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Rate Design

Indiana Industrial Energy Consumers, Inc. (INDIEC). Rate Design. presented by Nick Phillips Brubaker & Associates, Inc. Overview. Major rate design criteria Basic rate components Demand and energy charge variations Other rate design features Adjustment clauses

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Rate Design

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  1. Indiana Industrial Energy Consumers, Inc. (INDIEC) Rate Design presented by Nick PhillipsBrubaker & Associates, Inc.

  2. Overview • Major rate design criteria • Basic rate components • Demand and energy charge variations • Other rate design features • Adjustment clauses • Alternatives to firm service

  3. $ $ $ Major Rate Design Criteria • Reflect cost causation • Equity • Revenue stability • Send appropriate price signals • Control or reduce system costs • Promote efficient use of existing assets

  4. Basic Rate Components • Customer charge • Facilities charge • Demand charge • Energy charge Customer Charge Demand Charge Energy charge

  5. Customer and Facilities Charges • Customer Charge • Flat fee per month • Covers typical service drop, metering, billing • Facilities Charge • Per kW monthly charge • Sometimes used to recover distribution plant costs

  6. Demand Charge • Recovers fixed costs • Investment in plant • Return on investment • Carrying costs • Assessed per kW (electric)

  7. Energy Charge • Recovers variable costs • Fuel costs • Variable plant operation and maintenance costs • Sometimes used to recover fixed costs • Assessed per kWh or per MWh (electric)

  8. Demand Charge Variations • Flat • Declining block • Seasonally differentiated • Demand ratchet

  9. Rate Design to CollectClass Revenues Total Class Revenues to be Collected e.g., Industrial Class Revenue Requirement = $175.4 million Recover Variable Costs through Energy Charge ($/kWh) Recover Customer Costs through Customer Charge ($/month) Recover Fixed Costs through Demand Charge ($/kW)

  10. Recover Fixed Costs through Demand Charge ($/kW) Recover Customer Costs through Customer Charge ($/month) Recover Fixed Costs through Demand Charge ($/kW) Recover Variable Costs through Energy Charge ($/kWh) Recover Fixed Costs through Demand Charge ($/kW) Rate Design to CollectClass Revenues - Unbundled Total Class Revenues to be Collected Production $ Transmission $ Distribution $

  11. Demand By Month MW Customer 1 Annual Billing Demand = 150,000 kW 20 10 0 J F M A M J J A S O N D MW Customer 2 Annual Billing Demand = 240,000 kW 20 10 0

  12. Declining Block Demand ChargesCustomer 1 Demand Rate Annual Cost 150,000 $8.20 Flat Rate: $ 1,230,000 Multiple BlockDemand 1st 10,000 kW $ 1,080,000 120,000 $9.00 Add'l kW 184,000 30,000 $6.15 $ 1,264,000 Total 150,000 Cost above flat rate $ 34,000

  13. Declining Block Demand ChargesCustomer 2 Demand Rate Annual Cost $ 1,968,000 240,000 $8.20 Flat Rate: Multiple Block Demand: 1st 10,000 kW $ 1,080,000 120,000 $9.00 Add'l kW 738,000 120,000 $6.15 Total 240,000 $ 1,818,000 Savings compared to flat rate $ 150,000

  14. Seasonal Demand Charges

  15. Seasonal Demand ChargesCustomer 1 Demand Rate Annual Cost $ 1,230,000 Non-Seasonal Flat Rate Seasonal: Summer 40,000 $10.00 $ 400,000 1st 10,000 kW 22,000 $8.00 176,000 Add'l kW Winter 80,000 $8.20 656,000 1st 10,000 kW Add'l kW 8,000 $6.26 50,080 Total 150,000 $ 1,282,080 Cost above non-seasonal flat rate $ 52,080

  16. Seasonal Demand ChargesCustomer 2 Demand Rate Annual Cost $ 1,968,000 Non-Seasonal Flat Rate Seasonal: Summer 40,000 $10.00 $ 400,000 1st 10,000 kW 40,000 $8.00 320,000 Add'l kW Winter 80,000 $8.20 656,000 1st 10,000 kW Add'l kW 80,000 $6.26 500,800 Total 240,000 $ 1,876,800 Savings compared to non-seasonal flat rate $ 91,200

  17. Demand Ratchet Establishes a minimum level of kW demand based on demand established in a prior period

  18. Demand RatchetsFormat Rate A. 60% Ratchet 60% of highest kW last 12 months $7.68 60% of highest summer kW last 12 months 7.93 60% of highest summer kW last 36 months 7.42 Rate B. 90% Ratchet 90% of highest kW last 12 months $6.84 90% of highest summer kW last 12 months 7.04 90% of highest summer kW last 36 months 6.67

  19. Impact of 60% SummerDemand Ratchet Customer 3 30 25 20 Ratcheted Demand = 15 MW 15 MW 10 5 0 J F M A M J J A S O N D Prior Summer Customer 4 30 25 Ratcheted Demand = 12 MW 20 15 MW 10 5 0 Prior J F M A M J J A S O N D Summer

