1

Cross-Cutting Analytical Assumptions for the 6th Power

Plan

July 1, 2008

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

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%

Inputs to Discount Rate Calculation – Who Pays for New Resources

Entity or Item Reference Case

Low High

BPA share of public utility future generation resource supply

20% 10% 30%

Generation share of new resource additions 60% 50% 70%

Conservation share of new resource additions 40% 30% 50%

Utility/SBC share of conservation cost 60% 50% 70%

Consumer share of conservation cost 40% 30% 50%

Residential share of consumer cost of conservation 33% 30% 40%

Commercial and Industrial (i.e., business) share of consumer conservation cost

67% 60% 70%

5

Inputs to Discount Rate Calculation – Real Cost of Capital

2.02%

3.48%

4.83%

3.14%

4.46%

5.20%

0%

1%

2%

3%

4%

5%

6%

2010 - 2014 Average

GDP Deflator

30 year Treasury

30 year fixed rate mortgage

Long term AAA municipal bond(Municipal and PUD cost of debt)

30 year Treasury+ 1% (Cooputility cost of debt)

Long term Baa corporate bond(Business & IOU cost of debt)

6

Inputs to Discount Rate Calculation – Real Cost of Capital (2)

Category Mean Real Discount Rate

Standard Deviation

Number of Companies

Industrial 7.50% 3.20% 2,409

Commercial Companies 7.30% 4.70% 1,773

Commercial Property Owners 4.50% 0.90% 8

Commercial - Government Owned 3.30% 2.10% 25

Source: LBNL Technical Support Document for Distribution Transformers. Damodaran Online. The Data Page: Historical Returns on Stocks, Bonds, and Bills – UnitedStates. 2006. http://pages.stern.nyu.edu/~adamodar.

7

Discount Rate Calculation

Sector Reference Case

Low High

Residential Sector 3.9% 3.0% 5.0%

Industrial and Agricultural Sectors 7.5% 4.3% 10.7%

Commercial Sector 7.7% 7.0% 9.0%

Real Discount Rate for 6th Plan 5.0% 4.6% 5.4%

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 6th Plan?

Proposed Residential Sector

Sponsor Parameters Customer Wholesale Electric

Retail Electric

Natural Gas

Real After-Tax Cost of Capital 3.9% 4.4% 4.9% 5.0%

Financial Life (years) 15 1 1 1

Sponsor Share of Initial Capital Cost 40% 30% 30% 0%

Sponsor Share of Annual O&M 100% 0% 0% 0%

Sponsor Share of Periodic Replacement Cost

100% 0% 0% 0%

Sponsor Share of Administrative Cost 0% 50% 50% 0%

10

Proposed Commercial Sector

Sponsor Parameters Customer Wholesale Electric

Retail Electric

Natural Gas

Real After-Tax Cost of Capital 6.7% 4.4% 4.9% 5.00%

Financial Life (years) 10 1 1 1

Sponsor Share of Initial Capital Cost 50% 15% 35% 0%

Sponsor Share of Annual O&M 100% 0% 0% 0%

Sponsor Share of Periodic Replacement Cost

100% 0% 0% 0%

Sponsor Share of Administrative Cost 0% 50% 50% 0%

*Does not include utilities for transmission and distribution efficiency upgrades

11

Public & Private Commercial Floor Area & Finance Costs

Fraction of new Commercial Floor Space by Ownership from FW Dodge DataYEAR LOCAL STATE FEDERAL MILITARY UNKNOW PRIVATE Grand

2002 18% 5% 1% 0% 6% 70% 100%2003 22% 5% 2% 0% 4% 67% 100%2004 21% 4% 1% 1% 4% 70% 100%2005 14% 6% 2% 0% 0% 79% 100%2006 9% 4% 1% 0% 0% 86% 100%2007 12% 3% 2% 0% 0% 83% 100%

Grand Total 15% 4% 2% 0% 2% 77% 100%

Tax-Adjusted Real Cost of CapitalLOCAL STATE FEDERAL MILITARY UNKNOW PRIVATE Grand

3.1% 4.0% 4.0% 4.0% 7.6% 7.6% 6.7%

12

Proposed Industrial* & Agricultural Sectors

Sponsor Parameters Customer Wholesale Electric

Retail Electric

Natural Gas

Real After-Tax Cost of Capital 7.5% 4.4% 4.9% 5.0%

Financial Life (years) 10 1 1 1

Sponsor Share of Initial Capital Cost 50% 15% 35% 0%

Sponsor Share of Annual O&M 100% 0% 0% 0%

Sponsor Share of Periodic Replacement Cost

100% 0% 0% 0%

Sponsor Share of Admin Cost 0% 50% 50% 0%

*Investments in transmission and distribution efficiency upgrades financed at utility cost of capital

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 5th Plan

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”

Average Annual Distribution Losses for PNW Retail Utilities

0%

2%

4%

6%

8%

10%

12%

14%

N = 118 Utilities

Line

Los

ses

(Sha

re o

f Tot

al S

ales

)

Sales Weighted Average = 4.7%Median = 5.7%Geometric Mean = 5.2%

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 losses2 x 4.7% = 9.4%

Issue – How do we shape this hourly if we do not know hourly distribution system “loading”?

