SEAMS STEERING COMMITTEE MEETING 2, 2010 TX 10:00 a.m. 3 … meeting minutes 090210.… · 2009-02-10 · Carl Monroe agreed to meet but has requested a presentation on the ITP issues

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Southwest Power Pool SEAMS STEERING COMMITTEE MEETING

September 2, 2010 Dallas Love Field Conference Center – Dallas, TX

10:00 a.m. – 3 p.m.

• M I N U T E S •

Introductions Chair Paul Malone called the meeting to order at 10:00 a.m. There were 18 members in attendance—12 in person and 6 on the phone (see Attachment 1). When asking for approval of the June 15th minutes, Richard Ross, AEPSC, requested a revision. The change was agreed upon and the ‘June 15, 2010 Minutes ‐ Amended’ document will be posted to the SSC website.

Review of Previous Action Items

Link to Seams documents on the SPP Website www.spp.org >org groups > Access SPP’s Governing Documents (scroll down to the document listings at the bottom of the screen) >Governing - Tariff, Bylaws, Articles, Membership/Seams Agreements, Market Protocol, Business Practices—(Click on the + to expand the list) >Seams Agreements Discussion on provisions of the Southwester Power Administration (SWPA) Agreement The provision of the Membership Agreement included: 1. Reliability upgrades, if agreed upon 2. Government entity cannot enter into agreements without government approval 3. Payments can only through a government agency 4. No provision in agreement for cost allocation Mr. Ross stated that a Membership Agreement review was not in the purview of this committee. It was noted that since SWPA does not have an actual Seams Agreement with SPP, existing tariff provisions and practices apply. Lanny recommended incorporating cost allocation into SWPA tariff. Lanny responded to a former action item request to address the IPSAC discussion items at a ‘pre‐meeting’ of the MOPC. Carl Monroe agreed to meet but has requested a presentation on the ITP issues. Lanny suggested AEP join the pre‐meeting also.

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Lanny also provided an update on the SPP staff available to work on Seams efforts. Those involved include: o Policy Review – Bruce Rew, Katherine Prewitt, and Lanny Nickell o Ops Implementation – Bert Bressers, Jason Davis, and Kevin Bates o Planning Implementation – Keith Tynes (AECI coordination issues) o AECI and MISO – Lanny Nickell Action Item: Lanny to provide a monthly report to Seams Committee from each group noted above. Paul Malone requested clarification on the elements that comprise a Seams Agreement. Lanny responded that these agreements are impacted by the activities neighboring Balancing Authorities (BAs) are performing—for example: Transmission Service Coordination, ATC/AFC studies, Interconnection Agreements and Expansion Planning. Adam McKinnie, Missouri Public Service Commission, added that Joint Planning agreements should also be included. Lanny stated that SPP and the Entergy Seams Agreement cover these data sharing requirements. Mr. Malone added that committee members have differing interests based on their Seams but strongly encouraged the SPP staff to participate in the Interregional Studies with all of SPP’s neighbors. Mr. McKinnie added that we should ask our neighboring BAs what their system will look like 20 years out and encourage them to share their plans with us. Reports on AECI and MISO Seams Agreements Lanny discussed the market‐to‐market coordination effort that PJM and MISO implemented. This approach means if congestion occurs on a flowgate anywhere in the region, whoever can ‘fix’ the problem first does so and the cost is settled later. He added that SPP is developing a business case to determine if it’s more beneficial to integrate this approach or wait for future market development. The business case should be ready for stakeholder review by October. Mr. Malone asked where the documents are located that captured these issues. Lanny pointed to the earlier discussion concerning Seams Agreements for the location of the SPP Joint Operation Agreements (JOA) Brian Thumm, ITC Holdings, inquired if it was within the scope of a Seams Agreement to determine the issue of external upgrades when granting or denying long‐term requests. Based on SPP’s Tariff, it falls on the customer to resolve the issue before being granted transmission. Lanny responded that these issues are bound up in the Tariffs but it does fall within the scope of a Seams Agreement to address such issues. Mr. Ross shared that SPP tariff provisions filed 6 months ago also addresses this issue. Parallel Flow Visualization Project Update Bert Bressers, SPP, presented the current status of the Visualization project (see Attachment 2). Mr. Malone asked what would force a non‐market BA to participate in the project. Mr. Bressers responded that until NAESB files new business practices with FERC, there is no requirement to participate. NAESB is planning to file a recommended ‘interim’ approach in mid‐September. Voting is done by the NAESB executive committee based on the recommendations from the BPS. Lanny recommended that every SPP member become active in the business practices development before a final recommendation/approach is voted upon. It was noted again that current Seams Agreements will have to change to address this change in the IDC process.

