Allocating Capacity and Costs of New Transmission

November 7, 2007Portland, OR

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AgendaAgenda

Purpose - Discuss Cost Allocation and Cost Recovery of New Transmission Projects

• Cost Allocation – Rich Bayless• Cost Recovery – Ron Schellberg

– Expected Project Costs– FERC “higher of” methodology– Incremental Pricing Models– Rollover Rights

• Transmission Provider Practices• General Discussion

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Cost Allocation Principles

1. Cost Causers are Cost Bearers; Beneficiaries pay reflective of benefits received.

2. Projects comply with state and federal policy and developers identify the intended purpose or resource portfolio the transmission project applies to relative to such.

3. Allocation results in reasonable opportunity for full cost recovery but no more– Cost Allocation based on distribution of benefits– Customer or TP accepts responsibility for associated costs;

project causes no harm or uncompensated adverse impact.

4. For solely wholesale transmission, wholesale customers pay

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NTTG Planning ProcessNTTG Planning Process

5. NTTGSteering

CommitteePlan

Approval

2.Expansion Plan & Projects

WithBenefits Parsed

3. Cost Allocation Committee

Applies Principles& Recommends

Likely Cost Allocation

1.Bienniall NTTG Planning Process:

Identify Needs, Least Cost Expansion Project

Alternatives, Technical Benefits, Project Costs

4. Draft Biennial

Expansion Plan

6. Final BiennialPlan: Includes Likely

Cost & BenefitAllocation Estimates

given PlanningAssumptions

7. TP considers Final Biennial Plan for

incorporation into Final TP Transmission Plan

Approved

Customer & Stakeholder

Input

Customer & Stakeholder

Input

Customer & Stakeholder

Input

TP Local Planning process inputs

Finalization of TP Transmission Plan

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Cost Allocation Process• Project Developers and Planning Committee prepare info

package for CAC– Description and purpose– Expected benefits, risks, and costs

• Technical and economic– Proposed Cost Allocation and Recovery– Any pertinent analysis– Other

• CAC iterates with PC process and analysis.• Open process and stakeholder input• CAC examines and determines distribution of benefits/risks• Upon reaching agreement, CAC recommends estimate of

cost allocation for final Biennial Plan Report to Steering Committee

• CAC and PC receive and monitor updated info from developers during biennial cycle

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Cost RecoveryCost Recovery

• Expected Project Costs– Bridger to Northwest (710 Miles)

• 190 Miles – Bridger-Populus• 270 Miles – Populus-Hemingway• 250 Miles – Hemingway-Northwest

– For this cost recovery discussion assume: • 1000 MW Capacity• $1,000,000,000 Project Cost

– Results in: • $1000/kW or approximately $180/kW-year

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Cost RecoveryCost Recovery

• FERC “higher of” methodology– Charge “embedded rolled-in” rate or

“incremental” rate. Current PTP rates:• Idaho Power ~ $20/kW-year• Northwestern ~ $40/kW-year• PacifiCorp ~ $25/kW-year

– Bridger-Northwest costs well exceed current embedded rates

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Cost RecoveryCost Recovery

• Incremental Pricing Model– Assuming 40+ year deprecation rate– Rate Base +$1,000,000,000– Return, additional ~$120,000,000/year– O&M, additional ~$60,000,000/year– Total, additional $180,000,000/year

• Requests of shorter duration would cause annual cost recovery to increase.

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PoliciesPolicies

• Transmission Provider Policies– PacifiCorp– Idaho Power– Northwestern

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General DiscussionGeneral Discussion

• Cost Allocation

• Cost Recovery

• Transmission Provider Policies