meetings and publish minutes), rather

than expressing their own views and advancing proposed solutions for consideration. Instead of serving as a catalyst for

problem-solving, the ICT often appears to function as a conduit through which stakeholders and Entergy exchange well-

rehearsed positions, with little or no movement toward a convergence of views. In Lafayette's view, FERC intended a more

proactive role for the ICT than this.”

“The monthly models currently used in the AFC process(s) to assess short-term transmission ATCs DO NOT represent a

feasible dispatch. Significant overloads under n-1 conditions exist that are preventing customers from purchasing

transmission service on a forward basis. The daily models (out 30 days) used in the AFC process does not include the same

level of congestion...resulting in a significant seams issue between these two sets of models and demonstrating that

dispatch assumptions can and do determine transmission access on the Entergy system. The ICT needs to address this

issue and prevent the use of models in the AFC process that contain excessive "phantom" congestion. Phantom congestion

that is in models -- that has never occurred in real time nor is expected to occur in real time -- undermines market

confidence that energy can be reliably delivered across the Entergy system. The long-term models used to assess TSRs DO

NOT include upgrades to address Entergy's long-term (year 4 and beyond) reliability needs and obligations. These models

are fraught with n-1 overloads because upgrades that should be Entergy's responsibility, and should be in the Base Plan,

are not evaluated nor included. These upgrades are unfairly characterized as "supplemental" when Customer's try to obtain

long-term service. These are two of a number of issues that prevent buyers on and adjacent to the Entergy system from

procuring their capacity and energy needs on a forward basis. Identifying and recommending solutions to issues that

create unfair impediments to procuring transmission service should be a priority for the ICT, regardless of whether or not

this requires that Entergy change their tariff. The impact of some aspects of Entergy's tariff may not have been fully

understood during the ICT proceeding and the ICT should not limit their role to one of only implementing, but rather

provide the checks and balances that FERC and others expected. Paragraph 298 of the ICT order reiterates that in the

Guidance Order, the ICT is required to file a comprehensive report assessing the state of Entergy's transmission system


1/7/2008 20

operations whether Entergy's proposed transmission pricing ensures that merchant generation seeking to compete in the

Entergy footprint is able to do so. This report is to be filed one year after the ICT becomes operational. I hope the ICT

takes the opportunity in this report to accurately describe the impacts that Entergy's AFC process and limited 3-year Base

Plan has on buyers and sellers of power on and adjacent to the Entergy system.”

“The ICT is not independant. There is no accountability and there is no obligation to the stakeholders. You have used 25%

of your allotted time and have accomplished nothing.”

“Seems to be significant confusion on who is responsible for what. Hard to get questions answered.”

“The two primary concerns regarding the ICT is the independence from Entergy and the ICT ability to execute and

implement the Commission’s ICT Order and the Entergy Tariff. The ICT has effectively become a middle-person/entity and

has served to only slow down the process. The Reliability Coordinator role has been a noticeable step backwards.”

“Continued from 17 above. Minutes need more detail, almost meaningless unless an individual fleshes them out from his

own notes...which is not possible unless attended meeting.”

“Proof will be in results when TDU LSEs are able to move to complex multi source transmission arrangements involving

regional and interregional generation accross seams. Several LSEs I know will address this in 3/5 yrs.”

“One of the most one sided surveys I have ever seen. There were no questions asked about the ICT's independence. This

is an area where ICT need a lot of improvement. ICT needs to step up, voice their opinions, make decisions, develop their

own processes and procedures. ICT needs to stop using their contract with Entergy as an excuse for not taking a position

or making decisions. ICT also needs to stop looking to Entergy for answers. ICT needs to look at the OATT objectively and

in the event they think a change is needed voice it to FERC. The tariff is not set in stone and should be changed when an

issue or conflict warrents it. SPP RTO files changes regularly.”

“Keep in mind most (if not all) of the ICT staff are nice/friendly/personal people who on a personal level I do like… … it’s

not the individuals it is the organization … without the proper leadership or incentives even good people can fall prey to

simply turning the crank without any thought whatsoever logic, fairness, reasonableness or the intent of the tariff…..

particularly when you don’t want to upset the one that employees you. The ICT really seems more like an Independent

Study of Transmission. I suppose we should have recognized that "Coordination" carried with it little authority to impose

good planning practices on Entergy.... an organization that seems very effective at finding ways to place others in a

position to fully upgrade elements on their system that are already overloaded in the base case. As I listen to the

complaints of some SPP RTO customers... It is nice that the relationship between SPP ICT and the SPP RTO seems to have

created a conflict of interest for the SPP Organization... so that they want to keep the contract service business with

Entergy so bat that the SPP seems willing to disadvantage their own RTO tariff customers... perhaps as entergy customers

we will benefit from the SPP organization forcing some SPP RTO customers to pay for Entergy's base case overloads... The

SPP ICT staff have attempted to impose the historical SPP practices in the ICT area... often times this is a case of taking

what is a reasonable/good Entergy practice and replacing it with a more difficult and unreasonable RTO practice.... where

we end up with the worst of both organizations. The ICT and Entergy should recognize that customers are not necessarily

ALWAYS wanting something for nothing.... what they do want is a fair and reasonable treatment. While I understand

Entergy has it's own self interest at heart when it makes decisions... I don't know what motivates the ICT to behave the

way it does... Befor the ICT was implemented, I only had one entity I had to work through... now I have two and what

feels like twice as much work to do...”

January 8, 2008

The Honorable Kimberly D. Bose, SecretaryFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426

Re: Entergy Services, Inc., Docket No. ER05-1065-000The ICT’s Report on Entergy’s Transmission System and Transmission Pricing

Dear Secretary Bose:

The Southwest Power Pool, Inc. (“SPP”), as the Independent Coordinator of Transmission (“ICT”) for the Entergy Services, Inc. (“Entergy”) system, hereby submits the ICT’s Report on the State of Entergy’s Transmission System and Transmission Pricing, in accordance with the Federal Energy Regulatory Commission’s orders approving the establishment of the ICT.1

The ICT will serve a copy of this report to all Interested Government Agencies and will make the report publicly available by posting it electronically on Entergy’s OASIS.

If there are any questions related to this matter, please contact the undersigned at the number listed above.

Respectfully submitted,

/s/ David S. Shaffer____David S. Shaffer

Counsel for the ICT

Attachments

K:\SPP-ICT\Pricing Report\cover letter to ICT Transmission System and Pricing Report 2008.doc

1 See Entergy Services, Inc., 115 FERC ¶ 61,095, order on reh’g, 116 FERC ¶ 61,275, order on compliance,

117 FERC ¶ 61,055 (2006), order on reh’g, 119 FERC ¶ 61,187 (2007).

State of the Entergy Transmission System and Transmission Pricing

1

I. Purpose

Southwest Power Pool, Inc. (“SPP”), as the Independent Coordinator of Transmission (“ICT”) for the Entergy Services, Inc. (“Entergy” or “ESI”) system, is required by the Federal Energy Regulatory Commission (“Commission” or “FERC”) pursuant to the April 24, 2006, Order in ER05-1065 to file a comprehensive report assessing the state of Entergy’s transmission system operations as well as an evaluation of whether Entergy’s transmission pricing ensures that merchant generation is able to compete in the Entergy footprint.1

In conjunction with the ICT’s Annual Report that was filed on January 7, 2008, the instant report responds to the Commission’s directive. In so doing, the report will give a brief overview of Entergy and the ICT. The report will then discuss Entergy’s transmission system operations since the ICT was installed, including a review of transmission service requests (“TSR”), transmission congestion and reliability, transmission and interconnection studies, transmission planning, and the status of the Weekly Procurement Process (“WPP”). Finally, the report will examine Entergy’s transmission pricing structure for the recovery of new facility costs and provide the ICT’s assessment on the effectiveness of Entergy’s pricing mechanism to permit competition for merchant generation.

1 See Entergy Services, Inc., 115 FERC ¶ 61,095, at P 298 (2006) (“ICT Approval Order”).


2

II. System Characteristics

A. Entergy

Entergy provides services for the Entergy Operating Companies, which are a part of a multi-state public utility holding company system. The operating companies include Entergy Arkansas, Inc, Entergy Gulf Coast States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans Inc.

Entergy provides electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi and Texas.2 In 2006, residential customers comprised approximately 29% of Entergy’s total energy sales with commercial, industrial, government, and sales for resale accounting for 23%, 36%, 1%, and 10%, respectively.3

Entergy also operates more than 40 generating plants using natural gas, nuclear, coal, oil, and hydroelectric power and produces approximately 30,000 megawatts (“MW”) of electric generating capacity.4 Peak demand for 2006 was 20,887 MW.5 Total GWh by energy source for 2006 was approximately 113,250.6

2 See www.entergy.com/operations/information3 See www.entergy.com/content/investor_relations/pdfs/2006_final_IG.pdf , page 354 See www.entergy.com/operations/information5 See www.entergy.com/content/investor_relations/pdfs/2006_final_IG.pdf , page 356 See id.


3

Source: www.entergy.com/content/investor_relations/pdfs/2006_final_IG.pdf , page 35.

The Entergy Operating Companies have built or acquired approximately 15,500 miles of 69kV - 500kV transmission lines and move about 23,000 MW of power across the interconnected lines in an 112,000 square-mile area.7

The breakdown of the miles by size of the transmission line is shown below:

Source: “Entergy Transmission Asset Management 2006 Objectives,” at 6. Oasis.e-terrasolutions.com/documents/EES/2006_Trans_Planning_Summit_AM.pdf

7 See www.entergy.com/operations/information.

Entergy Miles of Transmission Line by Size

500 kV

1,88969kV

1,670

115 kV

5,645

138 kV

1,877

161 kV

1,562

230 kV

2,188

345 kV

192

18,703

14,383

41,687

74

38,402

Gas & Oil

Coal

Nuclear

Hydro

Purchased Power

GW

h

Sources of Energy

2006


4

B. SPP as the ICT for Entergy

On May 27, 2005, Entergy submitted to the Commission, on behalf of the Entergy Operating Companies, a proposed revision to its Open Access Transmission Tariff (“OATT” or “Tariff”) reflecting its proposal to establish an ICT for its transmission system and to implement a WPP. In its filing, Entergy identified SPP as the candidate it had chosen to perform the function of the ICT. In the ICT Approval Order, the Commission found that SPP, operating as a Regional Transmission Operator (“RTO”), satisfied the independence requirement to operate in the capacity of the ICT for Entergy and conditionally approved the tariff changes filed by Entergy. On November 17, 2006, the ICT assumed the responsibilities set forth in Attachment A to the ICT Agreement and Attachment S in Entergy’s OATT, with select reliability functions starting on November 1, 2006. Accordingly, the ICT is performing functions such as: (i) reliability coordination; (ii) AFC calculation; (iii) OASIS posting; (iv) processing of TSRs; (v) coordinating regional planning; and (vi) conducting stakeholder meetings. The ICT is also currently overseeing the design and testing of the WPP by Entergy’s Weekly Operations group.


5

III. Transmission System Operations

A. TSRs

In accordance with section 3.1 of Attachment S to Entergy’s OATT, the ICT is responsible for evaluating (granting or denying) all TSRs on a non-discriminatory basis consistent with the TSR Processing Criteria and Transmission Study Criteria and overseeing Entergy’s provision of short-term and long-term transmission service.

As demonstrated by Figure 1, there has been a significant increase in the number of TSRs received and acted on during the ICT’s first year of operation, compared to the same time period in the prior year. Specifically, the total number of TSRs received by the ICT increased 26%. The percentage increase for each type of service by duration was as follows: Hourly 31%, Daily 15%, Weekly 28%, Monthly 2%, and Yearly 21%.

Figure 1


6

Despite this increase in demand, TSRs have continued to be processed in a timely manner and consistent with the requirements of Entergy’s OATT and Commission policy. See infra section III.C. In addition, the ICT, in conjunction with Entergy, has implemented the requirements of Order No. 890, including changes to the AFC process and tariff requirements for transmission service.

However, as reported in the ICT’s Quarterly Performance Reports, there have been multiple error reports filed by Entergy with the Commission identifying instances where AFC data associated with Entergy’s automated systems has been lost, inaccurate, or mismanaged.8 In some instances, those data handling errors may have affected the processing of requests for transmission service on Entergy’s system. In addition, certain of these error reports have identified flawed assumptions and modeling errors. To address these problems, Entergy and the ICT are currently engaged in a “top down” review of the AFC processes, including all software and automation involved, to ensure that the AFC process is operating in an accurate and non-discriminatory manner. The ICT, consistent with its independent oversight obligations, will implement any necessary software corrections and revised procedures to improve Entergy’s automated systems and, in turn, the processing of TSRs in a fair, accurate and efficient manner.

B. Transmission Congestion and Reliability

On November 1, 2006, Entergy formally transitioned the Reliability Coordinator function to the ICT as approved by the ICT Approval Order. As the Reliability Coordinator for Entergy, the ICT has authority over all matters within the scope of its duties as a North American ElectricReliability Council (“NERC”) Reliability Coordinator. The ICT performs its duties in an independent manner while utilizing information from Entergy, Market Participants, and other balancing authorities. Section 5 of Attachment S to Entergy’s OATT, in conjunction with the Reliability Coordinator Protocol appended to Attachment S, provides that the ICT shall have exclusive authority to execute Transmission Loading Relief (“TLR”) procedures under NERC Standards IRO-006-4 and PER-004-1. Therefore, the ICT Reliability Coordinator has and exercises the authority to independently execute TLR events if it deems necessary. In order to mitigate projected overloads on the Entergy system, the ICT Reliability Coordinator also can re-dispatch generators, reconfigure and modify transmission maintenance and outage schedules, as well as adjust transmission schedules and reduce load to mitigate critical conditions.

As described more fully in the ICT Quarterly Performance Reports, the ICT has encountered increased congestion on the Entergy system due to record temperatures, large outages, and certain policy decisions by Entergy regarding voluntary redispatch that were implemented during the year.9 This increased congestion necessarily forced the ICT to call a

8 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 3.3 and 3.4, filed March 9, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, sections 8.3 and 8.4, filed June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 8.3, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 8.3, filed December 31, 2007.9 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 2.4, filed March 9, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 2.4, filed June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 2.4, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 2.4, filed December 31, 2007.


7

higher number of TLRs to curtail transmission service and help prevent instability, uncontrolled separation, or cascading outages compared to the previous year. From December 1, 2006 through November 30, 2007, the ICT Reliability Coordinator has initiated three hundred and three (303) TLR events with a total curtailment of 471,622 MWh’s during this period. For comparison purposes, from December 1, 2005 though November 30, 2006, there were a total of two hundred and eight (208) TLR events initiated with a total of 216,778 MWh’s curtailed. Figure 2 illustrates these TLR events broken down by monthly totals for the ICT and Entergy/ICT.

