1. Rate Design Indiana Industrial Energy Consumers, Inc. (INDIEC) Indiana Industrial Energy Consumers, Inc. (INDIEC) presented by Nick Phillips Brubaker & Associates, Inc. presented by Nick Phillips Brubaker & 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. Customer charge Facilities charge Demand charge Energy charge Basic Rate Components 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 Collect Class Revenues Total Class Revenues to be Collected e.g., Industrial Class Revenue Requirement = $175.4 million Total Class Revenues to be Collected e.g., Industrial Class Revenue Requirement = $175.4 million Recover Fixed Costs through Demand Charge ($/kW) Recover Variable Costs through Energy Charge ($/kWh) Recover Customer Costs through Customer Charge ($/month)

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

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

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

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

14. Seasonal Demand Charges Summer June-Sept Winter Oct-May First 10,000 kW$10.00$8.20 Additional kW$8.00$6.26

15. Seasonal Demand Charges Customer 1 Seasonal: Summer 1st 10,000 kW Add'l kW Cost above non-seasonal flat rate $ 52,080 40,000$10.00 $ 400,000 22,000$8.00176,000 $ 1,282,080 150,000 Demand Rate Annual Cost Winter 1st 10,000 kW Add'l kW 80,000$8.20656,000 8,000$6.2650,080 Total $1,230,000 Non-Seasonal Flat Rate

16. Seasonal Demand Charges Customer 2 Seasonal: Summer 1st 10,000 kW Add'l kW Savings compared to non-seasonal flat rate 91,200$ 40,000$10.00 400,000 40,000$8.00320,000 1,876,800240,000 $ $ Demand Rate Annual Cost Winter 1st 10,000 kW Add'l kW 80,000$8.20656,000 80,000$6.26500,800 Total $1,968,000 Non-Seasonal Flat Rate

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

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

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

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

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

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

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

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 Rates Demand Charges $8.20 Non-TOUTime-of-Use - - - - - OR - - - - - per kW of Maximum $8.77 per kW of On-Pk Demand Demand $5.96 Demand $2.63 per kW of Max Demand +

26. TOU Demand Charges Assumed Operating Demand 10,00010,000 kW Customer 3 12,00012,000 8,0008,000 PeakOff-Peak 10,00010,000 kW 12,00012,000 8,0008,000 PeakOff-Peak Customer 4 4,0004,0004,0004,000

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

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

29. Coincident Peak Demand 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 rate cases 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 Fuel and purchased power Environmental cost recovery Capacity cost recovery (CCR or PCRF) Conservation

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

33. Interruptible Service Salient 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 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 Service Conditions Requiring Interruption Inadequate generation capacity Underfrequency problems Economics Inadequate generation capacity Underfrequency problems Economics

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

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

37. Valuing Interruptibility Example 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 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. Varying amounts of notice – Day-ahead – 30-minute notice – 10 minute notice – Instantaneous Greater rate reductions for less notice Interruptible Rates Terms and Conditions

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

40. Real Time Pricing How 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 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 Pricing Considerations Price volatility – Hourly RTP prices are often tied 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 Price volatility – Hourly RTP prices are often tied 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 Pricing Energy 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 By mid-2007, state regulators must consider a requirement that utilities offer time-based rates to each customer class Time-based rates include RTP