1. 1 Cross-Cutting Analytical Assumptions for the 6 th Power Plan July 1, 2008

2. 2 Power Plan Required Analytical Inputs Discount Rate Cost of capital Share of conservation cost financed and by whom Transmission and Distribution System Losses Value of Deferred Transmission and Distribution System Expansion Forecast Future Electricity and Natural Gas Prices

3. 3 Discount Rate Used to compute the present value of future costs and benefits Recent Council Policy has been to use the corporate perspective –Tax-adjusted cost of capital of the decision makers –This varies depending upon the mix of decision makers and forecast future economic conditions Discount Rate in Prior Plans – 3% to 4.75%

4. Inputs to Discount Rate Calculation – Who Pays for New Resources Entity or ItemReference Case LowHigh BPA share of public utility future generation resource supply 20%10%30% Generation share of new resource additions60%50%70% Conservation share of new resource additions40%30%50% Utility/SBC share of conservation cost60%50%70% Consumer share of conservation cost40%30%50% Residential share of consumer cost of conservation33%30%40% Commercial and Industrial (i.e., business) share of consumer conservation cost 67%60%70%

5. 5 Inputs to Discount Rate Calculation – Real Cost of Capital

6. 6 Inputs to Discount Rate Calculation – Real Cost of Capital (2) CategoryMean Real Discount Rate Standard Deviation Number of Companies Industrial7.50%3.20%2,409 Commercial Companies7.30%4.70%1,773 Commercial Property Owners4.50%0.90%8 Commercial - Government Owned3.30%2.10%25 Source: LBNL Technical Support Document for Distribution Transformers. Damodaran Online. The Data Page: Historical Returns on Stocks, Bonds, and Bills – United States. 2006. http://pages.stern.nyu.edu/~adamodar.

7. 7 Discount Rate Calculation SectorReference Case LowHigh Residential Sector3.9%3.0%5.0% Industrial and Agricultural Sectors7.5%4.3%10.7% Commercial Sector7.7%7.0%9.0% Real Discount Rate for 6th Plan5.0%4.6%5.4%

8. 8 Cost of Conservation Financing Virtually all utility or system benefits charge conservation acquisitions are “paid for” out of current rate revenues (i.e., they are not financed) Bonneville may borrow a portion (<50%) conservation program expenditures What should we assume for the 6 th Plan?

9. Proposed Residential Sector Sponsor ParametersCustomerWholesale Electric Retail Electric Natural Gas Real After-Tax Cost of Capital3.9%4.4%4.9%5.0% Financial Life (years)15111 Sponsor Share of Initial Capital Cost40%30% 0% Sponsor Share of Annual O&M100%0% Sponsor Share of Periodic Replacement Cost 100%0% Sponsor Share of Administrative Cost0%50% 0%

10. 10 Proposed Commercial Sector Sponsor ParametersCustomerWholesale Electric Retail Electric Natural Gas Real After-Tax Cost of Capital6.7%4.4%4.9%5.00% Financial Life (years)10111 Sponsor Share of Initial Capital Cost50%15%35%0% Sponsor Share of Annual O&M100%0% Sponsor Share of Periodic Replacement Cost 100%0% Sponsor Share of Administrative Cost0%50% 0% * Does not include utilities for transmission and distribution efficiency upgrades

11. 11 Public & Private Commercial Floor Area & Finance Costs

12. 12 Proposed Industrial* & Agricultural Sectors Sponsor ParametersCustomerWholesale Electric Retail Electric Natural Gas Real After-Tax Cost of Capital7.5%4.4%4.9%5.0% Financial Life (years)10111 Sponsor Share of Initial Capital Cost50%15%35%0% Sponsor Share of Annual O&M100%0% Sponsor Share of Periodic Replacement Cost 100%0% Sponsor Share of Admin Cost0%50% 0% * Investments in transmission and distribution efficiency upgrades financed at utility cost of capital

13. 13 Impact of Changes Increases cost of “consumer” financing for Agriculture, Commercial and Industrial (8% vs 4.0%) However, this is mitigated by the increase in discount rate which reduces the impact of future interest payments Slightly decreases cost of “consumer” financing for residential (3.9% vs 4.0%) However, increase in discount rate will make “long lived” shell measure less attractive than in 5 th Plan