Figure 2

Based on its first year of experience as Reliability Coordinator for Entergy and the increase in TLR events, the ICT has initiated the development of a comprehensive Reliability Improvement Plan with Entergy and its stakeholders. This plan will consider all potential mitigation options including generation redispatch, mandatory generation ratios, the use of operating guides, and coordination with the ICT long-term planning group to reduce the number of TLRs and relieve the severe congestion on portions of Entergy’s system. The ICT firmly believes that these efforts will lead to a decrease in congestion and TLR events in the next year.


8

C. Transmission and Interconnection Studies

In accordance with the ICT’s responsibility to oversee the provision of transmission service on Entergy’s system, the ICT is charged with performing the studies necessary to evaluate transmission and interconnection service requests. As reported earlier, there has been a significant increase in the demand for service on Entergy’s system since the ICT was installed. Correspondingly, there has been an increase in the number of TSRs and interconnection requests that require a study to be performed.

As reported in the ICT’s Annual Report, during the first year of the ICT’s operations requested System Impact Studies (“SIS”) and Facilities Studies (“FS”) related to TSRs were processed, on average, in a timely manner and within the sixty (60) day study completion deadline under Entergy’s OATT.10

Further, as reported in the ICT’s Annual Report, Feasibility Studies and SIS related to generation interconnection requests were processed, on average, beyond the completion deadlines for those studies as established under Entergy’s OATT.11 The ICT reported that these delays were due, in large part, to complex nuclear studies that postponed the start of other studies of interconnection requests lower in the queue.12

During the first year of the ICT’s operations, eleven (11) interconnection requests were received by the ICT. In comparison, ten (10) interconnection requests were received by Entergy in the prior year.

D. Transmission Planning

On November 17, 2007, the ICT assumed the transmission planning responsibilities for Entergy’s system. Consistent with this obligation, the ICT has implemented a 2007 Interim Base Plan and has completed a draft 2008 Base Plan. As reported in the ICT’s Annual Report, each Base Plan has identified new transmission projects to improve reliability and transmission service on Entergy’s system. Some of those new projects have subsequently been incorporated into Entergy’s Construction Plan, including the following:

• Fawil: Upgrade 138/69 • Ray Braswell – Wynndale New 115 kV Line

• Close Patterson Bus Tie• Upgrade Switch Risers at Rison• College Station 138 kV Switch Station

The ICT’s Base Plan has also been used in the evaluation of transmission upgrade cost allocation under Entergy’s transmission pricing. See infra section IV.A.

The ICT, on its own initiative, has also developed an ICT Strategic Transmission Expansion Plan (“ISTEP”). The ISTEP provides Entergy and its stakeholders with an independent assessment of transmission projects that the ICT believes would enhance both

10 See ICT Annual Report at section III.8. 11 See id. 12 See id. at section II.3 at n. 3.


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reliability and economics within the Entergy footprint. The ISTEP will be subject to review and comments by stakeholders and Entergy and is intended to be finalized during the coming year.

Finally, greater regional and inter-regional planning has been a focus during the ICT’s first year of operations. In particular, the ICT has actively pursued various planning initiatives with transmission systems adjacent to Entergy. For example, a Rate Pancaking Task Force was formed with stakeholders to consider the impact of rate pancaking between Entergy and SPP and develop possible alternatives to the current structure. The focus of this, and other, efforts has been to improve communications between Entergy and other transmission systems in order to improve coordination and cooperation on expansion planning and reliability matters. In addition, Entergy, transmission customers, and the ICT have continued to work together to identify system constraints and load pockets on Entergy’s system and to analyze viable system enhancements and upgrades to resolve these congestion problems.

E. WPP

In the ICT Approval Order, the Commission approved the WPP as a way to improve Entergy’s procurement options by allowing merchant generation and other wholesale suppliers to compete to serve Entergy’s native load customers and by granting short-term firm transmission service through redispatch.13 The Commission envisioned that the WPP would commence in mid-2007 and Entergy’s customers would then begin to see the benefits of the WPP through customer savings.

As detailed in the ICT’s Quarterly Performance Reports, the development and testing of the WPP software and procedures has taken longer than originally anticipated and has delayed the implementation of the WPP.14 Therefore, as of the date of this report, the WPP has not commenced operations and the anticipated benefits of the WPP have not yet been realized. The ICT will continue to work closely with Entergy and stakeholders in the coming year to ensure that the WPP is fully developed and tested and that the WPP is successfully implemented.

13 See ICT Approval Order at P 246.14 See ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 5, filed

June 27, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 5, filed October 2, 2007; ICT Quarterly Performance Report, Docket No. ER05-1065-000, section 5, filed December 31, 2007.


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IV. Transmission Pricing

A. Entergy’s Transmission Pricing

The Commission-approved Entergy transmission pricing for recovery of new facility costs contains two primary components: Base Plan Upgrades (Entergy-funded) or Supplemental Upgrades (Customer-funded).15 Consistent with Commission practice and precedent and as described in Attachment T of the Entergy OATT, the pricing for Base Plan Upgrade costs, which includes upgrades that are needed to ensure reliability and meet load growth, are rolled-in to base transmission rates.16 Supplemental Upgrades, which by definition fall outside of reliability and load growth requirements, are paid for by the customer that causes the upgrade to be incurred.17 Under Attachment T, the Transmission Customer also receives limited rights associated with a Supplemental Upgrade.18 Entergy’s transmission pricing is designed to send efficient price signals for new interconnections and will be applied on a comparable basis to all customers.

FERC Order No. 2003 stated that such pricing of Supplemental Upgrades would be available to transmission providers that have turned over control of their transmission systems to an RTO or ISO. Although the ICT is not functioning as an RTO for Entergy, the Commission approved Entergy’s pricing structure for the initial term of the ICT and found that the level of oversight that the ICT has been given over Entergy satisfies the fundamental findings in Order 2003.19

In addition, the Entergy system has approximately 20,000 MW of merchant generation connected to its system and without the pricing for Supplemental Upgrades as described in Attachment T to Entergy’s OATT, the cost of network upgrades necessary to qualify this amount of generation as network resources would be borne unfairly by native load and other transmission customers under Base Plan funding pricing.

The ICT is responsible for determining whether upgrades should be classified as Base Plan or Supplemental as defined in Entergy’s OATT, including Attachment T, The Transmission Planning Protocol, Transmission Service Protocol, and Interconnection Service Protocol as appended to Attachment S, the Point-to-Point and Network Service provisions of Part II and III of the Entergy OATT, the Large Generator Interconnection Procedures (LGIP) in Attachment N, and the Large Generation Interconnection Agreement (LGIA) in Attachment O.

15 See Attachment T, Entergy’s OATT, section 2.16 Id.17 Id.18 See id. at section 4.19 See ICT Approval Order at P 167.


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B. ICT Assessment of Entergy’s Transmission Pricing

In order to assess the effectiveness of Entergy’s Transmission Pricing mechanism to ensure that merchant generation seeking to compete in the Entergy footprint is provided the proper incentives to invest in transmission, several factors must be considered. The pricing installed at the start of the ICT has been in place for only one year. Also, as described below, certain aspects of Entergy’s pricing structure are still pending implementation; thus, any analysis of the effectiveness of the pricing structure in creating a more competitive environment for merchant generation and providing adequate incentives for investment in the transmission system must necessarily be considered in conjunction with these facts. That being said, this assessment considered, to the extent possible, any trends in generation interconnection or transmission upgrades that show any increase (or decrease) in competition for embedded merchant generation with network generation that may be attributable to the implementation of the new transmission pricing structure.

The first area reviewed to determine the impact of the new transmission pricing was committed investments associated with long-term TSRs. If the impact of the new transmission pricing methodology increased competition for merchant generation during the first year, long-term transmission should have shown an increase in commitments to investment by merchant generation (i.e. the Supplemental Upgrade pricing mechanism together with congestion protection in the WPP and the financial payments associated with future use should have provided adequate incentives for merchant generation to invest in transmission upgrades required to support long-term TSRs). While the ICT did experience an increase in long-term TSRs during the first year, no transmission customer, including any merchant generation, committed to fund a Supplemental Upgrade associated with a request for long-term transmission service.

The generation interconnection process is the second area that could be affected by the transmission pricing structure change. While the pricing change could impact generation interconnection decisions, the expected impact would be limited as most of the benefits would be identified through the requested transmission service as discussed above. The general market conditions could also dictate changes to the generation interconnection queue and the number of requests. The ICT did not see any significant changes to the generation interconnection queue, and considers this as a neutral indicator of the transmission pricing policy impact.

A third area of review in the ICT’s assessment of the transmission pricing structure is the review of previously incurred generation interconnection costs funded by merchant generation. In accordance with section 5 of Attachment T of the Entergy OATT, the ICT completed a study of previous interconnection upgrades that were originally funded by a transmission customer and considered Base Plan for purposes of cost allocation. The purpose of this study was to complete an independent evaluation of previously incurred interconnection costs based on the current system configuration and determine whether the cost allocation for the facilities should be changed.20 If the ICT determined that the upgraded facilities in question would have qualified as Base Plan upgrades under the Attachment T definition, the ICT presented this result and the supporting data in the Retrospective Generation Interconnection Analysis (“RGIA”) report. The customer or Entergy is free to petition the Commission to revise the service



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agreement and approved cost allocation as a result of the RGIA. The ICT’s RGIA report resulted in the following upgrades being reclassified as Base Plan, and thus, the original funding customers could be eligible for refunds of any un-credited amounts on these upgrades which total approximately $9.3 million:

• Orange Change Breakers • Horn Lake Replace Disconnect • Getwell-Hernando Transmission Line • Horn Lake Replace Breaker • Crossett North: Replace (3) 115 kV Breakers • Attala (station upgrade) • Winona (station upgrade) • Winona-Koscuisko (Line upgrade) • Vicksburg Sub Upgrade

The remaining 42 upgrades were classified Supplemental with the un-credited amounts totaling approximately $76.9 million. Funding customers will retain the rights associated with Supplemental Upgrades as defined in Attachment T of the OATT. While the ICT evaluation did reclassify some of the upgrades, this evaluation did not provide any noticeable impact on theposition of merchant generation in the Entergy footprint.

Furthermore, certain provisions of the pricing mechanism described in Attachment T and other sections of the Entergy OATT are not fully implemented at the date of this report. Under section 4.4 of Attachment T, transmission customers that fund a Supplemental Upgrade will receive financial payments for any future short-term use of that upgrade. In the May 25, 2007 Order on Compliance, the Commission required that Entergy file a status report regarding the development of the software necessary to implement this section of Attachment T.21 In its status report on October 1, 2007, Entergy reiterated its commitment to develop the appropriate software and keep the Commission apprised of the future progress. However, at the time of this report, the software has not been implemented nor does the ICT have a date certain when the software will be in place.

Another complicating factor in the assessment of the transmission pricing structure in Attachment T is the implementation of the WPP. As reported above, the WPP has been delayed by unexpected issues in the development of the software and testing. The implementation of the WPP is expected to provide benefits to customers funding Supplemental Upgrades because of the Attachment V and T provisions that protect those customers from congestion charges in the WPP. Because the compensation and WPP-related provisions of the transmission pricing structure have not been implemented, it is somewhat premature to draw conclusions regarding the effectiveness of the full transmission pricing structure approved by the Commission in Docket No. ER05-1065.

Finally, as explained in section III.B. above, the ICT experienced an increase in transmission congestion and TLRs on the Entergy transmission system during the past year. The high level of TLRs demonstrates that there is considerable room for transmission expansion to provide for a more economic and reliable operation of the grid. While the congestion that is currently experienced on the system may not be at a level or duration to support the funding of transmission system expansion by Entergy or a single customer, the ICT is committed to work

21 Entergy Services, Inc.,119 FERC ¶ 61,187 (2007).


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with Entergy and its stakeholders to find both economic and reliability transmission solutions that incorporate both the current TLR events as well as an assessment of Short-Term and Long-Term transmission requests.

C. Summary of ICT Assessment

Although there are several factors that arguably make this assessment premature, the ICT has, to date, seen little evidence that Entergy’s Transmission Pricing has changed the conditions of merchant generation seeking to compete in the Entergy footprint during the first year of operation. From currently available indications, conditions appear to be generally unchanged from the prior state. The new transmission pricing policy did not provide for any measurable change in Long-Term or Short-Term transmission requests receiving service through use of the new pricing methodology nor was there any change in generation interconnection requests. If the approximately 20,000 MW of existing merchant generation within the Entergy footprint was transmission constrained and the new transmission pricing policy provided for a substantial improvement in their ability or willingness to fund Supplemental Upgrades, it is expected that additional upgrades through TSRs would have been pursued during the year. While there was an increase in the amount of TSRs, this increase cannot be attributed to the new transmission pricing policy. However, the ICT expects that the full implementation of the WPP and short-term compensation mechanism will create additional incentives that may provide merchant generation and other transmission customers the motivation to commit to Supplemental Upgrades, thereby increasing competition to serve Entergy’s network load.

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Bruce RewJanuary 17, 2008

Contract Services Update

www.spp.org 3

SPP Strategic Plan 10/06 – Contract Services

SPP will continue to offer services on a contract basis, pursuant to Board-approved assessment criteria, in order to increase revenues, further membership in SPP, and enhance the quality of existing services.

The following steps should be taken:1. SPP will continue to provide services to non-SPP Members that leverage SPP’s existing infrastructure.2. SPP will continue to evaluate these opportunities as they arise to ensure they fit within SPP’s Mission and Value Statements and provide benefits to the existing SPP Members (in terms of reduced administrative fees).

www.spp.org 4

Contract Services Overview

• Increase Revenues: Provides a positive cash flow to SPP operations equal to approximately a 0.03$ fee reduction

• Further Membership in SPP: Enhances new membership development by providing transition alternatives for prospective members

• Enhance Quality of Existing Services: Improved SPP operations through best practices and increased seams coordination

www.spp.org 5

ICT Services

• SPP Independent Coordinator of Transmission (ICT) for Entergy started 11/06

• The ICT performs tariff administration, reliability coordination, transmission planning and developing a Weekly Procurement Process (WPP)

• The ICT has a stakeholder process that includes a Stakeholder Policy Committee (SPC) and 4 working groups. Each participant gets a vote to establish stakeholder positions

www.spp.org 6

ICT 2007 Operational Highlights

• Tariff Administration has identified numerous corrections to the AFC process resulting in 38 instances of reported corrections

• Reliability Coordination has experienced an increase in TLR activity and is working on improvements to reliability and coordination with the SPP RC. The ICT has worked with Entergy to get a 500kV terminalupgraded to reduce TLR 5.

• Transmission Planning is working in Acadiana load pocket to develop a long-term transmission expansion plan. The ICT is close to get a project agreed to in the area.

• The WPP implementation has been delayed due to software development challenges and is scheduled for second quarter of 2008 start

• The ICT staff has implemented Order 693 and 890 requirements

• The ICT issued ISTEP developing a long-term strategic transmission plan

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www.spp.org 7

ICT 2008 Work Plan• Implement the WPP in the second quarter

• Improved Customer relations resulting in improved customer survey. The survey showed that ICT is better than status quo but needs to improve to meet customers high expectations.