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Cooper South Issues Mr. Bressers reported that SPP was still reviewing the data involving Cooper South in an attempt to identity a gap of 100 or so MWs not being account for in the IDC. The gap could be due on the fact that MISO does not account for market flow into the IDC. SPP continues to work with MISO to identify where the conflicting or incomplete information is coming from. The next step will be to work with PJM and MISO to develop a Best Practices approach for addressing such issues. SPP’s Response to NOPR RM102‐23‐000 Lanny discussed SPP’s draft response to the NOPR that was issued in mid‐July (see Attachment 3). Establish Priorities of Seams Agreement Issues The priorities as agreed upon by the committee include: o Coordinate the planning and identification of joint transmission projects with neighbors o Coordinate the required data sharing and ATC coordination with Entergy to improve current

agreements o Develop a resolution to the MISO/PJM Congestion Management Process (CMP) issues o Establish Cost Allocation/Recovery Principles These priorities will be conveyed to the MOPC for the final decision on priorities and projects. The committee will wait to hear from the MOPC on these items but was encouraged to continue working through these issues. Additional Action Items Action Item: Add to the next SSC agenda: ‐‐ The future role of the SSC in the Interregional Joint Planning Committee ‐‐ Ongoing updates from the ISPAC ‐‐ Ongoing updates on the tariff provisions and business practices Action Item: Lanny to determine what constitutes a written report to the SSC. Which metrics are should be captured regarding regional activities? Next Meeting Paul requested a teleconference call prior to the MOPC meeting in mid‐October so the committee can prepare a status report on the committee activities. The next scheduled face‐to‐face meeting will be held November 10th in Dallas at the AEP offices. Dowell will set up the two meetings and notify the committee of the details. Respectfully Submitted, Dowell Hudson, Secretary

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Parallel Flow Visualization Project UpdateUpdateBert Bressers

September 2, 2010

Parallel Flow Visualization Project

U d t P ll l Fl Vi li tiUpdate on Parallel Flow Visualization

• The NAESB WEQ BPS decided in the June and July 2010 Meetings to implement an interim solution for reporting Firm and Non Firm priorities to NERC SDX / IDC for the parallel flow visualization pilot that starts 11/1/2010. The expectation is that:

The RC of Non-Market BA’s send real time output of all resources and the priority of the MW output of resources in accordance with their Tariff. This for pilot.

The RC of Market BA’s is only required to send real time y qoutput of all resources. The currently reported Market Flow (total + break down in priorities) covers the priority requirements. This for pilot.

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Th i t i l ti i t i l ti k i t d th• The interim solution interim solution work paper is posted on the NAESB WEQ BPS website see the August 6th Minutes column.

• The next NAESB WEQ BPS meeting is scheduled for September 15-16 i Phil d l hi PJM i h i Th i ill b h P ’16 in Philadelphia. PJM is hosting. The meetings will be at the Penn’s Landing Hyatt in Philly. NAESB WEQ BPS will review formal comments on the interim solution and will then start working on the final solution.

• The time schedule for Final solution is implementation by 11/1/2011.

• According to the interim solution work paper, the BA is responsible forproviding the Generator Priority Assignment for Non-Market BA’s. (Notthe TSP)

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• The expectation is the RC’s will provide the priority data as soon as• The expectation is the RC s will provide the priority data as soon as possible so Change Order 283 (real time data submission of resources) has information starting November 1, 2010.

• NAESB should complete it EC approval in late September or early• NAESB should complete it EC approval in late September or early October 2010 and then the standards will go out for membership ratification. To date there has never been a WEQ standard that failed at the membership level.

• The priority data submission for generators has been incorporated into the SDX Functional Specification (Version 2.6). Requirements of format and frequency will be discussed at the IDCWG meeting in Minneapolis week 8/16 – 8/20.

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Ji B bi ( h i IDWG d M b f NAESB WEQ BPS)• Jim Busbin (chair IDWG and Member of NAESB WEQ BPS) doesn't have an expectation that all non-market RC's will be submitting their priority data by November 1. Until a permanent solution is prescribed (scheduled for 2011), participation with correct data will p ( ), p pprobably be somewhat moderate. He expects to see test data submitted by all RC's in the form they plan to utilize on a permanent basis by November 1.

• SPP need to work with TSP’s of Non-Market BA’s to get priorities for their resources based on their Tariffs.

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I t SPPImpact on SPP

• SPP as an RC will provide real time MW output of resources to NERC SDX by November 1, 2011. SPP developed software and will be ready for submission 11/1/2010.

SPP RC ill id i iti f ll t NERC SDX• SPP as an RC will provide priorities of all resources to NERC SDX for all resources of Non-Market BA’s for which SPP is RC. There are no requirements yet, so we don’t know if November 1, 2011 is realistic date. We expect requirements out off next week (week 8/16 p q (– 8/20) NERC IDCWG Meeting.

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Bert BressersDirector Operations SupportDirector Operations [email protected]

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FERC Notice of Proposed Rulemaking

T i i Pl i d C t

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Transmission Planning and Cost Allocation

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Purpose of the NOPR

To incorporate into transmission planning processes public policy requirements established by state or federal laws orpolicy requirements established by state or federal laws or regulations that may drive transmission needs.

