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Mountain States Transmission Intertie (MSTI) Open Season Update Meeting

Mountain States Transmission Intertie (MSTI) Open Season Update Meeting. Thursday, June 21, 2007 8:30 am to 12:00 pm General Office Auditorium Butte, MT. Agenda. Welcome and Meeting Purpose Discuss MSTI Announcement MSTI Brochure / Fact Sheet

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Mountain States Transmission Intertie (MSTI) Open Season Update Meeting

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  1. Mountain States Transmission Intertie(MSTI)Open Season Update Meeting Thursday, June 21, 2007 8:30 am to 12:00 pm General Office Auditorium Butte, MT

  2. Agenda • Welcome and Meeting Purpose • Discuss MSTI Announcement • MSTI Brochure / Fact Sheet • Discuss Idaho Power / PacifiCorp Projects / Fact Sheet • Engineering and Preliminary Siting Update • WECC Planning Process • MSTI Project Costs • NWE System Upgrades / Mitigation • Indicative Pricing • Next Steps • Additional Transmission Requests Received • NWE Consultant Developing Other Pricing Mechanisms • Schedule Next Meeting • Provide Framework for Moving Forward

  3. Mountain States Transmission Intertie (MSTI) • Background • Purpose, Benefit , and Need • Project Detail • Project Timeline • Siting, Permitting, and Environmental Review • Public Outreach and Communications • Contacts

  4. MSTI Brochure / Fact Sheet

  5. MSTI Brochure / Fact Sheet

  6. PacifiCorp / Idaho Power Fact Sheet

  7. MSTI Engineering and Preliminary Siting Update • Overview of 2006 Preliminary Engineering and Siting Analysis • 2007 Work Plan • MFSA Process

  8. WECC Planning Process • WECC Regional Planning Initiated May 17 • 17 responses • Discussed at FERC Technical Conference June 13 • Discussed at WECC PCC meeting June 14 • NTTG Sub-regional coordination July 9 • MSTI • PAC • IP • USE consulting

  9. WECC Planning Process • WECC Regional Planning Initiated May 17 • 17 responses • Discussed at FERC Technical Conference June 13 • Discussed at WECC PCC meeting June 14 • NTTG Sub-regional coordination July 9 • MSTI • PAC • IP • USE consulting

  10. MSTI Project Costs

  11. NWE System Upgrades / Mitigation

  12. Indicative Pricing • Process • Several scenarios were analyzed. The following illustrates three projects based on varying transmission capacity size and construction cost estimates. • Capital construction cost estimates were developed based on Power Engineering consultants in association with NWE personnel. • Pricing is based on a traditional FERC revenue requirement and return on rate base analysis. • Return on rate base plus operating expense, depreciation expense, property and other taxes, and income taxes combine to determine the net revenue requirement. • Each scenario assumes pricing over a 30-year period. The pricing options and ranges for each include a 30-year levelized and 10-year step pricing structure • Pricing ranges are stated in terms of dollars per MWh and dollars per KW month.

  13. Indicative Pricing • Assumptions • Rate base is the total of construction capital, AFUDC (8.9%), mitigation required capital, Idaho sales and use tax (6%) for the portion of the investment assumed in Idaho (50%), working capital, and depreciation reserve. • Each scenario assumes a 13% return on equity based on recent FERC approved returns for new transmission development. The debt rate is assumed at 6.794% with a 50-50 capital structure. Thus, the authorized return on rate base assumed is 9.897%. • O&M costs are assumed at 3.5% of the capital construction cost and escalate 3% per year over the 30-year period. • Depreciation is based on 30-year straight-line for book, and 20-year MACRS for tax purposes. • Property taxes assume 50% MT at 3.132%, and 50% ID at 1.025%. • The plan and pricing could also be considered conservative, as we are reviewing current legislation based on House Bill 3 and other potential impacts and savings regarding property tax rates or other state/federal incentives associated with new generation and related development.

  14. Indicative Pricing • Projects/Scenarios • Project #1: A 390 mile 500 kV line from Townsend, MT to Midpoint, ID with capacity of 1,500 MW. For pricing, a 75% subscription factor (1,125 MW) and a 100% subscription factor (1,500 MW) is illustrated. This project would be the most preferred approach, assuming sufficient demand and system utilization. • Project #2: A 305 mile 345 kV line from Townsend, MT to Borah, ID with capacity of 900 MW. For pricing, a 100% subscription factor (900 MW) is illustrated. • Project #3: A 270 mile 230 kV line from Mill Creek, MT to Borah, ID with capacity of 625 MW. For pricing, a 100% subscription factor (625 MW) is illustrated.

  15. Indicative Pricing • Summary of Results

  16. Next Steps • Additional Transmission Requests • Powerex • Cargill • NWE Engaged CRA International • Tariff Pricing Alternatives • FERC Presentation • Schedule Next Meeting • Develop Plan for Moving Forward

  17. Questions And Discussion

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