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Duke Energy Carolinas Transmission Tariff Rate Review PowerPoint Presentation
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Duke Energy Carolinas Transmission Tariff Rate Review

Duke Energy Carolinas Transmission Tariff Rate Review

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Duke Energy Carolinas Transmission Tariff Rate Review

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  1. Duke Energy CarolinasTransmission Tariff Rate Review Network Customer MeetingMarch 29, 2010

  2. Welcome & Purpose Joe Harwood, VP Wholesale Customer Relations

  3. Welcome • Safety Moment • Meeting Logistics • Attendee Introductions

  4. Background • Current Transmission Rate • Approved by the FERC in 1996 • Based on 1994 Costs • “Stated” Rate that has not changed since 1996 • Transmission Rates recover operating costs of the transmission system and return on transmission investments • Since 1994, transmission improvements made to maintain adequate and reliable service • By managing costs over past 15 years, Duke Energy Carolinas has avoided requesting a change in the transmission rate • However, ……………

  5. Today’s Objectives • Purpose of the Meeting • Duke Energy Carolinas is preparing a change in its transmission tariff to be filed at the FERC • Want to engage and involve Transmission Customers in the process • Timeline • Late March 2010 – July 2010: Customer Meetings & Discussions • Possibly hold customer meetings/discussions at least monthly • Next meeting tentatively planned for April 26, 2010 • By August 31, 2010 – File OATT Formula transmission rate filing with FERC • By October 31, 2010 – FERC response to filing • November 1, 2010 – Effective date of new rates using formula • New rates in effect until May 31, 2011 • Thereafter rate year will be June 1 of calendar year through May 31 of following year • Begin Discussion to Reach Goal • Agreement with Transmission Customers related to proposed Transmission Tariff revisions • File a proposed settlement with the FERC to expedite the regulatory process

  6. Agenda • Welcome and Introductions ………………… Joe Harwood • Purpose of Meeting ………………………….. Joe Harwood • Transmission System Update …………….. Ed Ernst • Formula Rate Overview ……………………….. Jane McManeus • Lunch • Formula Rate Protocols……………………… Jane McManeus • Formula Rate Template …………………….. Paula Moulton • Next Steps and Closing …………………….. Charlotte Glassman

  7. Transmission System Update Ed Ernst – Director, Transmission Planning

  8. Transmission System • Duke Energy Carolinas system overview • Transmission system facts and figures • How we plan the Duke Energy Carolinas transmission system • Where we spend money on transmission • Significant transmission projects

  9. Duke Energy Carolinas System Overview

  10. Transmission System Facts and Figures • Summer Peak of approximately 20,000 MW • 21 interconnections with 9 neighboring control areas • 13,000 circuit miles of transmission • Transmission voltage levels of 44 kV, 69 kV, 100 kV, 161 kV, 230 kV, 525 kV • Number of stations on the transmission system • 175 transmission substations • 1534 delivery stations • 220 of the delivery stations are to munis and coops

  11. How we plan the Duke transmission system • Annually, perform an assessment and plan looking out ten years, with emphasis on first three to five years. • Plan the system to meet NERC and SERC Reliability Standards as well as to meet company planning guidelines • Perform assessments and studies with other utilities through SERC and other arrangements • Develop a Collaborative Transmission Plan for the Duke Energy Carolinas and Progress Energy Carolinas systems through the NC Transmission Planning Collaborative

  12. Where we spend money on transmission • Capacity- load growth driven • System upgrades to integrate new generation into the grid • Reliability and Integrity • Upgrades of equipment to deal with performance issues, aging infrastructure, end of life issues • Transmission service request

  13. Significant transmission projects • Upgrade of interconnection between Duke and TVA • 2007-2010 project • Increased capacity from 216 MVA to 600 MVA • Approximate total cost = $65M • Caesar 230 kV line Upgrade- west of Hendersonville, NC • 2010-2013 project • Reconductor 22 miles of existing transmission line • Approximate total cost = $43M • Static Var Compensator for Northern Region grid support • In service in 2007 • 300 MVAR capability • Approximate total cost = $30M • Swain County/Jackson County NC transmission reinforcements • 2006-2011 project • Approximate total cost = $58M • Haw River 100 kV line upgrade • 2008-2010 project • Rebuild 22 miles of existing transmission lines • Approximate total cost = $25M

  14. Significant transmission projects (continued) • Antioch Tie • 500/230 kV tie station • Completed in 1996 • Approximate total cost = $30M • 230/100 kV Autotransformer fleet • Spending to rewind existing autotransformers • Purchase of new autotransformers • Fleet has grown from 94 autotransformers to 98 autotransformers • Approximate spending since 1996 - $75M • Relaying Upgrades Program • Replace electromechancial relays with solid state relays • On going program at approximate $5M per year • Line rebuild integrity program • 2010 budgeted spend is approximately $10M • Dan River combined cycle transmission plant upgrades • 2008-2012 project • Rebuild 27 miles of existing 100 kV lines • Approximate total cost = $30M

  15. Formula Rate Overview Jane McManeus, Director Rates – Duke Energy Carolinas

  16. Change in Costs • Revenue requirement based on 1994 costs = $207M Revenue requirement based on 2008 costs = $244M • Primary driver of increase is higher investment in transmission plant: net plant grew from $0.8B to $1.2B • Transmission plant grew at approximately 3-4% per year over 14 years. • Depreciation expense has increased in conjunction with growth in transmission plant. • Depreciation rate change effective 2009 lowers annual depreciation expense about $12M per year. • O&M expenses have increased by about 1.5% per year. • Revenue credits offsetting revenue requirements have increased from $1M to $38M • Transmission average peak demand has grown from 16,730 MW to 18,434 MW.