• Continue work on Tariff Administration/OASIS Automation improvements.

• Reliability Coordination improvements implemented to reduce TLR

• ISTEP completed and projects prioritized, Acadiana Load Pocket plan approved and constructed started in 2008

• Continue interaction with state commissions on the efforts of the ICT.

• Maintain reliability and compliance requirements

www.spp.org 8

ITO Services• E.ON U.S. (LG&E/KU) selected SPP to be an Independent Tariff

Organization and operations began on September 1, 2006

• The ITO performs the following functions:

• tariff administration

• OASIS hosting

• transmission scheduling

• transmission planning functions

• The ITO administers a stakeholder process

• TVA provides Reliability Coordination for E.ON

www.spp.org 9

ITO Highlights and action plan• Highlights:

• ITO successfully passed a FERC review of ATC process

• Implemented Order 890 requirements

• Action Plan

• Improve communications with E.ON and TVA

• Complete transition to new management

• Improve Transmission and Generation interconnection study process

www.spp.org 10

Contract Services Summary

• Improve Stakeholder satisfaction and perception of Contract Services Independence

• Continue to work on SPP risk mitigation and financials

• Transmission planning and expansion

Bruce Rew, P.E.Executive Director, Contract [email protected]

Southwest Power Pool, Inc.

REGULATORY AFFAIRS

Regulatory Update Fourth Quarter 2007

SPP Regulatory staff is currently monitoring 226 cases at the state and federal levels, a net increase of 45 cases since last quarter. Of this activity, 82% involves regulatory dockets at FERC with the remaining 18% attributable to state regulatory matters in Arkansas, Kansas, Louisiana, Missouri, New Mexico and Texas. An overview of significant regulatory activities arising in the fourth quarter of 2007 is set forth below.1 A detailed docket status report is available on the SPP website. A. FERC Audit, Docket No. PA08-2 On October 4, 2007, FERC initiated an audit concerning SPP’s responsibilities as a Regional Entity and a Regional Transmission Organization. FERC seeks to determine whether SPP is operating in compliance with the SPP Bylaws, Delegation Agreement between NERC and SPP and the conditions included in the Delegation Order, SPP Membership Agreement, transmission provider obligations described in the SPP OATT and other obligations and responsibilities as approved by the Commission. The first Data Request was received November 19, 2007 with responses to the 72 items due December 14, 2007. SPP responded as follows: 64 responses provided December 14, 2007; 3 responses provided December 21, 2007, following the granting of an extension; 5 responses deferred as the subject of open dockets. B. FERC CEII Requests SPP staff received a number of FERC CEII requests in 2007. Seven CEII requests are currently pending before the Commission for approval in the following dockets: CE08-15, CE08-16, CE08-27, CE08-28, CE08-29, CE08-30, and CE08-31. Additional information on individual CEII requests is presented in the detailed docket status report. SPP staff has finalized a recommendation for consideration by the Markets and Operations Policy Committee (“MOPC”) at its January 15-16, 2007 meeting that we believe will resolve questions and concerns regarding the CEII process. C. Reevaluation of FERC’s Annual Electric Assessment The FERC Fee Whitepaper prepared by the Regulatory Legislative Committee of the ISO/RTO Council (“IRC”), “The Need for Reassessment: Ensuring Equity in the Assessment of FERC Annual Charges,” is now available on the Documents and Filings portion of the SPP website. Representatives of the IRC members and the members’ stakeholders, including Nick Brown of SPP and Sandra Hochstetter, former Chairman of the Arkansas Public Service Commission 1 Dockets or cases with no significant activity during this period have been omitted.

(“APSC”) and now Vice President of Strategic Affairs for AECC, met with the FERC Commissioners individually in Washington, D.C. on October 24, 2007 to discuss this issue and present the paper. D. IRC Media Briefing and Congressional Forum The IRC hosted a media briefing and Congressional forum in Washington, D.C. on October 16, 2007 to discuss energy efficiency, renewable generation and demand response. In October of 2007, the IRC issued three reports: “Increasing Renewable Resources: How ISOs and RTOs are Helping Meeting this Public Policy Objective,” “Progress of Organized Wholesale Electricity Markets in North America,” and “Harnessing the Power of Demand.” These reports are available on the documents section of the IRC website, www.iso-rto.org.

E. FERC Rulemaking Proceedings 1. Docket Nos. RM05-5 & RM96-1-027: Order No. 698 & 698-A

These dockets involve the development of measures to enhance communications between the natural gas and electric utility industries. Order No. 698 compliance filings, statements of compliance and petitions for waiver have been filed in Docket No. RM05-5. On December 20, 2007, FERC issued Order No. 698-A denying requests for rehearing, providing clarification of the final rule, and providing policy guidance on coordination issues. The North American Energy Standards Board (“NAESB”) has filed a report of its activities from January 2005 to October 2007 regarding the adoption of Version 001 of the Wholesale Electric Quadrant Standards.

2. Docket Nos. RM05-17 & RM05-25: Order Nos. 890 & 890-A SPP staff participated in a FERC Order No. 890 Transmission Planning Regional Technical conference in Atlanta, Georgia on October 1-2, 2007. NERC filed a revised standards work plan with FERC on October 5, 2007. On November 1, 2007, E.ON U.S. requested clarification of FERC’s September 7, 2007 notice granting an extension of the effective date of the minimum lead time for undesignating network resources adopted in Order No. 890. On November 20, 2007, FERC granted SPP an extension of time up to and including December 14, 2007 to file an attachment to the SPP OATT incorporating transmission planning principles and concepts adopted in Order No. 890. FERC has since granted public utilities an extension of time up to and including May 9, 2008 to modify the reliability standards related to the calculation of ATC in compliance

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http://www.iso-rto.org/

with Order Nos. 890 and 693, further allowing utilities up to and including August 7, 2008 to develop business practices that complement NERC’s new reliability standards. FERC issued Order No. 890-A on December 28, 2007, granting limited rehearing and clarification to address implementation of certain reforms and to ensure that transmission service is provided on a non-discriminatory, just and reasonable basis.

3. Docket Nos. RM06-16 and RM06-22: Mandatory Reliability Standards for the Bulk Power System

Both SPP and the IRC have filed NOPR comments in this proceeding. In a series of filings, NERC has submitted to FERC: (1) its revised standards work plan, (2) a proposed amendment to the NERC Rules of Procedure – section 1600, (3) a compliance filing, (4) a petition for interpretations of requirements for four FERC-approved NERC Reliability Standards, (5) a petition seeking approval of proposed reliability standards INT-001-3, INT-004-2, INT-005-2, INT-006-2, and INT-008-2, and (6) a petition seeking approval of proposed reliability standard IRO-006-4. Commission action is forthcoming.

4. Docket No. RM06-23: Order No. 702

On October 30, 2007, FERC issued a final rule amending its regulations for gaining access to CEII. The final rule creates an annual certification for repeat requesters; provides for the issuance of letter responses to CEII requests, rather than delegated orders; and eliminates the Non-Internet Public designation, allowing filers until December 29, 2007 to identify any NIP documents that may qualify for CEII protection and request that the designation be changed. On November 29, 2007, the Edison Electric Institute filed a request for rehearing and clarification of Order No. 702, asking that: (1) submitters of CEII be allowed adequate time to respond to requests for release of their CEII; (2) FERC allow submitters an opportunity for administrative review before FERC releases the information; and (3) FERC stay the release of information pending administrative review and pending judicial appeal of a decision to release. FERC granted rehearing of Order No. 702 on December 31, 2007.

5. Docket No. RM07-3: Three New Proposed NERC Reliability Standards

On December 20, 2007, FERC approved NERC Reliability Standards FAC-010-1, FAC-011-1 and FAC-014-1. These standards set requirements for the development of system operating limits of the bulk-power system for use in the planning and operation horizons

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6. Docket Nos. RM07-19/AD07-7: Wholesale Competition in Regions with Organized Electric Markets On December 16, 2007, the AARP, et al. filed a joint request with FERC to expand the scope of the section 206 proceeding to investigate the justness and reasonableness of wholesale power prices charged in RTO-run centralized markets. FERC has not yet acted on this request.

F. FERC Administrative Proceedings 1. Docket No. AD07-12: Reliability Standard Compliance & Enforcement in Regions with

ISOs & RTOs On September 18, 2007, FERC held a technical conference to address issues associated with cost recovery of penalties for reliability standard violations assessed against ISOs and RTOs. SPP and the IRC filed separate post-technical conference comments on October 2, 2007. NERC filed comments on November 6, 2007. FERC action is forthcoming.

2. AD07-13: FERC Conference on Enforcement Policy SPP Regulatory staff monitored FERC’s November 16, 2007 webcast of FERC’s conference on enforcement, which addressed the implementation of the Commission’s enforcement authority as expanded by the Energy Policy Act of 2005. According to Chairman Kelliher, in 2007 FERC entered into twelve settlements involving a total of $41.6 million in civil penalties. After opening remarks by the Commission, Susan J. Court, Director of the Office of Enforcement, presented an overview of the first two years of EPAct enforcement, which was followed by panel discussions of the broad policy perspective, the practitioners’ view and the enforcement of reliability standards. A video with audio webcast archive of this conference is available online at: http://www.capitolconnection.gmu.edu/ferc/ferc.htm. SPP did not file post-conference comments.

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http://www.capitolconnection.gmu.edu/ferc/ferc.htm

G. FERC ERO Rules & Organizational Filings

Docket No. RR06-1: NERC Filing of Version 5 Reliability Standards; Docket No. RR06-3: 2007 Business Plan and Budget, & Budgets of Regional Entities; & Docket Nos. RR07-1 thru RR07-8: Regional Entity Delegation Agreements2 Having been granted an extension of time, on October 30, 2007, NERC submitted a filing in compliance with FERC’s April 19, 2007 Order in Docket Nos. RR06-1-004, RR06-3-000 and RR07-1-000, et al.

NERC’s third quarter 2007 report on the analysis of voting results for reliability standards is now posted for the period of July 1, 2007 thru September 30, 2007. Edison Electric Institute and the National Rural Electric Cooperative Association have filed a limited protest of NERC’s October 30, 2007 compliance filing. NERC filed an answer to the comments and protests on December 14, 2007.

H. FERC Electric Rate & Other Formal Filings of Interest 1. Docket Nos. EL05-148 & ER05-1410: Settlement concerning PJM’s Reliability Pricing

Model Program

On October 1, 2007, PJM submitted corrections to its September 24, 2007 FERC Status Report, as supplemented September 26, 2007, on integrating energy efficiency into the capacity market and forum for identifying and resolving impediments to demand response.

Supplemental protests, as well as protests to PJM’s September 24, 2007 compliance filing, have been filed.

The PJM Industrial Customer Coalition intervened on October 15, 2007.

On November 15, 2007, FERC denied the PJMICC Group’s3 request for rehearing of the Commission’s June 25, 2007 Order, affirming its finding that the Reliability Pricing Model program produces just and reasonable rates for capacity in PJM.

2. Docket Nos. EL07-27 & ER07-396: ETEC/Tex-La/Deep East Settlement Agreement & SPP Filing of OATT Revisions to Incorporate these Annual Transmission Revenue Requirements upon FERC Approval

On October 31, 2007, an Offer of Settlement was submitted by East Texas Cooperative, Tex-La Electric Cooperative, and Deep East Texas Electric Cooperative resolving all issues set for hearing concerning revenue requirements to be included in the SPP Tariff.

2 Due to the overlap in content, these dockets are being presented together. 3 The PJM Industrial Customer Coalition, the Maryland Office of the People’s Counsel and the District of Columbia Office of the People’s Counsel

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On November 20, 2007, FERC Trial staff filed comments in support of the settlement agreement. FERC certified the settlement as uncontested on November 26, 2007. These dockets will be terminated upon approval of the settlement.

3. Docket No. EL07-87: Xcel’s Complaint against SPP & John Deere Wind Energy

On November 7, 2007, J.D. Wind filed a Status Report and Expedited Motion for Extension of Time for the filing of answers to the August 13, 2007 complaint of Xcel Energy Services, Inc. FERC granted J.D. Wind an extension of time up to and including December 17, 2007. Joint Status Reports were filed by Xcel Energy Services, Inc. and J.D. Wind on December 17 and 21, 2007. The parties anticipate that an agreement will be filed by January 7, 2008.

4. Docket No. EL08-9: Cargill’s Complaint against SPP

On November 9, 2007, Cargill Power Markets, LLC filed a formal complaint against SPP alleging that SPP processed a queue of requests for long-term firm point-to-point transmission service on the ERCOT East DC Tie in a manner that violated FERC policy and the SPP Tariff. At page two of the Complaint, Cargill requests that FERC “instruct SPP on the proper application of FERC’s first come, first serve principle and direct SPP to reprocess the queue in a manner that requires the incumbent transmission service customer to match only properly designated ‘competing request’ of ten years in duration and to enter into renewed transmission service agreements with ten-year terms.” SPP filed an answer in opposition of Cargill’s complaint on November 39, 2007, requesting that the Commission deny Cargill’s claim for relief and dismiss Cargill’s complaint with prejudice. SPP contends that its processing of competing new service requests for the East DC Tie was consistent with section 2.2 of the SPP Tariff, as well as section 2.12 of SPP’s Business Practices, and that the provisions of SPP’s Tariff and Business Practices are consistent with FERC policy. Tenaska Power Services Co. and Constellation Energy Commodities Group, Inc. have moved to intervene in this proceeding, with Calpine filing a Motion to Intervene and Limited Answer. FERC action is forthcoming.

5. Docket Nos. ER03-765 & ER07-371: Reactive Compensation

On November 19, 2007, FERC denied East Texas Cooperatives’ (“ETC”) request for rehearing of the May 21, 2007 Order. FERC also directed that Calpine submit a new compliance filing by December 19, 2007, removing the words “to SPP” from section 1 of the revised rate schedule. The next day, FERC issued an order granting in part and denying in part rehearing and conditionally accepting SPP’s July 16, 2007 compliance filing, subject to revisions, to

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become effective March 1, 2007. SPP must submit the required compliance filing on December 20, 2007, amending section II.A and adding language to section V as dictated by the Commission at paragraph 26 of the order.

6. Docket No. ER05-925: Westar Refund Report

Westar is awaiting FERC action on its September 14, 2007 filing of a refund report in compliance with Article II (Settlement Rates) of the settlement agreement.

Westar requests that the Commission grant waiver of the requirement that Westar submit a report of refunds within 30 days of the date refunds are made.

Comments on Westar’s compliance filing were due October 5, 2007. None were filed.

7. Docket Nos. ER05-1051 & ER05-1052: Westar-KPP Ancillary Services Settlement

On October 4, 2007, FERC issued a letter order approving SPP’s August 2, 2007 filing of the Westar-KPP ancillary services settlement. Commissioners Kelly and Wellinghoff dissented in part with separate statements. The letter order terminates Docket No. ER05-1052-000.

On December 31, 2007, SPP submitted a refund report in compliance with FERC’s October 4, 2007 Order.

