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Rocky Mountain Power - Utah

Rocky Mountain Power - Utah. Workgroup III Allocation Factors. Presented by UTAH INDUSTRIAL ENERGY CONSUMERS Salt Lake City, Utah August 12, 2010. Rocky Mountain Power - Utah. Utah Jurisdiction Monthly Load Shape. 1998. YE Sep 2007. 2008. Test Year Ending June 2010. PEAK MONTHS.

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Rocky Mountain Power - Utah

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  1. Rocky Mountain Power - Utah Workgroup III Allocation Factors Presented by UTAH INDUSTRIAL ENERGY CONSUMERS Salt Lake City, Utah August 12, 2010

  2. Rocky Mountain Power - Utah Utah Jurisdiction Monthly Load Shape 1998 YE Sep 2007 2008 Test Year Ending June 2010 PEAK MONTHS Utah Industrial Energy Consumers

  3. Rocky Mountain Power - Utah PacifiCorp Monthly Load Shape 1990 2007 2008 Test Year Ending June 2010 PEAK MONTHS Utah Industrial Energy Consumers

  4. Rocky Mountain Power - Utah “ Based on this comparison, we can see that the mean monthly coincident peaks of the months of June, July and August are not significantly different from one another but are significantly different from the rest of the months. The means of these months are significantly higher than the rest of the months except September, which is statistically the same as June. ” Docket No. 09-035-23 DPU Exhibit 15.0R, Page 8 Dr. Abdinasir Abdulle November 12, 2009 Summer peak demands are significantly different from demands in other months. Utah Industrial Energy Consumers

  5. Rocky Mountain Power - Utah Net Power Costs in the Summer Average Nearly 40% Higher than in the Winter *Includes Morgan Stanley seasonal purchase at $84/MWhr Source: Exhibit RMP _ GND-1R, Docket No. 09-035-23 Utah Industrial Energy Consumers

  6. Rocky Mountain Power - Utah Allocation methods may vary between JAM and class COSS. “ I agree that allocation factors may differ [between JAM and class COSS] as long as the underlying cost classification is preserved. For example, if a cost item is classified as demand-related in the jurisdictional allocation model it must be classified as demand-related in the COS model also. This preserves the underlying rationale for cost causation. With this in mind, allocation methods may vary depending on the unique circumstances in the RMP COS model compared to that in the jurisdictional allocation model. For example, certain demand-related costs may be allocated to each jurisdiction using a 12CP method in the JAM. In the RMP COS model, these same demand-related costs may be allocated to the customer classes based on a 3CP or similar approach reflecting the pronounced summer peak in the RMP system. ” Rebuttal Testimony of Joseph Mancinelli Docket No. 09-035-23 DPU Exhibit 15.0R, Pages 12-13 November 12, 2009 Utah Industrial Energy Consumers

  7. Rocky Mountain Power - Utah There is good reason to use summer peak loads when allocating among classes in Utah. “ Using the 12 CP approach in the RMP COS may align well with JAM but does not consider seasonality, which is more pronounced on the RMP system than the greater PacifiCorp system. Use of the 12 CP in the RMP COS does not accentuate seasonality in the cost of service analysis and the corresponding rates. To improve the summer/winter cost differential it may be appropriate to allocate demand related costs in the RMP COS model based on a 3 or 4 CP. ” Surrebuttal Testimony of Joseph Mancinelli Docket No. 09-035-23 DPU Exhibit 5.0SR, Page 10 November 30, 2009 Utah Industrial Energy Consumers

  8. Rocky Mountain Power - Utah Other Facts Concerning Class Allocations • Class allocations and jurisdictional allocations of generation fixed costs and variable costs are not currently the same and haven’t been the same for a number of years • The Utah Commission has never specifically adopted the allocations of generation fixed and variable costs currently being used in class allocations Utah Industrial Energy Consumers

  9. Rocky Mountain Power - Utah The 75% Demand/25% Energy weighting is the result of “compromise” among states – not the result of anytechnical analysis. “The choice of the 75% demand 25% energy classification for generation and transmission plant was the last allocation decision made by PITA after the merger. The PITA analysis indicated that a wide range of demand and energy classification could be supported on a technical basis. The demand energy classification was the swing issue employed to balance the sharing of merger benefits between all the states and 75% demand 25% energy was selected because it produced an overall cost allocation result that was acceptable to all the states. ” RMP’s Response to UIEC Data Request 10.18 Docket No. 09-035-23 Utah Industrial Energy Consumers

  10. Rocky Mountain Power - Utah The Commission has never adopted the JAM allocations for class cost of service purposes. “ Regarding the issue of the impact of the Stipulation and the Revised Protocol on customer classes, the Committee, PacifiCorp and UAE agree the record in this docket is not fully developed on this issue and the Order in this case should not try to resolve it. We concur. We further conclude the Revised Protocol only addresses inter-jurisdictional cost allocation which means class cost of service will be dealt with in other dockets such as general rate cases. ” Utah PSC Docket No. 02-035-04 at page 40Order Issued September 14, 2004 Utah Industrial Energy Consumers

  11. Rocky Mountain Power - Utah Fixed Costs and Variable Costsare Inversely Related Source: PacifiCorp 2008 IRP, Page 104 CombustionTurbine CombinedCycle PulverizedCoal Annual Fixed Cost/kW Variable Cost/kWh Annual Hours of Generation when: CC is more economical than CT PC is more economical than CC $70 10.0¢ $130 6.2¢ 1,600 $290 2.6¢ 4,400 Utah Industrial Energy Consumers

  12. Rocky Mountain Power - Utah 12CP with 75/25 Demand/Energy WeightingResults in an Inconsistent Allocation ofFixed and Variable Costs Source: Exhibit UIEC____(MEB-35R) Docket No. 09-035-23 Variable Costs Fixed Costs 140 140 120 120 100 100 80 80 Fuel Cost/kWhr $ Net Plant/kW 60 60 40 40 20 20 0 0 Total Residential Transmission Total Residential Transmission Utah Schedule 1 Schedule 9 Utah Schedule 1 Schedule 9 Utah Industrial Energy Consumers

  13. Rocky Mountain Power - Utah Allocations of Fixed and Variable Costs should be Consistent with the Facts and Equitable to All Customers Consistent Approaches • Utility systems are built to serve the total load on a least cost basis and all customers should share in the fixed costs in proportion to their peak demands and in the variable costs in proportion to their energy. • Low load factors customers should get below average fixed costs because less base load is needed to serve them, but above average variable costs. High load factor customers should get above average fixed costs because more base load is needed to serve them, but below average variable costs. Energy Weighting Methods • The 12CP - 75/25 method allocates above average fixed costs to high load factor customers but does not let them have the below average variable costs to which they are entitled. Utah Industrial Energy Consumers

  14. Rocky Mountain Power - Utah Allocation of Fixed Costs on the Basis of Energy Consumption Burdens High Load Factor Customers High LoadFactorCustomer A Low LoadFactorCustomer B Customer Characteristics Total Demand - Units - Percent Energy - Units - Percent Load Factor Allocation of Fixed Costs On Demand On Energy Overcharge to High Load Factor Customer 2,000100.0% 900,000100.0% 62% $10,000$10,000 1,00050.0% 600,00066.7% 82% $5,000$6,670 $1,670 1,00050.0% 300,00033.3% 41% $5,000$3,330 Utah Industrial Energy Consumers

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