  17. Determination of Revenue Requirements • Basic calculation is return on rate base + operating expenses • Rate base components: • Transmission plant balance less accumulated depreciation • Excludes generator step up transformers, interconnection facilities and <44KV facilities • Allocated general and intangible plant less accumulated depreciation • Transmission construction work in progress (CWIP) (specific projects) • Accumulated deferred income taxes associated with items included in revenue requirements • Working capital • Other rate base adjustments necessary to reflect funds supplied by investors • Contra AFUDC adjustments to properly reflect plant balances for wholesale jurisdiction

  18. Determination of Revenue Requirements (continued) • Return is determined by applying weighted average cost of capital percent to rate base • Cost of capital rate incorporates cost of debt and cost of equity (i.e. ROE) weighted in proportion to capital structure • Maintain option for incentive ROE if appropriate • Operating expenses: • Depreciation expense for transmission plant and allocated general/intangible plant • O&M expense, including transmission O&M and allocated A&G expense • Allocated general tax expense: • Property tax, payroll tax, other non-income taxes • Income taxes

  19. Determination of Revenue Requirements (continued) • Special items • Amortization of GridSouth costs over 5 years • Revenue credits: • Revenues received that offset costs included in revenue requirements, primarily non-firm and short term firm revenues for transmission service, and lease payments associated with transmission facilities • Losses: • If billing demands are stated at the customer meter (i.e. exit point of the transmission system), revenue requirements are grossed up to compensate for losses.

  20. Formula Rate • Determination of revenue requirements is stated as a formula that uses cost inputs from FERC Form 1 and company records. • The resulting revenue requirement is recomputed annually. • For point-to-point service, the annual revenue requirement is divided by calendar year average transmission system peak demand for long term firm service to determine a rate per KW. • For network service, individual customer load ratio share percentage is applied to annual revenue requirement. • Numerator of percentage is customer 12 month average (rolling) transmission demand coincident with Duke Energy Carolinas transmission peak; denominator is Duke Energy Carolinas 12 month average (rolling) transmission peak demand for long term firm service. • Revenue requirements and rates are billed initially using estimated annual revenue requirements and trued up to actual revenue requirements when known.

  21. Ancillary Services • Duke Energy Carolinas is reviewing current ancillary service revenue requirements to determine if sufficient to recover current costs

  22. Formula Rate Protocols Jane McManeus, Director Rates – Duke Energy Carolinas

  23. Formula Rate Protocols & Timeline Illustration • Duke Energy Carolinas will implement a formula methodology to calculate its transmission service rates for Network Integration Transmission Service and Point-to-Point Transmission Service. • The revenue requirements and rates will be recalculated annually using the approved formula and in accordance with the established formula protocols. The protocols are separated into the following categories: • Annual update process • Annual review procedures • Resolution of challenges

  24. Annual Update Process • Implementation year – annual transmission revenue requirement (ATRR) will be applicable to services on and after November 1, 2010 through May 31, 2011 • Subsequent years – ATRR will be applicable to services on and after June 1 of a given calendar year through May 31 of the subsequent calendar year • On or before May 15th of each year the ATRR and the PTP transmission rates will be recalculated. This represents the Annual Update for the upcoming rate year • The Annual Update will be posted to the OASIS website • An informational filing will be made with FERC • The date on which these events occur is the publication date • The Annual Update will include the true-up for the prior year ATRR • True up amount (including interest) increases or decreases ATRR for upcoming billing period

  25. Annual Review Procedures • Each Annual Update shall be subject to the Annual Review procedures • Interested parties will have up to 90 days after the publication date to serve information requests to Duke Energy Carolinas (i.e. Discovery Period) • Duke Energy Carolinas will respond to requests within 15 business days in most circumstances • Any interested party will have up to 120 days after the publication date to review calculations and notify Duke Energy Carolinas of any specific challenges • Preliminary challenges will be posted to the OASIS website

  26. Resolution of Challenges • Duke Energy will respond to parties making the preliminary challenges within 30 days after the end of the review period • For any preliminary challenges to the Annual Update not resolved, the interested party may make a formal challenge with FERC • Each Annual Update shall become final either 1)12 months from publication date if no challenge has been made and FERC has not initiated a proceeding, or 2) the date that FERC issues a final order in response to a Formal challenge

  27. Formula Rate Implementation Timeline Initial implementation: Rate Period is November 2010 through May 2011,

  28. Formula Rate Annual Review/Resolution of Challenges Timeline

  29. Formula Rate Template Paula Moulton, Rates Manager

  30. Next Steps & Closing Charlotte Glassman, Transmission Contracts Manager

  31. Additional Questions • Questions that have not been answered today or have not been asked should be submitted in writing. • All questions should go to Charlotte.Glassman@duke-energy.com • All questions should be submitted by April 12, 2010 – two weeks from today. • Duke Energy will endeavor to provide written responses by April 26, 2010. • All responses will be distributed to all who were invited to this meeting.

  32. Customer Input • How did this forum work? • Do you want to continue with this type of meeting? • How often should we meet? • Will April 26, 2010 work for most customers? • Should the second meeting be in person or via conference call?

  33. Questions and Discussion