8. Docket Nos. ER06-20 & EC06-4: ITO Second Semi-Annual Report

On October 15, 2007, SPP submitted the ITO’s Second Semi-Annual Report for the period of March through August 2007.

9. Docket Nos. ER06-451, et al.: EIS Market Implementation

SPP filed an answer in this proceeding on October 11, 2007. FERC rejected without prejudice SPP’s August 3, 2007 filing of proposed Tariff revisions, as amended August 16, 2007. SPP submitted the required compliance filing on December 14, 2007, revising the SPP Tariff to implement a modified plan to allow external resources to participate in SPP’s real-time EIS Market. An effective date of October 15, 2008 is requested. SPP has also filed the Congestion Resolution Report, Depth of Market Report, Over/Under Scheduling Report and Revenue Neutrality Uplift Report.

10. Docket No. ER06-729: Attachment M Revisions

On January 26, 2007, FERC granted SPP’s limited request for rehearing of the October 19, 2006 Order and also approved SPP’s November 20, 2006 compliance filing.

SPP must submit a new compliance filing by February 1, 2008 detailing the neutrality uplift payments associated with losses for into and within transactions and through and out transactions, as required by FERC’s October 19, 2006 Order.

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11. Docket No. ER07-282: Executed Service Agreement for Firm Point-to-Point Transmission Service with KPP & Revised Agreement for Firm Point-to-Point Transmission Service between SPP & KMEA

On November 6, 2007, FERC accepted SPP’s December 1, 2006 filing, of an executed service agreement for firm point-to-point transmission service with KPP and a revised agreement for firm point-to-point transmission service between SPP and KMEA, as amended on June 27, 2007 and September 12, 2007. An effective date of November 1, 2006 was granted as requested.

12. Docket No. ER07-525: Entergy Filing of Long-Term Firm Point-to-Point Transmission

Service Agreement between Entergy & AEP On October 18, 2007, FERC issued an order denying Entergy’s request for rehearing of the June 29, 2007 order which accepted and suspended the proposed rate schedule and established hearing and settlement judge procedures. FERC has directed Entergy to make time value of revenues refunds within 30 and file a refund report with the Commission within 15 days thereafter. Entergy filed a report of refunds paid to American Electric Power Service Corporation on November 29, 2007.

13. Docket No. ER07-643: Executed Meter Agent Service Agreements between AEP & SPP EIS Market Participants

On October 12, 2007, FERC issued a letter order accepting SPP’s August 9, 2007 compliance filing of revised versions of eight executed Meter Agent Service Agreements between AEP and various participants in SPP’s real-time EIS market. An effective date of February 1, 2007 was granted as requested.

14. Docket No. ER07-1069: AEP Filing of Revised Pro-forma Tariff Sheets to Update AEP’s Transmission Service Rates & Institute a Formula Rate

On October 1, 2007, AEP submitted a compliance filing in response to FERC’s August 31, 2007 Order Conditionally Accepting and Suspending Revised Tariff Sheets and Establishing Hearing and Settlement Judge Procedures.

On December 7, 2007, FERC issued an order in which it: (1) denied AEP’s request for rehearing, Customers’ request for rehearing and ETC’s request for rehearing concerning the classification of AEP’s transmission facilities, (2) granted East Texas Electric Cooperatives’ request for rehearing concerning thirteen monthly plant balances, and (3) accepted AEP’s compliance filing, effective February 1, 2008, subject to refund and subject to the outcome of the ongoing settlement and hearing procedures. FERC has also granted rehearing of its August 31, 2007 Order.

A settlement conference is scheduled for January 29, 2008 at the FERC headquarters in Washington, D.C.

SPP is an intervenor in this docket.

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15. Docket No. ER07-1093: Service Agreement for Network Integration Transmission Service between SPP & Westar, as well as a Network Operating Agreement between SPP, Western Resources, Inc. & Kansas Gas & Electric

On November 6, 2007, FERC accepted by letter order SPP’s September 25, 2007 filing of a revised version of the NITSA between SPP and Westar, as required by the Commission’s August 27, 2007 Order. An effective date of June 1, 2007 was granted as requested.

16. Docket No. ER07-1098: Executed Service Agreement for Network Integration Transmission Service between SPP & Grand River Dam Authority On October 3, 2007, FERC issued a letter order accepting SPP’s June 29, 2007 filing of an executed NITSA between SPP and GRDA, as amended August 9, 2007. This NITSA supersedes the Service Agreement included in SPP’s electronic filing of transmission service agreements pursuant to Order No. 2001.

17. Docket No. ER07-1099: Unexecuted Service Agreement for Network Integration Transmission Service between SPP & Western Farmers Electric Cooperative, Inc. On October 11, 2007, FERC accepted via letter order SPP’s June 29, 20007 filing of an unexecuted NITSA between SPP and WFEC, as well as an executed NOA between SPP and WFEC, and AEP, as amended August 23, 2007. An effective date of June 1, 2007 was granted as requested.

18. Docket No. ER07-1201: Partially Executed NITSA between SPP & AEP

On October 18, 2007, SPP filed as Exhibit I a partially executed NITSA between SPP as Transmission Provider and AEP as Network Customer, as well as the corresponding NOA. The NITSA was amended to add Designated Network Resources contingent upon the construction of transmission upgrades. FERC accepted SPP’s October 18, 2007 NITSA filing by letter order on December 18, 2007, to become effective February 1, 2007.

19. Docket No. ER07-1226: Proposed Tariff Revisions Changing Pricing Zone Rates & Incorporating Base Plan Rates On October 29, 2007, SPP submitted a filing in compliance with FERC’s September 28, 2007 Order revising Attachments H and T of the SPP Tariff to reflect the revenue requirement for Westar’s transmission facilities associated with the Spring Creek generating station. An effective date of September 30, 2007 is requested.

Comments on SPP’s October 29, 2007 filing were due to FERC by November 19, 2007. None were filed. FERC has not yet acted on SPP’s filing.

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20. Docket No. ER07-1248: SPP Filing to Revise SPP’s Tariff and Confirm SPP’s Adoption of Version 3 of NERC’s Transmission Loading Relief Procedures

On October 18, 2007, FERC accepted by letter order SPP’s August 3, 2007 filing of proposed Tariff revisions, as amended on August 24, 2007.

21. Docket No. ER07-1311: Proposed Tariff Revisions regarding the Interconnection of

Large Generators to SPP’s Transmission System, as well as SPP’s Pro Forma LGIA & LGIP On October 4, 2007, the American Wind Energy Association (“AWEA”) and the Wind Coalition requested leave to amend their motion to intervene to include a protest or, in the alternative, to file a late protest. AWEA and the Wind Coalition contend that: (1) SPP’s proposed treatment of Attachment Facilities is not just and reasonable; (2) SPP’s proposed variations to the reactive power standard should be rejected as unjust and unreasonable because they require capital investments in facilities that are unlikely to be used; (3) SPP’s restriction of important customer options for providing security lacks justification; (4) SPP’s proposed variations from the pro forma LGIA regarding restudy of reassessment of costs lack justification; and (5) SPP’s proposed variations from the LGIP regarding clustering are vague, restrict customers needlessly and lack justification. On October 19, 2007, SPP filed an answer to the late protest filed by the American Wind Association and the Wind Coalition, requesting that FERC accept SPP’s August 30, 2007 filing of proposed Tariff revisions with an effective date of November 1, 2007. On October 29, 2007, FERC issued a letter order finding SPP’s filing of revisions to its LGIA and LGIP to be deficient. SPP filed the necessary response on November 28, 2007.

22. Docket No. ER07-1319: Executed Network Integration Transmission Service & Network

Operating Agreement between SPP & Sunflower Electric Power Corporation On October 26, 2007, FERC issued a letter order accepting SPP’s August 31, 2007 filing of a revised NITSA and an NOA between SPP and Sunflower Electric Power Corporation, effective August 1, 2007 as requested.

23. Docket No. ER07-1320: Executed Service Agreement for Network Integration

Transmission Service between SPP & Kansas Electric Power Cooperative, Inc. & an Executed Network Operating Agreement between SPP, Kansas Electric Power Cooperative, Inc. & Mid-Kansas Electric Company On October 26, 2007, FERC accepted by letter order SPP’s August 31, 2007 filing of an executed NITSA between SPP and KEPCO and an executed NOA between SPP, KEPCO and Mid-Kansas Electric Company under SPP’s Tariff, effective August 1, 2007, as requested.

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24. Docket No. ER07-1417: MISO/SPP Filing of Proposed Revisions to the Congestion Management Process of their Joint Operating Agreement

On November 27, 2007, FERC issued an order conditionally accepting the proposed revisions to the Congestion Management Process of the JOA, effective October 1, 2007, as requested. FERC denied Xcel’s request to require that the filing parties attest that any changed calculations remain in compliance with NERC and NAESB requirements. However, the Commission is requiring that MISO and SPP clarify the language of section 6.6. On December 7, 2007, SPP and MISO filed the compliance filing required by the Commission’s November 27, 2007 Order. Several entities have moved to intervene in this proceeding, with Xcel filing a motion to intervene with comments.

25. Docket No. ER08-60: Partially Executed Service Agreement for Network Integration Transmission Service between SPP & AECC, as well as a Partially Executed Network Operating Agreement between SPP, AECC & AEP

On October 16, 2007, SPP filed a partially executed NITSA between SPP as Transmission Provider and Arkansas Electric Cooperative Corporation (“AECC”) as Network Customer, as well as a partially executed NOA between SPP as Transmission Provider, AECC as Network Customer and American Electric Power Service Corporation as agent for AEP as the Host Transmission Owner. On December 18, 2007, FERC accepted SPP’s filing via letter order, granting an effective date of January 1, 2008, as requested.

26. Docket No. ER08-78: Executed Revised Service Agreement for Network Integration Transmission Service between SPP & Westar On October 22, 2007, SPP filed an executed revised service agreement for NITS between SPP and Westar. The Agreement modifies an existing Service Agreement between SPP and Westar that was accepted by FERC subject to a compliance filing pending in Docket No. ER07-1093. An effective date of December 21, 2007 is requested for the proposed changes. FERC issued a letter order accepting SPP’s Filing on December 18, 2007, effective December 21, 2007, as requested

27. Docket No. ER08-90: Executed Amended & Restated Interconnection Agreement

between SPP, Public Service Company of Oklahoma & Western Farmers Electric Cooperative On October 25, 2007, SPP filed an executed Amended and Restated Interconnection Agreement between SPP, Public Service Company of Oklahoma and WFEC. The Agreement is intended to replace a previous interconnection agreement between WFEC and Public Service Company of Oklahoma and all subsequent amendments. FERC accepted SPP’s Filing via letter order on December 18, 2007, effective

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September 26, 2007, as requested.

28. Docket No. ER08-108: Updating the EIS Market Offer Cap On October 29, 2007, SPP filed Tariff revisions to reflect updates of annual values used in the calculation of offer caps for all pivotal resources in SPP’s real-time EIS market. FERC accepted SPP’s Filing via letter order on December 18, 2007. An effective date of January 1, 2008 was granted as requested. Golden Spread and Westar have moved to intervene in this proceeding.

29. Docket No. ER08-242: Tariff Revisions to Modify the EIS Service Market - Attachments AE & AF

On November 20, 2007, SPP filed proposed Tariff changes designed to implement improvements to the SPP EIS Market. An effective date of January 19, 2008 is requested. The proposed Tariff revisions conform to recently adopted modifications to SPP’s Market Protocols. Several motions to intervene have been filed, with motions to intervene and protest being filed by Golden Spread and the Electric Power Supply Association. On December 21, 2007, SPP filed an answer to the requests for rejection and modification submitted in this proceeding. SPP contends that its proposal to designate unscheduled imbalance transactions as non-firm will not harm the robustness of the EIS Market and is consistent with SPP’s JOA with MISO and also requests that FERC reject Golden Spread’s protest as procedurally improper.


Transmission Service between SPP as Transmission Provider and Kansas Municipal Energy Agency as Network Customer, as well as an Executed Network Operating Agreement between SPP as Transmission Provider, KMEA as Network Customer and Mid-Kansas Electric Company as the Host Transmission Owner

On December 3, 2007, SPP filed an executed NITSA between SPP as Transmission

Provider and KMEA as Network Customer, as well as an executed NOA between SPP as Transmission Provider, KMEA as Network Customer and MKEC as the Host Transmission Owner. An effective date of November 1, 2007 is requested.

Comments were due December 24, 2007, but none were filed. SPP is awaiting Commission action on this filing. 31. Docket No. ER08-296: MISO Filing of Revisions to Section 37 of the MISO Energy

Markets Tariff On December 3, 2007, MISO and the MISO Transmission Owners filed revisions to section 37 of the MISO Energy Markets Tariff to ensure that MISO’s distribution of revenues from network integration transmission service to Transmission Owners is just, reasonable, and not unduly discriminatory or preferential following the end of the MISO

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rate Transition Period, the first six years of MISO operations which end January 31, 2008. An effective date of February 1, 2008 is requested. As a result of this filing, on December 17, 2007, AmerenUE requested that the Missouri Public Service Commission suspend further proceedings in Missouri Docket No. EO-2008-0134. On December 12, 2007, Ameren filed an unopposed motion for extension of time to file protests and motions to intervene, which FERC denied on December 14, 2007. AmerenUE moved to intervene and protest on December 26, 2006, requesting that the proposed revisions be rejected in favor of language that meets the statutory standard or, at a minimum, that the matter be set for hearing and sent to settlement proceedings. FERC has not yet acted on AmerenUE’s filing.


Transmission Service between SPP as Transmission Provider and American Electric Power Service Corporation, as agent for Public Service Company of Oklahoma (“PSO”) and Southwestern Electric Power Company, as Network Customer, as well as an Executed Network Operating Agreement between SPP as Transmission Provider, AEP as Network Customer, and American Electric Power Service Corporation as agent for PSO, SWEPCO and AEP Texas North Company as Host Transmission Owner

On December 13, 2007, SPP filed an executed NITSA between SPP as Transmission

Provider and AEP as Network Customer, as well as an executed NOA between SPP as Transmission Provider, AEP as Network Customer and American Electric Power Service Corporation as agent for PSO, SWEPCO, and AEP Texas North Company as Host Transmission Owner. An effective date of February 1, 2008 is requested.

These Agreements reflect various amendments to the Agreements currently pending in

Docket No. ER07-1201-001, including the removal of Mutual Energy SWEPCO, L.P. as a network customer and revisions necessary for AEP to exercise its one-year rollover right prior to the filing of SPP’s transmission planning process pursuant to Order No. 890.

FERC has not yet acted on SPP’s filing.

I. Open Access Transmission Tariff Filings 1. Docket Nos. OA07-17 & OA07-32: Entergy’s Order No. 890 Compliance Filing

On November 30, 2007, Entergy Services, Inc. made a filing in Docket No. OA07-32 informing FERC that Entergy has complied with Order No. 890’s requirements concerning the evaluation of pre-confirmed transmission service requests. FERC also issued an order in Docket No. OA07-17 on December 13, 2007, accepting Entergy’s August 13, 2007 filing of revised Tariff sheets. An effective date of July 13, 2007 was granted as requested.

