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
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