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

Shape of Transmission System Losses – Now In ProCost Data File*

0.0%0.5%1.0%1.5%2.0%2.5%3.0%3.5%4.0%4.5%5.0%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Segment 1Segment 2Segment 3Segment 4

*MC_and_Loadshape_6P.xls

19

Value of Deferred Transmission and Distribution

• Current RTF Assumptions– Distribution = $26.45/KW-yr (2006$)– Transmission = $4.12/KW-yr (2006$)

Company Transmission (2006$/KW-yr)

Distribution (2006$/KW-yr)

Total ($/KW-yr)

PacifiCorp $29.42 $76.17 $105.59

PGE $9.87 $20.37 $30.14

SnohPUD NA $12.56 NA

PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$adjusted to 2006$ using Handy-Whitman Index

20

Value of Deferred Transmission

Company/Area Average $/KW Annualized $/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

Assumed Transmission Financing

WACC Share of Financing

Public 3.14% 5%

BPA 4.46% 75%

IOU 5.20% 20%

WACC 4.54% 100%

22

Estimated Value of Deferred Transmission Cost

$51.70

$13.56

$21.30

$9.87 $4.12

$18.03 $16.60

$29.42

$18.80 $23.10

$0

$10

$20

$30

$40

$50

$60

SDG&ESCE

PG&E

CA - Avg

.

S. Cal

N. Cal

PacifiC

orp PGE

Averag

e

Curren

t RTF

2006

$ / K

W-y

r

PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$adjusted to 2006$ using Handy-Whitman Index

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

PSE Results – First Year Cost

$161

$222

$99

$0

$50

$100

$150

$200

$250

PSE - Low PSE - Average PSE - High

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

Assumed Distribution Financing

WACC Share

Muni/PUD 3.14% 40%

Coop 4.46% 5%

IOU 5.20% 55%

BPA 4.46% 0%

Weighted 4.33% 100%

PSE Results – Annualized Cost

$5.97

$13.36

$9.67

$0

$5

$10

$15

PSE - Low PSE - Average PSE - High

2006

$/ K

W-y

r

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

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

Estimated Value of Deferred Distribution Cost

$7.48

$76.17

$26.45$12.56

$44.27

$21.26

$5.81 $9.67

$20.37$24.70

$0$10$20$30$40$50$60$70$80

CPL

KCP&LPG&E

PSI

PSE - Ave

rage

PacifiC

orp PGE

SnohP

UD

Avera

ge

Curren

t RTF

$/K

W-y

ear

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

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 CO2

as proxy for Market Price + “Avoidable” RPS Cost

30

Forecast Gas Prices at Henry HUB

02468

101214161820

2004 2008 2012 2016 2020 2024 2028

Nom

inal

$/M

MB

TU

Low MedHighAEOICF

5th Plan Natural Gas Market Price “Scenarios”

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

Quarters

2004

Dol

lars

Per

MM

Btu

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

Comparison with Council's

On-Peak Electricity Price Forecast

0.00

50.00

100.00

150.00

200.00

250.00

300.00

Sep-

03

Sep-

05

Sep-

07

Sep-

09

Sep-

11

Sep-

13

Sep-

15

Sep-

17

Sep-

19

Sep-

21

2004

$/M

Wh

.

100%90%80%70%60%50%40%30%20%10%0%Council's Forecast

5th Plan Electricity Market Price “Scenarios”

Comparison with Council's Electricity Price

Forecast

0.0020.0040.0060.0080.00

100.00120.00140.00160.00180.00200.00

Sep-

03

Sep-

05

Sep-

07

Sep-

09

Sep-

11

Sep-

13

Sep-

15

Sep-

17

Sep-

19

Sep-

21

2004

$/M

Wh

.

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

Council's Forecast

Which Market Price Forecast Should be Used for “Illustrative” Determination of Cost

Effectiveness?

0

20

40

60

80

100

120

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

Rea

l Mar

ket P

rice

(200

6$/M

WH

)

5th Plan Final Base

RPS HCAPTL HFUELHIGHCO2 HDRPS HCAPTL HFUELHIGHCO2_70 HDRPS HCAPTL HFUELVHCO2 HDRPS HCAPTL HFUEL HD

35

Levelized Price of Future Market Price Scenarios

0

10

20

30

40

50

60

70

80

90

5th Plan FinalBase

NORPS HCAPTLHD

RPS HCAPTLHFUEL HIGHCO2

HD

RPS HCAPTLHFUEL

HIGHCO2_70 HD

RPS HCAPTLHFUEL VHCO2

HD

RPS HCAPTLHFUEL HD