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2. Docket No. OA08-5: SPP’s Order No. 890 Compliance Filing

On October 11, 2007, SPP filed Tariff revisions incorporating specific changes to the Order No. 888 pro forma OATT adopted by FERC in Order No. 890. Motions to intervene and protest/limited protest have been filed by Redbud, the TDU Intervenors, and AWEA. The Southwestern Power Administration, AEP, and Xcel have also moved to intervene. SPP filed an answer to the protests and requests for modification, asking that FERC reject the protests and accept SPP’s compliance filing. SPP contends that it is exempted from providing conditional firm service due to its real-time EIS market and that the protest of the TDU Intervenors is procedurally improper. FERC action is forthcoming.

3. Docket No. OA08-60: SPP Request for Waiver of Rollover Policy in Order No. 890 for

Certain Potential SPP Firm Transmission Service Customers

On December 14, 2007, SPP requested that the Commission waive the applicability of its revised policies concerning rollover rights adopted in Order No. 890 for certain potential SPP firm transmission customers. Such waiver is necessary to ensure that specific potential customers will have an existing rollover right at the time SPP’s planning process becomes effective and will be able to roll t heir transmission requests under the Commission’s pre-Order No. 890 policies. Comments on SPP’s request were due to FERC January 4, 2008.

4. Docket No. OA08-61: SPP Order No. 890 Compliance Filing

On December 14, 2007, SPP submitted revisions to the SPP Tariff in compliance with the Commission’s directives to file a proposal for a coordinated and regional planning process that complies with the planning principles adopted in Order No. 890.

Comments on SPP’s filing were due January 4, 2008.

J. Pending Waiver Requests

There were two waiver requests pending as the fourth quarter came to an end. The Empire District Electric Company has asked for a waiver in connection with the Cloud County Wind Farm. The waiver is unique from past waivers as it seeks to establish policy concerning the level of capacity upon which Base Plan funding is provided; i.e. the net dependable capacity or the wind farm capacity. The SPP Regional State Committee (“RSC”) and its Cost Allocation Working Group (“CAWG”) are addressing the policy issue. Current plans call for the RSC to reach a policy recommendation, the SPP staff to issue its recommendation on the waiver, and the matter to be reviewed and acted upon by the MOPC and Board of Directors during the January 2008 cycle of meetings.

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The second pending waiver is from American Electric Power involving the Turk Power Plant. This waiver request will also be considered as a part of the normal waiver review process during January.

K. Entergy’s ICT Proposal

Entergy’s ICT Proposal is addressed in FERC Docket Nos. ER04-699-000 and ER05-1065-000,4 as well as Louisiana Public Service Commission (“LPSC”) Docket No. U-28155 and Arkansas Public Service Commission (“APSC”) Docket No. 04-050-U.

On October 1, 2007, Entergy filed a status report in Docket No. ER05-1065 explaining the progress made in developing software to provide compensation to a party that has funded a Supplemental Upgrade when the capacity of that upgrade subsequently is used to provide short-term point-to-point transmission service. On October 2, 2007, the ICT filed its 3rd Quarterly Performance Report for the period of June 1, 2007 to August 31, 2007. On November 16, 2007, the Lafayette Utilities System filed comments in response to the ICT’s 3rd quarterly performance report, requesting a technical conference to examine whether the ICT has the appropriate level of personnel and expertise to perform its important functions. Entergy has requested that FERC deny the parties’ request for a technical conference in this proceeding. In the event that a technical conference is convened, Entergy requests that FERC focus on the ICT’s role and authority. Occidental Chemical Corporation also filed limited comments relaying its continued concern over the increased occurrence of Transmission Loading Relief events.

L. SPP EHV Overlay Assessment

SPP staff continues to work with Quanta Technology on model development and scenarios for a restudy of the EHV Overlay Plan. The base case and future scenarios are consistent with the feedback received as a result of an extensive survey from SPP stakeholders in late 2007. SPP staff has been working with the Transmission Working Group and other groups to create a conceptual long-range action plan with major initiatives such as seams agreements and cost allocations which will be required to implement an EHV Overlay in the next 5 – 20 years. SPP hopes to finalize model development in mid-January and complete the identification of potential EHV Overlay alternatives in February. Subsequent economic analyses will be performed in March to compare alternative plans. Staff will continue to work with stakeholders and share results as they become available through the first quarter of 2008. This SPP EHV Overlay Restudy will be integrated with an unprecedented Joint Coordinated System Plan which is being sponsored by MISO, PJM, SPP and TVA and others to evaluate reliability needs in 2018, as well as economic opportunities in 2024.

4 FERC Docket No. ER05-1065 replaced Entergy’s Initial ICT Proposal in Docket No. ER04-699, which closed June 30, 2005.

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M. Cost Allocation for Economic Upgrades The Regional State Committee’s Cost Allocation Working Group continues to move forward with the strategic initiative to “develop and implement a methodology to provide for the recovery of the cost of an approved level of economic upgrades.” Two initiatives are underway. First efforts continue to develop a Balanced Portfolio of Economic Upgrades while, separately, the CAWG is addressing policy questions associated with cost allocation for economic upgrades in a draft "Concepts Paper on Economic Upgrades." The Concepts paper is expected to be initially reviewed by the RSC in January 2008 and the CAWG should have their first look at draft economic project portfolios in January as well.

N. Arkansas Regulatory Proceedings 1. Docket No. 06-154-U: SWEPCO Turk Coal Plant CECPN Approval

On November 21, 2007, the APSC issued Order No. 11 granting SWEPCO’s CECPN for the Turk Plant, subject to the conditions ordered at pages 73 thru 76 of the 113-page order.

At ordering paragraph No. 2 the APSC directed that,

Subsequent Commission docket matters relating to the Turk plants transmission line corridor shall be filed with the Commission only after independent review and input is provided by the SPP in order to assure that the transmission lines not only move the power from Turk but improve congestion in the area. SPP shall participate in subsequent transmission line docket matters related to the Turk plant. (Emphasis added)

On December 12, 2007, SWEPCO filed a motion for clarification and acceptance of conditions in Order No. 11. On December 20, 2007, Hempstead County Hunting Club, Inc., P-Bo Land Company, Inc., Yellow Creek Corporation, Schultz Family Management Company and Emon A. Mahony collectively filed an application for rehearing of APSC Order No. 11. The APSC ruled on these motions December 31, 2007 with the issuance of Order No. 13. The APSC clarified portions of Order No. 11; amended Condition Nos. 1, 2 and 11; and retained jurisdiction and regulatory oversight compliance over all terms and conditions of Order No. 11. Condition No. 2, as amended, now directs that:

Subsequent Commission docket matters relating to the Turk plant’s transmission line corridors shall be filed with the Commission only after independent review and input is provided by the SPP in order to assure that the transmission lines not only move the power from Turk but improve congestion in the area. SPP shall participate in subsequent transmission line docket matters related to the Turk plant. Further, SWEPCO shall provide proper notice to Intervenors of subsequent

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Commission docket matters relating to the Turk plant’s transmission line corridors.

The Intervenors’ petition for rehearing of Order No. 11 was otherwise denied. SPP is not a party to this proceeding.

2. Docket No. 06-172-U: SWEPCO CCN Application, Fayetteville

On October 4, 2007, the APSC issued Order No. 6 granting SWEPCO’s CCN application to rebuild and convert its existing 69 kV transmission line in Washington County to 161 kV between SWEPCO’s Fayetteville and North Fayetteville substations. The APSC also granted a variance zone to accommodate the concerns and objections of Neal and Gina Pendergraft, the Ross Pendergraft Trust and the University of Arkansas.

The APSC has directed that SWEPCO file a construction report in this docket. On December 6, 2007, the APSC issued Order No. 7 authorizing and directing the closure of this docket.

3. Docket No. 07-101-R: Proposed Rulemaking to Implement Act 647 of 2007 regarding

the Retention of Contract Attorneys & Consultants by the Arkansas Public Service Commission On September 26, 2007, the APSC issued Order No. 3 adopting the rules proposed in attachment 1 to the Joint Motion of the parties filed on September 19, 2007 to be incorporated in the Commission’s rules as section 8 of the Commission’s Special Rules – Electric. The APSC directed Entergy Arkansas, Inc. and SWEPCO to file their Federal Litigation Consultant Fee Rider Tariffs in separate dockets with the Commission by October 26, 2007 and to submit annual filings in those dockets as necessary.

APSC staff is to fulfill the requirements of Ark. Code Ann. § 25-15-204(d)(1) and Ark. Code Ann. § 10-3-309 on behalf of the Commission and to submit its compliance filings in this docket. APSC staff has filed a certified copy of the rule, as amended by APSC Order No. 3, with the Secretary of State Bureau of Legislative Research and Arkansas State Library Document Services in order to implement Act 647 of 2007. The APSC issued Order No. 4 on November 14, 2007, authorizing and directing that this docket be closed.

O. Kansas Regulatory Proceeding

Docket No. 08-KMOE-028-COC: KAMO’s Application for a Certificate of Public Convenience

On October 5, 2007 KAMO filed a petition for reconsideration of the Kansas Corporation Commission’s (“KCC”) September 21, 2007 Order, wherein the KCC found that, “AECI is

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a Kansas public utility for purposes of the proposed transmission project, it must apply for certification as such by the Commission, and is a necessary and indispensable party to this proceeding.” At P 27. KAMO’s petition for reconsideration was denied by the KCC on November 5, 2007. AECI was directed to join this action and amend the Application in this proceeding within 30 days from the date of service of this order or this docket would be dismissed for failure to join all necessary and indispensable parties. AECI amended the Application on November 26, 2007. On December 10, 2007, the parties and KCC staff met for a prehearing conference at the KCC in Topeka, Kansas. AECI is to begin preparing testimony to support the “public interest” standard required as part of their application. KCC staff also requested that AECI provide an analysis of the benefits of joining SPP versus how AECI could address the concerns of KCC staff without joining SPP. A joint motion for an order establishing issues and a procedural schedule was issued on December 21, 2007. An evidentiary hearing has been proposed for March 11 and 12, 2008.

P. Louisiana Regulatory Proceedings 1. Docket No. R-26172, Subdocket C: Possible Suspension of, or Amendments to, the

Louisiana Public Service Commission’s Market Based Mechanism Order to Make the Process More Efficient and to Consider Allowing the Use of On-line Auctions for Competitive Procurement Comments on whether to abolish the Market Based Mechanism Order have been filed, with responses to staff’s questions also being filed by Cleco on November 27, 2007. On January 2, 2008, Louisiana Public Service Commission (“LPSC”) staff issued notice of a second proposed rule.

2. Docket Nos. U-27866, Subdocket B & U-29702: SWEPCO’s Application for Certification

of Contracts for the Purchase of Capacity and to Purchase, Operate, Own and Install Peaking, Intermediate and Baseload Generating Facilities

On February 14, 2007, SWEPCO filed an application with the LPSC in Docket No. U-29702 for certification of the proposed Turk Coal Plant. A certification hearing was held on September 11, 2007.

LPSC staff supports approving the application with multiple conditions, including that the plant is approved by both Arkansas and Texas Commissions. Both SWEPCO and LPSC staff have filed post hearing briefs in the case and are awaiting an order.

LPSC Docket No. U-27866, Subdocket C, SWEPCO’s application for the certification for purchase of capacity, was consolidated with Docket No. U-29702 on October 16, 2006.

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Q. Missouri Regulatory and Circuit Court Proceedings 1. Docket No. EO-2008-0046: Aquila’s Application to Transfer Operational Control of

Certain Transmission Assets to MISO A prehearing conference was held in Jefferson City, Missouri on October 15, 2007, with a procedural schedule adopted by order on October 30, 2007. Direct and rebuttal testimony has been filed by the parties in this docket. Rebuttal testimony for non-Aquila parties was due November 30, 2007. However, on December 28, 2007, MISO filed Supplemental Rebuttal testimony based on supplemental or additional studies conducted by MISO or on their behalf which have not been submitted into evidence in the docket. Parties have objected to the introduction of the testimony and raised concerns about the studies referenced in the testimony and requested either exclusion of the testimony or a delay in the procedural schedule to allow the parties to conduct additional discovery and to develop or revise their positions in the docket based upon this information. Surrebutal and cross-surrebuttal testimony is currently due January 18. 2008.

2. Docket No. EO-2008-0134: AmerenUE’s Application to Transfer Functional Control of

its Transmission System to MISO

On November 1, 2007, AmerenUE filed an application with the Missouri Public Service Commission (“MoPSC”) to continue the transfer of functional control of its transmission system to MISO through April 30, 2012. Applications for leave to intervene have been filed by MISO, Missouri Industrial Energy Consumers, Aquila, SPP, and Kansas City Power & Light Company. On December 17, 2007, AmerenUE filed a motion to temporarily abate or delay the docket until at least June of this year. That request was based on a MISO TO tariff filing made at FERC that would recalculate revenue distribution. AmerenUE’s position is that this new calculation method could decrease AmerenUE’s incremental revenues by approximately $60 Million annually. All parties, with the exception of MISO, either agreed with the request to delay or had no objection to it. MISO requested a status report be provided by AmerenUE in February (60 days after MISO TO filing) to allow the Commission to determine whether the docket should be delayed past that point in time. No ruling on the Motions has been issued.

3. Circuit Court of Greene County, Missouri Case No. 105CC4503: Associated Electric Cooperative, Inc. v. American Electric Power Company; Board of Public Utilities of Springfield, Missouri; Empire District Electric Company & Grand River Dam Authority

This case has been settled and removed from the bench trial docket; a bench trial had been set for January 3, 4, and 7, 2008.

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R. New Mexico Regulatory Proceeding

Case No. 07-00390-UT: An Investigation into the Prudence of Southwestern Public Service Company’s Participation in the SPP RTO

On October 11, 2007, the New Mexico Public Regulation Commission (“NMPRC”) issued a final order granting SPS a certificate of public convenience and necessity and siting approval to construct and operate certain transmission and associated facilities. As a result of arguments raised in that hearing, the NMPRC determined that the prudence of SPS’ participation in the SPP RTO should be examined in a future proceeding.

Accordingly, on October 16, 2007, the NMPRC issued an order docketing investigation into the prudence and reasonableness of SPS’ participation in the SPP RTO.

SPS must file direct testimony no later than 75 days after the completion of the hearing in Case No. 07-00319-UT in accordance with the NMPRC’s mandate that, “SPS and Staff should provide the Commission, from the New Mexico consumers’ perspective, a cost/benefit analysis of SPS’s participation in the SPP that demonstrates, among other matters, a quantification of any reduction or increase in SPS’s administrative and general and other costs as the result of its participation in the SPP, the impact, if any, on SPS’s purchased power and fuel costs and reliability of service, and the impact of that participation on the Commission’s ability to protect the interests of New Mexico consumers under the Public Utility Act.” At P 3. The hearing in Case No. 07-00319-UT is scheduled to begin April 9, 2008 and may extend through April 23, 2008.