14. 14 Distribution System Losses RTF adopted 5% as estimate of Average Annual Distribution System Losses in 1999 – based on prior Council Plans RTF asked staff to review “annual” loss data to determine whether 5% assumption should be retained Implementation of “shaped distribution” system losses may be problematic do to absence of data needed to estimate “hourly distribution system loading”

15. Average Annual Distribution Losses for PNW Retail Utilities Sales Weighted Average = 4.7% Median = 5.7% Geometric Mean = 5.2%

16. 16 Shape of Distribution System Losses Lazar Proposal –Total losses = 4.7% –Assume “no load” losses are 1% –Average “load losses” = 3.7% Load Losses = 2x average losses 2 x 4.7% = 9.4% Issue – How do we shape this hourly if we do not know hourly distribution system “loading”?

17. 17 Transmission System Losses Prior Plan Used 2.5% Review of WECC System Modeling Appears to Suggest Average Transmission Losses are closer to 4.0% RTF Agreed to Use “Shaped Hourly Losses” ProCost Modified to Use Shaped Transmission (and Distribution) System Losses

18. 18 Shape of Transmission System Losses – Now In ProCost Data File* * MC_and_Loadshape_6P.xls

19. 19 Value of Deferred Transmission and Distribution Current RTF Assumptions –Distribution = $26.45/KW-yr (2006$) –Transmission = $4.12/KW-yr (2006$) CompanyTransmission (2006$/KW-yr) Distribution (2006$/KW-yr) Total ($/KW-yr) PacifiCorp$29.42$76.17$105.59 PGE$9.87$20.37$30.14 SnohPUDNA$12.56NA PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$ adjusted to 2006$ using Handy-Whitman Index

20. 20 Value of Deferred Transmission Company/AreaAverage $/KWAnnualized $/KW-yr* SDG&E$312$18.80 SCE$859$51.70 PG&E$225$13.56 Cal$300$18.03 S. Cal$276$16.60 N. Cal$354$21.30 *All values in 2006$. Assumes WACC = 4.54%

21. 21 Assumed Transmission Financing WACCShare of Financing Public3.14%5% BPA4.46%75% IOU5.20%20% WACC4.54%100%

22. 22 Estimated Value of Deferred Transmission Cost PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$ adjusted to 2006$ using Handy-Whitman Index

23. 23 PSE Distribution Cost Estimate Methodology “ Color-coded” 10 years (1990 – 2000) of capital investments in distribution system –Excluded Investments needed to maintain current system –Excluded Investments needed to provide new service –Included Investments needed to reinforce existing system to handle increased demand

24. PSE Results – First Year Cost All values in 2006$. Low and High computed as one standard deviation from 10 yr average. 2000$ Adjusted to 2006$ using Handy-Whitman Index.

25. 25 Assumed Distribution Financing WACCShare Muni/PUD3.14%40% Coop4.46%5% IOU5.20%55% BPA4.46%0% Weighted4.33%100%

26. PSE Results – Annualized Cost All values in 2006$. 2000$ Adjusted to 2006$ using Handy-Whitman Index. Assumed WACC = 4.33% based on 45% Public/55% IOU Financing

27. Other Estimates of the Value of Deferred Distribution Source: Energy and Environmental Economics and PEA. Costing Methodology for Electric Distribution System Planning. 11/9/2000

28. Estimated Value of Deferred Distribution Cost All values in 2006$. 2000$ Adjusted to 2006$ using Handy-Whitman Index. Assumed WACC = 4.33% based on 45% Public/55% IOU Financing

29. 29 Recommendations Distribution System Losses – Retain 5% Assumption –What about “shaping”? Transmission System Losses – Use Hourly Losses (Increases average from 2.5 to 3.9% for “System Load Shape) Distribution System Deferred Cost - $25/ KW-yr Transmission System Deferred Cost - $23/ KW-yr Natural Gas Market Price Forecast – Use Medium Price Forecast Electricity Price Forecast – Use High Capital Cost-High CO 2 as proxy for Market Price + “Avoidable” RPS Cost

30. 30 Forecast Gas Prices at Henry HUB

31. 5 th Plan Natural Gas Market Price “Scenarios”

32. 5 th Plan Electricity Market Price “Scenarios” – Constrained by FERC Cap

33. 5 th Plan Electricity Market Price “Scenarios”

34. Which Market Price Forecast Should be Used for “Illustrative” Determination of Cost Effectiveness?

35. 35 Levelized Price of Future Market Price Scenarios