  20. Impact of Demand Ratchet Rate Annual Cost Demand Customer 3 $8.20 No ratchet 189,000 1,549,800 $ $7.93 60% ratchet 209,000 1,657,700 Additional Cost 107,900 $ Customer 4 $8.20 240,000 No ratchet 1,968,000 $ $7.93 240,000 60% ratchet 1,903,200 Benefit 64,800 $

  21. Energy Charge Variations Formats Base Rate FCA* Total Option A:All Fuel in FCA 0.543¢ 1.457¢ 2.000¢ Option B:With 1.5¢ ofFuel Embedded 2.000¢ 2.043¢ -0.043¢ Option C:No FCA 2.000¢ 2.000¢ ---- *Fuel Cost Adjustment

  22. Other Rate Design Features • Voltage Differentiated Rates • Time Differentiated Rates • Coincident Peak Rates

  23. One Rate Demand Charge $12.00 Delivery Voltage Credits: $3.00 Primary Transmission $5.63 Voltage Differentiated Rates Separate Rates Secondary $12.00 Primary $ 9.00 OR Subtransmission/ Transmission $ 6.37

  24. Time Differentiated Rates • Typical demand charges are based on non-coincident peak demands • Utilities size shared facilities to meet the maximum system demand • Generation • Bulk transmission • On-peak use is a better price signal

  25. Time Differentiated RatesDemand Charges Non-TOU Time-of-Use $8.77 per kW of On-Pk Demand - - - - - OR - - - - - $8.20 per kW of $5.96 per kW of On-Pk Maximum Demand Demand + $2.63 per kW of Max Demand

  26. TOU Demand ChargesAssumed Operating Demand Customer 3 Customer 4 kW kW 12,000 12,000 10,000 10,000 8,000 8,000 4,000 4,000 Peak Off-Peak Peak Off-Peak

  27. TOU Demand ChargesCustomer Impacts Rate Annual Cost Demand Customer 3 $8.20 Non-TOU Charge 120,000 984,000 $ $8.77 TOU Charge 120,000 1,052,400 Additional Cost 68,400 $ Customer 4 1,180,800 $8.20 144,000 Non-TOU Charge $ $8.77 120,000 TOU Charge 1,052,400 Savings 128,400 $

  28. Time Differentiated RatesEnergy Charges Non-TOU Time-of-Use 0.600¢ per kWh of On-Pk Energy 0.543¢ per kWh of Metered Energy 0.484¢ per kWh of Off-Pk Energy

  29. Coincident PeakDemand Charges • Coincident peak = customer demand at the time of the utility’s system peak • Refinement of on-peak pricing • Requires advanced metering • Used for unbundled transmission service

  30. Adjustment Clauses • Track cost changes • Monthly, semi-annually, annually • Avoid frequent base ratecases • Automatic vs. non-automatic • May vary between rate schedules

  31. Examples of Adjustment Clauses • Fuel and purchased power • Environmental cost recovery • Capacity cost recovery (CCR or PCRF) • Conservation

  32. MENU Regulated Alternatives to “Plain Vanilla” Firm Service • Interruptible Service • Real Time Pricing

  33. Interruptible ServiceSalient Characteristics • Lower quality of service • Curtailment may be controlled by a third party (e.g., RTO, utility or supplier) • No production capacity required • No production capacity costs • Number, duration and annual hours of interruption usually limited

  34. Interruptible ServiceConditions Requiring Interruption • Inadequate generation capacity • Underfrequency problems • Economics

  35. OFF Interruptible ServiceBenefits • Planning reserves • Operating reserves (10 minute response) • Spinning reserves (instantaneous response) • Market opportunities

  36. Interruptible RatesPricing Firm Interruptible Energy Charge/kWh 2.500¢ 2.500¢ Demand Charge/kW* $6.37 $3.18 or Incremental + 10% Energy Energy Charge/kWh* 2.500¢ Demand Charge/kW* $6.37 $0.00 *Subtransmission delivery

  37. Valuing InterruptibilityExample of Calculation Method • Relies on the utility’s avoided cost of a peaking unit • Demand charge reduction based on the peaking unit’s levelized investment cost, including carrying costs • More hours available for interruption yields a larger rate reduction

  38. Interruptible RatesTerms and Conditions • Varying amounts of notice • Day-ahead • 30-minute notice • 10 minute notice • Instantaneous • Greater rate reductions forless notice

  39. Interruptible RatesTerms and Conditions • Annual interruption hours are often limited • Notice period to convert to firm service • Noncompliance penalty • Buy-through provision

  40. Real Time PricingHow Is It Different? • Traditional firm rates recover average embedded cost of service • RTP prices vary by hour to reflect current/projected marginal system costs • Simulates competitive market

  41. Real Time PricingConsiderations • Price volatility • Hourly RTP prices are oftentied to market clearing power prices (natural gas costs) • Large adders for shortage costs in critical peak periods • Customer bears more price risk • Customer must respond effectively to price signals

  42. Real Time PricingEnergy Policy Act of 2005 • By mid-2007, state regulators must consider a requirement that utilities offer time-based rates to each customer class • Time-based rates include RTP

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