S. Texas Regulatory Proceedings 1. Docket No. 33672: Proceeding to Designate CREZs

On October 2, 2007 and November 6, 2007, the Public Utility Commission of Texas (“PUCT”) issued interim orders designating zones 2A, 4, 5, 6, 9A and 19, as described in Figure 3 of the ERCOT Study and the Interim Orders, as CREZs and directing ERCOT to file results of a CREZ Transmission Optimization Study by April 2, 2008. Major transmission improvements necessary to deliver to customers the energy generated by renewable energy resources in the CREZ will be identified in a final order. ERCOT advised the PUCT by letter dated November 12, 2007 of proposed solutions of input, assumption and procedure issues and requested guidance on alternative resolutions regarding the CREZ Transmission Optimization Study process.

2. Docket No. 33687: EGSI’s Transition to Competition Plan

On October 24, 2007, the PUCT issued an order abating this docket and ordering Entergy Gulf States, Inc. (“EGSI”) to request that SPP conduct an analysis similar to the Phase II Entergy Integration Report completed by ERCOT in 2006 and filed by EGSI as part of its TTC Plan. No specific timelines were provided.

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On November 7, 2007, SPP filed a motion for clarification of the PUCT’s October 24, 2007 Order requesting that the PUCT clarify that EGSI should compensate SPP for the costs of performing the study. SPP also provided an overview of SPP’s proposed work plan and a proposed timeline for study completion.

On November 13, 2007, ETC filed a response to SPP’s Motion for Clarification. ETC has requested that the PUCT issue an order directing the undertaking and publication of three independent studies to assess the ERCOT, SPP and “No Action” options and using a uniform, open process for all stakeholders/intervenors.

The PUCT issued a two-paragraph Order Clarifying Order Abating Docket on November 28, 2007, requiring EGSI to provide an updated cost-benefit analysis of EGSI’s remaining in the Southeastern Electric Reliability Council power region, approving SPP’s study work plan, and directing that EGSI pay SPP’s costs for completing the study.

3. Docket No. 33891: SWEPCO Turk Plant CCN Proceeding

On February 20, 2007, SWEPCO filed a petition with the PUCT seeking Certificate of Convenience and Necessity authorization for the proposed 600 MW Turk Coal Plant. A hearing on the merits was held October 17, 2007 at the State Office of Administrative Hearings in Austin, Texas.

Briefs have been filed, and the parties are currently awaiting a proposal for decision.

The PUCT staff and the Texas Industrial Energy Consumers have voiced their opposition to SWEPCO’s application, whereas the East Texas Electric Cooperatives and Rayburn Country Electric Cooperative have each filed amicus briefs in support of CCN approval.

On November 21, 2007, the APSC granted SWEPCO CECPN approval for the Turk Coal Plant in Docket No. 06-154-U.

4. Docket No. 34442: Complaint of JD Wind against SPS

A prehearing conference was held October 1, 2007 in Austin, Texas, and on October 5, 2007, the PUCT issued Order No. 4 abating this case and scheduling a second prehearing conference for January 23, 2008.

SPP is not an active participant in this docket.

5. Docket No. 34467: Complaint against EGSI for Violation of PUCT Procedural Rules

As a result of the abatement of Texas Docket No. 33687, the PUCT issued Order No. 1 on November 15, 2007, requesting comments on whether the PUCT should proceed with establishing a procedural schedule for this docket or establish a procedural schedule at some later date (i.e. after a final order in Docket No. 33687).

Responses to Order No. 1 were filed by EGSI, ETC and Texas Electric Cooperative, Inc., each supporting the establishment of a procedural schedule at some later date.

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6. Project No. 34560: Rulemaking Proceeding to Amend PUC Substantive Rules Relating to the Selection of Transmission Service Providers related to CREZs & Other Special Projects PUCT staff’s recommended proposal for publication of new § 25.216, related to the selection of transmission service providers, was considered at the December 7, 2007 Open Meeting. PUCT action is forthcoming. SPP is not an active participant in this project.

7. Project No. 34557: Proceeding to Establish Policy relating to Excess Development in

Competitive Renewable Energy Zones

A second workshop on dispatch priority options for excess wind resources in the ERCOT market was held November 8, 2007, and several comments have been filed.

SPP has not actively participated in this proceeding.

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REGULATORY OUTLOOK

2008 Missouri EO-2008-0046

Surrebuttal & cross-surrebuttal testimony due for all parties per the MoPSC’s October 30, 2007 Procedural Order

Jan. 18, 2008

Texas 34442

Second Prehearing Conference in accordance with PUCT Order No. 4 (Williams Clements Building, Austin, Texas)

Jan. 23, 2008

FERC ER07-1069

Settlement conference in accordance with FERC’s December 5, 2007 Order (FERC, Washington D.C.)

Jan. 29, 2008

FERC ER06-451

Deadline for SPP informational filing analyzing the effects of its calibration method and the TDU Intervenors’ proposal to become part of a consolidated settlement location with the host control area, as required by FERC’s March 20, 2006 Order at P 117. SPP must also incorporate into this filing an analysis of whether the state estimator captures constraints affecting LSEs in a manner comparable with the way it captures constraints affecting larger control-area operators in compliance with FERC’s Sept. 26, 2006 Order at P 70.

Feb. 1, 2008

FERC ER06-729

Deadline for SPP filing detailing the neutrality uplift payments associated with losses for into and within transactions & through & out transactions, as required by FERC’s October 19, 2006 Order

Feb. 1, 2008

FERC ER06-451, et al.

Deadline for SPP submission of a report to FERC on ways of incorporating demand response into the SPP EIS Market

Feb. 1, 2008

Missouri EO-2008-0046

Prehearing Conference, per the MoPSC’s October 30, 2007 Procedural Order

Feb. 4, 2008


Deadline for filing of Joint Stipulation of Facts, List of Issues, Order of Witnesses & Order of Cross-Examination Due, in accordance with the MoPSC’s October 30, 2007 Procedural Order

Feb. 8, 2008


Deadline for filing of Statements of Position, Exhibit Lists & Objections to Prefiled Testimony, per the MoPSC’s October 30, 2007 Procedural Order

Feb. 15, 2008

FERC RR06-1

Deadline for NERC filing in compliance with FERC’s June 7, 2007 Order to develop and file violation severity levels for each requirement of each reliability standard

Mar. 1, 2008


Evidentiary Hearing, per the MoPSC’s October 30, 2007 Procedural Order (Governor Office Building, Jefferson City, Missouri)

Mar. 3-5, 2008

Texas 33672

Deadline for ERCOT filing of CREZ Transmission Optimization Study results, as required by the PUCT’s October 2, 2007 Interim Order

April 2, 2008

FERC ER06-451

Deadline for SPP submission of a report re-assessing the feasibility, cost, & benefits of any control area consolidation following its first year of imbalance market operation in compliance with FERC’s October 31, 2006 Order

May 1, 2008

FERC RM05-17 RM05-25

Deadline for public utilities, working through NERC, to modify the reliability standards related to the calculation of ATC in compliance with Order Nos. 890 and 693, pursuant to FERC’s December 6, 2007 Notice of Extension of Time

May 9, 2008

FERC ES06-51

Expiration of SPP’s authorization to issue senior secured notes, per FERC’s July 20, 2006 Letter Order

July 20, 2008

FERC RM05-17

Deadline for public utilities, working through NERC, to develop business practices that complement NERC’s new reliability standards, per FERC’s

Aug. 7, 2008

23

24

RM05-25 December 6, 2007 Notice of Extension of Time 2009

FERC ES07-40

Expiration of SPP’s authorization to issue $50,000,000 in non-secured promissory notes, per FERC’s August 15, 2007 Order

Aug. 15, 2009

ISO/RTO Council Whitepaper on Interconnection Queue Management

Process

1 EXECUTIVE SUMMARY Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”) have made significant progress in implementing Congress’ goal of open and competitive wholesale markets in the two-thirds of United States within their footprint. Building on the framework established by the Federal Energy Regulatory Commission (“FERC” or “Commission”) in Orders Nos. 888 and 2000, ISOs and RTOs have largely achieved the goal of ensuring nondiscriminatory interconnection of new generation in accordance with the procedures established in Order No. 2003 and facilitated the interconnection of over 108,0001 MW of new generation resources across the country from 2001 to 2006. As has been recognized by key market participants, the development and administration of new market structures and programs in organized markets coupled with the evolution of public policy encouraging renewable resources have also significantly encouraged the development of new resources.2 The success of ISOs and RTOs in attracting investment in new generation has not been free of challenges. The vast number of new interconnection projects proposed to interconnect within ISO and RTO regions has given rise to certain challenges in the management of the queue process that may not have been evident at the time of the implementation of Order No. 2003. These added complexities, arising out of some of the policy decisions made in Order No. 2003 may inadvertently be contributing to commercial uncertainty for interconnection customers with requests in the queue and thus frustrating the very goals of Order No. 2003. Recognizing the existence of various challenges to the queue management process, the Commission held a technical conference to identify concerns relating to the queue management process and explore possible solutions in both ISO/RTO and non ISO/RTO regions. The ISO/RTO Council (the “IRC”) commends the Commission for initiating and promoting discussions regarding the interconnection queue process. The IRC believes that this generic review of the issues created by large numbers of generation projects in interconnection queues is a worthwhile endeavor and should lead

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1 Source: IRC document, "Progress of Organized Wholesale Electricity Markets in North America, A Summary of 2006 Market Data from 10 ISOs & RTOs" published in October 2007, Table 3. Excludes Canadian entities. 2 See, for example, letter from American Wind Energy Association et al. to Chairman Kelliher et al. February 26, 2007 (copy attached)

to improvements in the function of interconnection queues. The IRC appreciates the opportunity to provide these comments on the generation interconnection process, the challenges experienced by its members and the ongoing efforts to identify and implement effective solutions. As heard from the various ISO and RTO representatives at the Commission’s December 11, 2007 Technical Conference on Interconnection Queuing Practices (“Technical Conference”), there are significant regional differences in the management and administration of the interconnection queue processes, the makeup of the queues, and the potential solutions being considered to address the associated challenges. Although there are regional differences relating to the interconnection queue process, based on the ongoing dialogue among ISOs and RTOs and the comments presented at the Technical Conference, the IRC has identified some common challenges experienced by ISOs and RTOs as well as some potential solutions that warrant further discussion and review in individual RTO/ISO stakeholder processes. In this Whitepaper, the IRC addresses the common challenges experienced by ISOs and RTOs relating to the queue management process and identifies some of the potential solutions that are being evaluated to address these challenges. In particular, Section 3 of this Whitepaper identifies the common challenges or concerns with the interconnection queue process, particularly given the significant numbers of generation interconnection requests that are presently pending in the respective queues of the RTOs/ISOs. For instance, the current process does not account for the simultaneous processing of a large number of interconnection requests or the different level of complexity associated with different types of interconnection projects, system topology or transmission capability margins. In addition, the current process does not necessarily account for the time that it takes to process a complex interconnection request or the completion of associated studies, or the significant hurdles introduced to the management of the queue by restudies that may be warranted due to the entry or exist of existing and/or new projects in the queue.3 Next, Section 4 of the Whitepaper identifies some of the ideas that are being explored by stakeholders at large to address the concerns with the interconnection queue process. The fundamental objective of the solutions being explored is a process that results in interconnection study outcomes that are realistic and lead to a more efficient usage of interconnection resources that match a broad range of policy needs such as the Renewable Portfolio Standards adopted in certain states in the Northeast, Midwest and West regions, and the development and administration of new market structures such as the Forward Capacity Market (“FCM) recently implemented in New England and the Reliability Pricing Model (“RPM”) recently implemented in PJM.

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3 Although the IRC recognizes that successfully interconnecting generation, particularly in a situation with reduced transmission capacity “headroom”, is closely tied with the issue of the appropriate method for allocating costs of new transmission upgrades, this paper focuses primarily on administrative changes to queue processing. Further discussion of the more generic issues associated with cost allocation is deferred for purposes of this analysis until the administrative and policy solutions outlined herein (and others under consideration) undergo further development.

As presented at the Technical Conference, it is important to recognize that ISOs and RTOs have been engaged in extensive stakeholder processes to identify the challenges presented by the interconnection queue process in light of the specific policies and/or market developments impacting their specific region. As a result, ISOs and RTOs are, on an individual basis, exploring with their stakeholders potential solutions that will be proposed to the Commission in various region-specific filings beginning in 2008. Given these ongoing efforts and the impending filings, the IRC respectfully requests that the Commission allow these regional efforts to come to fruition in lieu of the issuance of a generic rulemaking on interconnection queue process reforms at this time. The IRC recognizes that some potential solutions, such as alternative milestones, may raise interface issues if applied within some regions and not others. The IRC will continue discussion as the ISOs and RTOs complete the stakeholder processes to identify and resolve such issues, where possible, and inform the Commission of any resolution.

2 Background

Historical Underpinnings The Commission’s Order No. 2003 came about to ensure that the requirement of open access transmission service established in Order No. 888 was maintained since Order No. 888 did not directly address generator interconnection issues. The three main objectives of FERC Order No. 2003 were:

• Limit opportunities for transmission providers to favor their own generation • Facilitate market entry for generator competitors by reducing interconnection

costs and time • Encourage needed investment in generator and transmission infrastructure

While Order No. 2003 has been successful in increasing open access, secondary impacts on queue processing have occurred partly due to changes in the electric industry as a whole, the overall increase in the number of projects entering the queue and the high “drop out” rate of projects that are in the queue. It should be noted at the outset that although much of the focus of discussion of this issue to date has centered on the experiences of wind and other renewable generation, the issues associated with queue processing are not limited to renewable generation. In the past, other policies drove the entry of non-renewable generators into the queue, and the IRC expects that there will be alternate policy and market drivers in the future. As a result, it is imperative that the Commission examine its Order No. 2003 requirements holistically rather than solely focusing on one form of generation entering the queue.

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Changes in the Profile and Magnitude of New Generation Projects Since the Issuance of Order No. 2003 The design of the current queue process was based on the assumption that unused transmission capacity was readily available. However, since Order No. 2003 went into effect, the location and type of generating units entering the queue has been affected by changes in fuel price projections, the development of larger markets for the sale of the output of generation and the regulatory environment including siting and environmental issues. Additionally, there has been evolution in both public policy and market structures that have changed both the makeup of the queue and the timeframe needed to evaluate and sort through the complexity of those projects. Among these policy changes are environmental regulations and related programs that are changing the type and location of new generating units. For example, a number of states have enacted renewable portfolio standards or have policies that promote renewables without the force of law. These policies, combined with increasing economies of scale in terms of production costs, favorable tax treatments and other financial incentives, and advancements in wind technology have caused significant increases in requests for wind projects, particularly in the Midwest ISO, SPP, and the CAISO. It is worth noting that the amount of wind generation in the queue far exceeds the statutory requirements and the operational capabilities of the grid. Other regions have seen increases due to other state legislation such as the Global Warming Solutions Act in California, and the anticipation that “once-through“ cooling restrictions on power plants in the west could accelerate generation retirements. All of these actions along with the opportunities that the organized markets provide for renewable generation have and continue to drive an overwhelming increase in new generation interconnection requests.