To provide sponsors of transmission projects the right, consistent with state or local laws or regulations, to construct and own facilities selected for inclusion in regional transmission plans.

To improve coordination in the evaluation of transmission f iliti d t b l t d i t i hb i

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facilities proposed to be located in two neighboring transmission planning regions.

To provide a closer connection between transmission planning and cost allocation processes.

Transmission Planning RequirementsFERC proposes to require all public utility transmission providers to:

Participate in a regional transmission planning process that produces a regional transmission plan and that meets Order No. 890 transmission planning principles.

Account for public policy requirements established by state or federal laws or regulations that may drive transmission needs.

Remove from FERC-approved tariffs or agreements any right of first refusal that provides an incumbent public utility with an undue

p

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first refusal that provides an incumbent public utility with an undue advantage over a non-incumbent transmission project developer, while preserving state authority.

Enter into a transmission planning agreement with neighboring transmission providers.

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Cost Allocation RequirementsFERC proposes to:

Establish principles for allocating the costs of new transmission facilities in a manner that is at least roughly commensurate with the distribution of benefits.

Require each public utility transmission provider to have a cost allocation method for new transmission facilities in the regional transmission plan (“intraregional facilities”) that satisfies certain proposed cost allocation principles.

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Require each public utility transmission provider to have a cost allocation method for new transmission facilities resulting from the planning agreements implemented by neighboring regions (“interregional facilities”) that satisfies certain proposed cost allocation principles

SPP CommentsSPP plans to develop comments to:

Highlight SPP’s progress in addressing issues raised in the NOPR.

Caution that FERC is treading into areas of state jurisdiction and discuss the implications of state jurisdictional issues.

Make recommendations for the final rule to be promulgated in this proceeding.

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SPP Comments (cont’d)

Highlight SPP’s Efforts to Address NOPR Issues:

SPP’s Highway/Byway cost allocation aligns costs with beneficiaries.

The NOPR specifically suggests a highway/byway approach to cost allocation for transmission facilities.

SPP has already filed, and FERC has accepted, a cost allocation plan consistent with the NOPR.

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SPP’s Integrated Transmission Plan process includes assessment of federal and state public policy mandates.


Highlight SPP’s Efforts to Address NOPR Issues:

SPP has modified Attachment O to provide a limited TO right of first refusal to acknowledge a TO’s concomitant obligation to build.

Third-party transmission developers are permitted to participate in SPP planning and construction under Attachment O.

Third-party developers may engage in building and ownership of facilities through designee qualification/novation process).

Third-party transmission developers may be designated to build if an existing TO does not agree to build within 90 days of its designation

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not agree to build within 90 days of its designation.

While SPP has seams agreements in place that partially address planning and cost allocation for interregional projects, SPP and its neighbors must continue to work to address issues related to planning and cost allocation of interregional projects.

Further Commission guidance would be helpful.

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State Jurisdictional Issues:

TOs in SPP have a state obligation to serve retail native load reliably; therefore, TOs must have some right of first refusal to build facilities to satisfy their state law obligations.

Denying TOs a right of first refusal to build additions/upgrades to their systems would inappropriately require them to rely on third parties to build additions to their systems to satisfy their state legal obligations

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obligations.


SPP Recommendations for Final Rule:

SPP supports the NOPR transmission planning and cost allocation requirements, but recommends that FERC make them stronger.

FERC should require transmission providers to enter into comprehensive seams agreements with neighbors.

Seams agreement mandate must apply to non-jurisdictional utilities operating under reciprocity agreements as well

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under reciprocity agreements as well.

FERC should require transmission providers to demonstrate that they participate in regional planning and have developed a regional plan.

Cost allocation/recovery should be tied specifically to transmission planning and satisfying the transmission planning requirements of the NOPR.

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If FERC elects to prohibit all rights of first refusal for existing TOs, FERC should develop standards for construction and design of facilities or should specifically authorize regional planning entities to develop mandatory construction/design standards.

Without such standards:

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Developers of transmission have too much discretion regarding what to build and RTOs/ISOs have no guidance on how to evaluate competing bids to build.

The inclination is to build least-cost rather than most beneficial (i.e., line rating, wood vs. metal poles, etc.).



FERC should clarify that RTOs/ISOs may rely upon states’ direction of the choice transmission developer under applicable state law.

RTOS/ISOs should not be required to interpret or enforce state law regarding the proper entity to build/own transmission facilities.

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FERC should consider authorizing transmission planners to establish corridors for transmission development to:

Coordinate transmission development by multiple builders along the same corridors to minimize land use impacts.

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Enable transmission development along existing rights of way to facilitate siting process and minimize land use impacts.

Comments on the NOPR are due September p29, 2010

SPP will develop comments for this NOPR in coordination with the Strategic Planning

Committee

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