The Magnitude of Each ISO/RTOs Queue

ISO-New England ISO New England has seen a significant increase in the number of interconnection requests partly due to various state sponsored solicitation programs, Renewable Portfolio standards, and the implementation of a Forward Capacity Market (FCM) with the first auction occurring in February 2008. In New England, the new FCM and various state sponsored solicitations for new capacity have encouraged the development of new resources, which has led to an increase in the number of generation projects requesting interconnection. As of December 11, 2007 ISO New England was processing 95 interconnection requests, totaling approximately 12,600 MW, an amount which greatly exceeds anticipated requirements. The mix of generator types requesting interconnection in the ISO New England footprint is: 53.7% Natural Gas/Oil, 23.5% Natural Gas, 18.3% Wind & Other Renewables, 3.7% Oil, 0.6% Nuclear, and 0.2% Coal.

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30

80

123

14

5645

90

131

191

4435 32

173 173

25

49 53

0

50

100

150

200

250

2005 2006 2007 2005 2006 2007 2005 2006 2007 2005 2006 2007 2005 2006 2007 2005 2006 2007

CAISO ISONE MISO NYISO PJM SPP

Coal Natural Gas Nuclear other Other Renewables Wind

136

Figure 1: Number of Interconnection Requests by Fuel Type for 2005- December 1, 2007

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7,488

1,016

12,093

5,932

16,972

3,944

22,797

6,788

23,501

6,057

38,832

15,180

38,276

4,942

50,513

6,807

37,809

12,427

0

10,000

20,000

30,000

40,000

50,000

60,000


MW

2005 2006 2007 Figure 2: Annual MW of Interconnection Requests for 2005- through December 1, 2007

Midwest ISO In the Midwest ISO, as in the other ISO/RTO regions, the amount of generation that has been entered into the queue far exceeds the estimated current requirements. With 191 requests received through November 2007, the Midwest ISO is on track for a 62% increase in requests over 2006, which itself was a 44% increase over 2005. There is approximately 73,000 MW worth of active projects in the queue, over 57,000 MW of which is wind; however, the necessary amount of renewable generation to meet the current renewable mandate statues in the Midwest ISO footprint is only 12,600 MW. Additionally, the requests total more than half of the peak demand for the footprint.

SPP SPP is experiencing similar increases in the amount of projects requesting interconnection. From 2003 through 2005, SPP received 24 requests for interconnection each year. In 2006, the number of requests more than doubled to 49 and through the first 11 months of 2007, the number of requests has been 53. Currently, SPP has 76 interconnection requests in its queue with 67 of those consisting of wind projects. The current peak load for the SPP footprint is approximately 43,500

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MW and the amount of wind with Interconnection Agreements and under study exceeds the minimum load requirements of the footprint.

PJM PJM has also seen an increase in requests driven at least in part by the implementation of its Reliability Pricing Model (RPM) capacity market. For PJM, the number of interconnection requests in its biannual study groups has increased by 120%. For example the four interconnection queues during the two-year period ending January 2005 included 35, 28, 31, and 52 requests, respectively. However, the next four interconnection queues comprising the two year period ending January 2007, included 76, 64, 92 and 88 requests. This significant increase in the number of queue requests has made it increasingly difficult to process interconnection studies in a timely manner.

California ISO

1/10/2008

The CAISO currently has 173 active interconnection requests representing 57,686 MW. Of this active total, 118 of the interconnection requests and approximately 40,000 MW of capacity are renewable resources. The capacity in the queue associated with these renewable resources has grown quickly from 5,700 MW as of January 2006 to 11,000 MW in January 2007 to the approximately 40,000 MW as of November 2007. To put this into proper perspective, the CAISO historic peak demand experienced during the heat wave in the summer of 2006 was 50,270 MW.

NYISO The NYISO experienced an initial influx of new wind interconnection requests shortly following the State’s adoption of an RPS requirement in 2004. At present there is approximately 400MW of wind generation in commercial operation in New York and there remains over 7,000MW of wind projects in the NYISO’s interconnection queue. Renewable resources, primarily wind, now account for nearly two-thirds of these projects.

3 Challenges Resulting from Current Generation Interconnection Queue Pro Forma Policies and Processes

3.1 Proliferation of Generator Interconnection Requests due to Inadequate Screening Mechanisms

Page 7

The current Order No. 2003 pro forma requirements to enter the queue process are very low both from a monetary and a data perspective. The structure of the current process puts value in obtaining and maintaining a queue position, rather than focusing on the viability of a particular project. The importance of queue position in the interconnection process, combined with the relatively low cost of commencing the process, leads to a high number of projects entering the queue, even though the likelihood of the projects ever entering service may be very low. Many of these projects may not have a buyer or financing, any realistic prospect of actual site control, or the ability to timely obtain the equipment necessary to enter service when stated. As the number of interconnection requests continues to increase, projects enter the queue to “hold their place” in line before the list gets longer, which only leads to an even longer list of projects that may never come to fruition. Additionally, the minimal threshold requirements inherent in the current generator interconnection queue process create incentives for developers to put in multiple requests for the same project. For example, there have been examples of wind developers “bundling” phased projects into a single large project in order to maintain a queue position, even though the project will actually be built in discrete phases. The RTO/ISOs have also seen developers of all types entering multiple requests for a project to determine the least cost interconnection request (i.e. “upgrade shopping”). The ISO/RTO essentially then becomes a low cost consultant to the project, screening various possible site alternatives for the developer rather than studying the impact of a site and project which has already been vetted and chosen by the developer. In yet another example of upgrade shopping, there have been instances of developers placing requests for the same project in two different Transmission Providers’ queues. The current Order No. 2003 pro forma requirement to treat these interconnection requests consecutively or in clusters may not necessarily account for programs for competitive solicitations for generation. By design, a competitive solicitation program selects only a limited number of generators, potentially much smaller than the total amount of interest. However, the interconnection queue will reflect interconnection requests for generators that are actually competing against each other in a competitive solicitation program and do not intend to complete their interconnection program unless selected. This is driven, in part, by the fact that developers need to have some idea of their potential interconnection costs in order to prepare bids to enter into such competitive solicitations. The additional requests add difficulty to the management of the interconnection queue, particularly in the performance of complicated system design studies to address cumulative impacts that will not materialize. This can be especially problematic for large concentrations of generators in relatively small geographic areas. In general, when the queue is made-up of a large number of projects that lack commercial viability, it leads to delays and uncertainty in the entire process. While the analysis for a single project, or even one project with two points of interconnection, is not difficult, multiple sets of results generated from studying, then restudying as projects exit the queue, can present significant uncertainty for subsequently queued projects as

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their results become dependent on more and more decisions to be made by earlier queued projects. Exiting the queue is even easier than entering it. The flexibility offered to developers to exit the queue negatively impacts the balance between an expeditious answer and a certain answer. Each time a project drops out of the queue after either the System Impact Study or Facilities Study all projects that were lower than that project in the queue have to be restudied due to the change in the system model used for the studies. For example, with five requests ahead of a project in queue, there are 32 possible scenarios that the sixth request faces_ (i.e. scenarios with all combinations of excluded and included requests ahead of it in the queue). There is not an objective way to delineate the most likely scenario. Therefore, given the Order No. 2003 pro forma rights a queue position has, the ISO/RTO is required to study the scenario with all the generation. These studies typically result in a conservative answer from a transmission standpoint, and a discouraging answer from a developer standpoint. Moreover, the constant need for restudies adds significant amounts of time required to complete a study and creates an additional need for resources to perform the studies. It also leads to uncertainty for all remaining projects which are either awaiting their study analysis or have their study analysis completed, but need to revise their upgrade requirements because the higher queue project has withdrawn. A request does not get a “final” answer until literally all requests ahead of it in queue either achieve commercial operation or withdraw. This is unmanageable commercial risk for a developer, and unnecessary complication for the RTO/ISO. .

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28.5%

43.1%44.3%

39.8%

27.6%

42.3%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%


Figure 3: Project Withdrawal Rates Suspensions compound this problem even further. With no cost required to suspend one’s place in the queue, nor the requirement to provide any reason for the suspension, some ISOs and RTOs have seen an increase in project suspensions following completion of the interconnection agreement negotiations. Such suspensions cause additional work and increased uncertainty for lower queued projects. Specifically, the ability to put an interconnection request in suspension ties up transmission capacity, increases cost uncertainty for later entrants who must pay the upgrade costs on which they are dependent should the earlier project not proceed, and increases the amount of restudy necessary if the project does not go forward after suspension. For every one project that is suspended, there are at least two studies that need to be completed for each subsequent project —one study with the suspended project and one study without it.

3.2 Tightening Transmission Capacity Increases Study Complexity The challenges caused by high levels of generator interconnection requests are exacerbated by the fact that the “headroom” in existing transmission systems is, in many locations, rapidly diminishing. The need for new transmission infrastructure to create additional capability, and the siting of same, has not “caught up” with the number

1/10/2008 Page 10

of new projects entering the queue, causing more and more costly and complex transmission upgrades to be reviewed, studied and restudied as different projects enter and exit the queue. This is particularly true when proposed generation facilities are clustered in areas that are relatively close electrically. 4 The lack of transmission capability is also a concern with the implementation of renewable generation. For instance, wind generation is typically located in remote areas without significant local load. Additionally, certain states that have adopted renewable portfolio standards that will rely on projects located outside of their state boundaries. In each of these instances, significant transmission infrastructure is required to accommodate energy deliveries from generation facilities whether clustered in close electrical areas or remotely located. The lack of transmission capacity to support many interconnection projects means that even seemingly simple requests may be viewed as complex due to the need for large scale upgrades to accommodate a project, particularly those proposed in a heavily constrained area. Projects requiring tens or hundreds of millions of dollars in network upgrades necessarily take a long time to fully evaluate. These upgrades must also be factored into the analysis for subsequent projects in the queue, many of which are impacted by these upgrades. Project complexity in general, whether tied to the lack of transmission capacity, the bundling of small projects into one as noted above, or the advent of site shopping through placing multiple requests in the queue, all lead to timelines which may exceed the current Order No. 2003 pro forma tariff timelines. For example, in the state of Illinois there are 20,000 MW of wind projects awaiting interconnection. The difficulty with these projects is not the particular fuel source or type of project, but the complexity of the projects and their impact on the queuing process. The transmission upgrades that will be required to integrate projects of this size into the system will be significant, likely involving multiple backbone transmission lines. Projects of this size will take much longer to study than allowed by the Tariff to complete and the required upgrades will have an impact on subsequent projects causing a domino effect of delays through the interconnection queue. Another example is the Buffalo Ridge Area in Southwestern Minnesota, Northwestern Iowa and Eastern South Dakota. There are nearly 22,000 MW of wind generation requests for interconnection in that area by 2014 in the Midwest ISO queue, with only 1900 MW of outlet capacity planned for the region by that same date. Like the Illinois example, backbone transmission lines will be part of the solution to allow this generation to interconnect. Processing these requests in a sequential fashion would lead to sub-optimal solutions and high cost hurdles for the first-mover in the queue. However, a simple group study, which does not take into account demand for the energy, has its own complications as many of these projects are expected to drop out of the queue at some point in the process; that will result in restudy to identify alternate backbone solutions to support the lower amount of generation.

1/10/2008 Page 11

4 For example, over 40% of ISO New England’s interconnection queue is comprised of projects within the State of Connecticut.

3.3 The Sheer Number of Interconnection Requests Strains Technical Resources

The sheer volume of interconnection requests strains existing ISO/RTO resources from both an administrative and technical prospective. All ISO/RTOs have needed to hire additional staff members to keep up with the increase in requests. Consultants, who are often used to supplement ISO/RTO staff efforts, are not bidding to perform interconnection studies. This is likely due to the same difficulty experienced by the ISOs and RTOs in obtaining experienced, qualified personnel to undertake these studies in a timely manner. The lack of experienced staff exacerbates the problems faced by the ISO/RTOs – the complexity of analysis that results from the number of projects and the lack of existing transmission capability to deliver new generation to load.

3.4 The Current Pro Forma Tariff Language Is Unclear and Inflexible to Address Treatment of Certain Recurring Complexities

In the current pro forma tariff, the procedures specified for the generation interconnection queue process lack enough flexibility to address some of the issues faced by ISO/RTOs. First, the prescribed process and timelines do not account for differences in the types of interconnection projects. Second, the process and timelines do not account for differences in system topology or capability margins. Finally, the process and timelines do not account for the large number of requests submitted. These issues prevent ISO/RTOs from meeting tariff set deadlines, reduce customer satisfaction in the overall study process, and increase the number of requests in the queue which are unlikely to ultimately reach interconnection. Moreover, the tariff does not clearly explain what changes to a project will require a restudy to be performed or what constitutes “material modifications” that could result in the loss of queue position. For example, SPP considers a change in wind turbines as not material, but a restudy is performed. Other regions may consider a change in wind turbines at the end of the study process a modification that could result in the loss of queue position. The switching of wind turbine types has been a very problematic issue, since most wind developers enter the queue thinking they can purchase a particular machine only to later determine they are unavailable or that particular turbine will require significant amounts of reactive compensation to meet Order No. 661-A. The vagueness of the tariff on interconnection procedures leads to developers modifying projects, which in turn causes restudy and extended timelines for the project making the change, which then affects all other projects that fall lower in the queue. The evidence required of the generation developer on site control, particularly how much land is needed is also not clearly stated in the pro forma tariff language.

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The tariff, while clear that the customer determines its Point of Interconnection (POI), does not provide standards or rules for determining the optimal POI. In some cases, this can result in sub-optimal transmission planning and potentially longer study timelines. Additionally, it could drive some of the “upgrade shopping” discussed earlier. For example, a customer could select a POI that is less than optimal from a system standpoint, but has a low cost set of interconnection facilities and a higher cost set of network upgrades. A change in the interconnection point, based on Good Utility Practice applied by the ISO or RTO, could lower the overall cost and provide improved integration with long-term transmission expansion needs, but shift more cost responsibility to the generator. Finally, the Small Generator Interconnection Procedures (SGIP) have added an additional level of complexity to an already complex and resource intensive process. It has been the experience of some ISOs and RTOs that some interconnection customers will reduce the size of their project so that it is one machine below the cap set forth in the tariff to be able to utilize the more flexible and less stringent SGIP. Several ISOs/RTOs, including SPP, have moved to operating only one queue to prevent the use of this threshold avoidance practice by developers. To that end, there is a need for increased coordination between the SGIP and the Large Generator Interconnection Procedures (LGIP).

4 Potential Solutions to Address Current Challenges

4.1 Consider Alternatives to the Present Scope of Feasibility Studies

One option for consideration would be to redefine the present scope and function of the ISO/RTO in performing feasibility studies. Various alternative methods are under consideration including providing information on the current transmission capacity available to projects before they enter the queue and having developers perform their own preliminary studies prior to making their interconnection request. As noted previously, at present, the ISO/RTOs effectively serve as a low cost consultant in the initial decision making process. Eliminating the feasibility study as a separate step, and instead combining it with the system impact study, potentially reduces the processing timeline. To the extent that, subject to Critical Energy Infrastructure Information (CEII) and confidentiality issues, key data could be provided to developers, it would be presumed to enable better up front decision-making and with it, a reduced number of duplicate requests could be realized. Issues to be further considered around this solution are data timing issues, given that information may be out-of-date as soon as it is posted. Additionally, further analysis is required to determine whether this approach would reduce the overall workload or by

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contrast increase the workload and reconciliation time with external parties to the detriment of the timeline.

4.2 Group Interconnection Requests in a Standard Fashion to the Extent the Transmission Provider Elects to Conduct Studies in Clusters

Under the current pro forma tariff, Transmission Providers have the option to process a group of interconnection request together, instead of serially, for the purpose of studying the interconnection requests together. Several ISO/RTOs have already implemented processes to cluster, or group, requests in their Commission-approved interconnection procedures. For example, the NYISO currently uses a clustering approach, based upon project milestones, in its “Class Year” process for Facilities Studies and cost allocation. Grouping requests together can sometimes improve efficiency, by sizing a transmission project to meet the aggregate need, and reduce study timelines for the group as a whole. However, it does not eliminate rework as projects drop out through the group study for various reasons, which can include the fact that multiple projects may be competing for the same Power Purchase Agreement (PPA), or that projects may be speculative for any number of reasons. Basically, grouping the supply requests without applying the demand for the energy against it is only a piece of a comprehensive solution. Clustering has both positive and negative impacts, depending on the circumstances. As such, there will ultimately be a need for flexible implementation of any clustering approaches, and to address other related issues, such as cost allocation. Standardizing the way requests are grouped within an individual ISO/RTO may reduce the complexity of the studies. For example, one method to group such projects would be to apply electrical impact studies to determine how projects should be grouped instead of drawing a circle around a series of projects on a map and calling that a group. Additionally, upgrade costs could potentially be shared among the group, which might provide benefit to developers planning to locate in the same area. However, any specific recommendation regarding cost allocation is outside the scope of this document and requires further discussion and analysis by the ISO/RTOs. As the clustering approach is developed further, some ISO/RTOs that are not currently using clustering may consider filing with the Commission the appropriate waivers to retroactively implement the cluster approach within their specific region.

4.3 Increase the Magnitude of Milestones Required to Continue Through the Interconnection Study Process

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A potential solution to reduce the number of projects not expected to reach interconnection would be to increase the financial or other requirements needed to enter and remain in the queue. Tying a deposit more closely to expected study costs would both set expectations of developers appropriately as well as potentially focus developer requests more narrowly. This could also address the concerns with “upgrade shopping”

identified earlier5 in many cases. Consideration would need to be given to impacts on small developers as well as to those parties that are required by state regulatory agencies to evaluate alternative points of interconnection. Additional information could also be required in the application phase to indicate if the particular project remains viable including requiring site control commitments, site specific equipment purchasing, and/or power purchase agreements. Because of varying requirements for different generation project types and different developer business models which may not be able to provide the same demonstrations of readiness at the same type in the process, it is likely that these requirements would need to offer either/or alternatives to meet the milestones and proceed. In any case, all requirements would need to be objective, and well-defined in the tariff. Applications that do meet these requirements could be given priority and not required to wait in line behind those projects that cannot show this level of commitment. Proceeding through the rest of the queue process could be based on meeting milestones, where milestones are defined as criteria which allow a request to proceed to the next stage in the process, potentially leapfrogging other requests. At its heart, this is a solution that would allow prioritization based on pre-defined, but alternate measures than the current first-in first-out measure. Those milestones could range from additional financial commitments to data completion to being selected through competitive solicitation programs or markets, such as ISO New England’s FCM. For example, the financial commitment of interconnection customers should increase at each stage of the study process and the necessary level of site control should also increase. Site control could be an additional mandatory requirement at an appropriate stage in the process, rather than an alternative to security deposits. Another example is stricter data requirements. The tariff could be modified to prevent customers from proceeding when their request has data deficiencies, including the elimination of the six month window given to wind generation developers to provide detailed electrical design specifications. The current requirement for continuance of milestones for Large Generator Interconnection Procedure (LGIP) Section 11.3 is too lenient and too late in the process. The requirements listed are mostly applicable to fossil fuel units and not renewable generation. This can lead to speculative projects entering into interconnection agreements and then entering suspension. Moving these milestones earlier in the process (e.g. as part of the interconnection request application) and making them applicable to all projects, including renewables, should reduce the number of projects that enter the queue to only withdraw in the middle of the process or seek suspension.

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5 ISO New England observed that several projects were withdrawn from consideration under the FCM qualification process (a process to determine whether a proposed capacity project is viable for the next commitment period) when study fees came due. In one case, a single participant had submitted over 100 proposed capacity projects and withdrew most prior to the fees being collected.

Finally, along with the milestones, there should also be additional financial consequences for those projects that are delayed or withdrawn. For example, interconnection customers who withdraw during the study stage could be required to pay for the costs of any necessary restudies using their prior deposits. Also if a project wishes to enter suspension, the developer could be required to pay a significant non-refundable charge (i.e. $/MW/Month) if no construction has commenced on the project at the time of suspension. Alternatively, suspension could only be permitted in response to a Force Majeure event, rather than a blanket option available to all generators for any reason they choose. That suspension should also be tied to a specific milestone listed in the Large Generator Interconnection Agreement (LGIA), rather than the generic suspension rationale permitted today. The current suspension limit of three years could also be reduced to lower the level of uncertainty that surrounds the queue. Essentially, the complexity and timeliness of the queue in some ISO and RTO regions could be dramatically improved if the ability for projects to enter suspension was designed to be an avenue of last resort for a project under unavoidable circumstances, not as a free option. There are a number of potential benefits if only viable projects are entered into the generation interconnection queue or if they were given priority. First, the queue backlog would level off. Second, projects could be studied and interconnected into the system in a timely manner. Third, suspension rates would be lower, thus withdrawal rates would be lower leading to a decrease in the need to perform restudies. The debate continues about the potential positive and negative effects of increasing financial, site control, data and other requirements for projects to enter the queue, advance through the process, and ultimately to suspend. These concepts are in the early stages of discussion in the ISO/RTOs, and work remains to develop an equitable, objective, and effective milestone list. Additional analysis is also required to determine whether the administrative and restudy burden potentially caused by this approach more than offsets the positive benefits of moving higher prioritized projects ahead in the queue. The IRC clearly recognizes that for this method to be successful, the changes made need to balance the goal of reducing time and uncertainty for queue participants, while maintaining open access and reducing negative or other unintended consequences.

4.4 Clarify Pro-Forma Tariff Language The current pro forma tariff should be modified to provide more guidance or detail as to what constitutes a “material modification” and the associated ramifications of a “material modification”, rather than leaving that determination to the discretion of the Transmission Provider. Such modifications should address what changes to an interconnection project should not be allowed without loss of queue position versus those that are immaterial and can be incorporated with only proper notice. The vagueness of the tariff on what constitutes a “material change” to a project allows

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developers today to change the specifications of the project at anytime during the study process with little to no financial or non-financial penalty to themselves. By setting expectations up front for developers on what constitutes a material modification, it can be expected such changes and the associated restudies could be reduced. If evidence of the level of site control is to increase as projects move through the study process modifications to the tariff will have to provide more specific language on what documentation is required as evidence of site control. The modifications to the tariff should allow for tailoring study requirements and timelines for certain scenarios. The current study requirements for small generators in the tariff could be shortened by eliminating the need to perform some of the studies presently required pursuant to clear tariff rules. For example, under certain conditions, it might be reasonable to perform a single study in lieu of the three-step process currently required. Also, the tariff definition of a small generator should be modified to consider the relationship of the size of the generation to load around the connection point rather than absolute size of the proposed generator (i.e. a 20 MW generator at a site with 5 MW of load usually is harder to process than a 20 MW generator at a site with 150 MW of load.) While it is reasonable for the study processes and timelines for small generators to be shortened, there is also a need to recognize that extremely large and complex projects will likely require more time and resources to complete the study process. The tariff should include provisions that recognize the complexity of such projects and allow the ISO/RTO to set realistic or practical study timelines.

4.5 Improve Integration with Long Term Planning There is a natural and inseparable interrelationship between transmission planning for long-term load growth, and the interconnection of new generation. This is true despite the fact that as a consequence of Order No. 2003, these two processes have been somewhat separated in order to accommodate the need to timely interconnect independent suppliers in a nondiscriminatory manner. The separation of these processes was necessitated by the separate competitive supply positions, business objectives, and plans of the independent supplier versus the need to upgrade the system for reliability (and more recently, economics) as part of the traditional RTO planning function and transmission owner franchise obligation. Melding together the independent decisions of a multitude of independent suppliers and load serving entities into a cohesive and efficient transmission infrastructure remains a puzzle that the industry continues to try to solve. The IRC believes that the ISO/RTOs are uniquely positioned to address this question, and reintroduce some of the cohesion in generation and transmission planning that has been stretched since the open access rule. ISO/RTOs and their stakeholders have lived through the effects of this separation and experienced first hand the difficulty and frustration of trying to achieve fast, effective, and fair generator interconnections, while

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developing an efficient forward looking long-range transmission plan. These difficulties have been the result of some growing pains surely, but at the core we believe are the result of essentially adopting the pro forma procedures enacted established in Order No. 2003 to ensure fair and comparable interconnection service, and applying them to the high volume of interconnections the ISO/RTOs must address. The advantage of the broader regional focus of the ISO/RTOs is frustrated by the pro forma procedures, the nature of which may not lend itself to any kind of efficiency of scope. Today, we are facing an ever steeper challenge to providing acceptable interconnection service. The cumulative effect of many projects in certain areas can drive the state of the system to the point that large-scale upgrades may be needed to interconnect the significant quantity of proposed generation. While the transmission capacity needed to optimally and efficiently accommodate expected resource needs in a given region may be extensive, the assessment of construction costs for a large-sized transmission project can pose too great a financial hurdle for the first generation developer(s). As a result, the network upgrades may forgo economies of scale in an effort to mitigate the up-front transmission costs. The IRC recognizes that at its heart, the solution will be driven by the answer to a fundamental policy question. Specifically, should the location of generators be the driver of new transmission upgrades or should new project developers have to fit their projects around a pre-approved transmission plan which is designed to meet the needs of existing and projected future load? There is no simple answer to this question, and the answer likely melds the two alternatives. On one hand, there are efficiencies in developing facilities that can move higher volumes of electricity. Those facilities can provide benefit with respect to right-of-way utilization, production cost decreases and in facility costs per unit of power reflecting impacts to losses and reliability margins. These facilities take longer to permit and develop, and so require the longer view. A longer term view cannot be planned for without some assumptions about load and generation, which introduces an element of risk. However, under a scenario where new projects must fit within a planned transmission grid this becomes a risk that must be accepted. On the other hand, Order No. 2003 views transmission as a generation enabler rather than a driver, with a focus on upgrades driven by new generation projects. Such an approach places the risks and costs of new development on the party reaping the reward from those investments and, some may argue, is more in keeping with sustaining a competitive model for the development of needed new generation infrastructure. The ultimate solution must balance the need for supporting competitive generation development models with the reality that without sufficient transmission infrastructure to enable generation to connect in a timely fashion, the backlog of queue requests can be expected to continue at current levels into the foreseeable future.

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Texas, with its Competitive Renewable Energy Zones (CREZ) process, and California, with its Location Constrained Resource Interconnection (LCRI)6 proposal, have begun the process to integrate the long-term view into the interconnection planning arena by identifying transmission solutions to solve specific regional generation problems, both tied to renewables. The CAISO’s LCRI proposal was triggered by issues associated with the generation interconnection activities in the Tehachapi wind area. The issues in the Tehachapi area were ultimately resolved through proactive measures taken by the CAISO and FERC that were facilitated by a waiver of specific LGIP requirements to allow a “retroactive” group study process.7 In Texas, the CREZ process seeks to build transmission to support statewide renewable needs from a high number of generation developers located in pre-defined areas. Neither of these proposals eliminates the ability of generators to proceed through the pro forma interconnection queue procedures, should they so desire.

Conclusion The individual ISO/RTOs continue to examine the interconnection queue process issues and explore potential solutions to them in their stakeholder processes, with filings expected from several of the ISO/RTOs beginning in 2008. The IRC will continue the ongoing dialogue among its members of the common issues in order to avoid the potential implementation of a patchwork of different designs from being instituted across the country. The IRC believes the Commission’s Technical Conference has provided a solid record for this work to continue and has used this White Paper to outline, on a generic basis, the scope of common issues, competing policy goals and potential solutions being discussed. The IRC stands ready to assist the Commission and the stakeholders in the ongoing regional and national dialogue on these important issues.

6 CAISO LCRI Tariff amendment filing: http://www.caiso.com/1c88/1c88dad154710.pdf. On January 25, 2007 the CAISO filed a Petition with FERC for a Declaratory Order seeking conceptual approval of a new financing mechanism to facilitate the construction of interconnection facilities for location-constrained resources. On April 19, 2007, FERC granted the CAISO's petition and accepted the design concepts proposed therein, thereby paving the way for the CAISO to file tariff language for implementing this important initiative. Participating Transmission Owners ("Participating TOs") would pay the upfront costs of constructing what was Location Constrained Resource Interconnection Facilities ("LCRIFs"). Participating TOs that construct LCRIFs would be permitted to reflect in their Transmission Revenue Requirement ("TRR") and in the CAISO's Transmission Access charge ("TAC") the costs of a LCRIF which are not being directly recovered from generators connected to the LCRIF. In other words, the unsubscribed capacity of qualifying LCRIFs would be rolled into the CAISO's TAC. As new generation resources are developed in an area and connect to a LCRIF, the costs of the capacity required by those generation resources would be directly recovered from those new generation owners "pro rata" on a going-forward basis, and the costs included in TAC reduced accordingly. Once the anticipated generation in the region is fully developed and the capacity of the LCRIF is fully utilized, the going-forward costs of the LCRIF would be borne entirely by Generation developers and would not be included in the TAC. Thus, under the CAISO's proposal, the costs associated with the unsubscribed portion of the qualifying facilities would be included in TAC, until additional Generators are interconnected, at which time costs would be directly assigned to such Generators. On December 21, 2007 FERC issued an Order conditionally accepting CAISO’s proposed LCRI tariff revisions. 7 FERC order on Tehachapi: http://www.caiso.com/1bee/1bee799b1f1f0.doc, Board Memo on Tehachapi: http://www.caiso.com/1b6b/1b6bb5ca7400.pdf

http://www.caiso.com/1c88/1c88dad154710.pdf

http://www.caiso.com/1bee/1bee799b1f1f0.doc

http://www.caiso.com/1b6b/1b6bb5ca7400.pdf