Cross-Cutting Analytical
Assumptions for the 6th Power
Plan
July 1, 2008
1
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
2
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%
3
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%
Inputs to Discount Rate Calculation –
Real Cost of Capital
6%
5.20%
GDP Deflator
4.83%
5%
4.46%
4%
3.48%
3.14%
30 year Treasury
30 year fixed rate mortgage
3%
Long term AAA municipal bond
(Municipal and PUD cost of debt)
2.02%
2%
30 year Treasury+ 1% (Coop
utility cost of debt)
1%
Long term Baa corporate bond
(Business & IOU cost of debt)
0%
2010 - 2014 Average
5
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 – United
States. 2006. http://pages.stern.nyu.edu/~adamodar.
6
Discount Rate Calculation
Sector
7
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%
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?
8
Proposed Residential Sector
Sponsor Parameters
Customer
Wholesale Retail
Electric
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%
Proposed Commercial Sector
10
Sponsor Parameters
Customer
Wholesale Retail
Electric
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
Public & Private Commercial
Floor Area & Finance Costs
Fraction of new Commercial Floor Space by Ownership from FW Dodge Data
YEAR
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 Capital
LOCAL
STATE
FEDERAL MILITARY UNKNOW PRIVATE Grand
3.1%
4.0%
4.0%
4.0%
7.6%
7.6%
6.7%
11
Proposed Industrial* & Agricultural
Sectors
Sponsor Parameters
Customer
Wholesale Retail
Electric
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
12
upgrades financed at utility cost of capital
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
13
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”
14
Average Annual Distribution Losses
for PNW Retail Utilities
Line Losses
(Share of Total Sales)
14%
12%
10%
8%
6%
4%
2%
0%
N = 118 Utilities
Sales Weighted Average = 4.7%
Median = 5.7%
Geometric Mean = 5.2%
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”?
16
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
17
Shape of Transmission System Losses –
Now In ProCost Data File*
5.0%
4.5%
4.0%
3.5%
3.0%
2.5%
2.0%
1.5%
1.0%
0.5%
0.0%
Segment
Segment
Segment
Segment
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
18
*MC_and_Loadshape_6P.xls
1
2
3
4
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
$12.56
NA
PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$
19 adjusted to 2006$ using Handy-Whitman Index
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%
20
Assumed Transmission Financing
WACC
Share of Financing
Public
3.14%
5%
BPA
4.46%
75%
IOU
5.20%
20%
WACC
4.54%
100%
21
Estimated Value of Deferred
Transmission Cost
$60
$51.70
2006$ / KW-yr
$50
$40
$30
$29.42
$20
$23.10
$18.03 $16.60 $21.30
$18.80
$13.56
$9.87
$10
$4.12
22
PacifiCorp, PGE, SnohPUD & RTF Cost in 2000$
adjusted to 2006$ using Handy-Whitman Index
Av
er
ag
e
C
ur
re
nt
RT
F
PG
E
Pa
ci
fiC
or
p
al
.C
N
al
C
S.
vg
.
C
A
-A
PG
&E
SC
E
SD
G
&E
$0
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
23
PSE Results – First Year Cost
$250
$222
$200
$161
$150
$99
$100
$50
$0
PSE - Low
PSE - Average
PSE - High
All values in 2006$. Low and High computed as one standard deviation
from 10 yr average. 2000$ Adjusted to 2006$ using Handy-Whitman Index.
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%
25
PSE Results – Annualized Cost
$15
$13.36
2006$/ KW-yr
$9.67
$10
$5.97
$5
$0
PSE - Low
PSE - Average
PSE - High
All values in 2006$. 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
$76.17
$44.27
$24.70 $26.45
$21.26
$20.37 $12.56
All values in 2006$. 2000$ Adjusted to 2006$ using Handy-Whitman Index.
Assumed WACC = 4.33% based on 45% Public/55% IOU Financing
C
ur
re
nt
R
TF
ge
er
a
Av
U
D
oh
P
Sn
PG
E
ci
fiC
PS
Pa
-A
ve
r
ag
e
PS
I
or
p
$9.67
$5.81
E
PG
&E
L
$7.48
KC
P&
$80
$70
$60
$50
$40
$30
$20
$10
$0
C
PL
$/KW-year
Estimated Value of Deferred
Distribution Cost
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 - $23/ KW-yr
• Natural Gas Market Price Forecast – Use Medium Price
Forecast
• Electricity Price Forecast – Use High Capital Cost-High
CO2 as proxy for Market Price + “Avoidable” RPS Cost
29
Forecast Gas Prices at Henry HUB
20
Low
Med
High
AEO
ICF
18
Nominal$/MMBTU
16
14
12
10
8
6
4
2
0
2004
30
2008
2012
2016
2020
2024
2028
5th Plan Natural Gas Market Price
“Scenarios”
16.00
2004 Dollars Per MMBtu
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
1
5
9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77
Quarters
5th Plan Electricity Market Price “Scenarios” –
Constrained by FERC Cap
Comparison with Council's
On-Peak Electricity Price Forecast
300.00
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Council's Forecast
200.00
150.00
100.00
50.00
Sep-21
Sep-19
Sep-17
Sep-15
Sep-13
Sep-11
Sep-09
Sep-07
Sep-05
0.00
Sep-03
2004 $/MWh .
250.00
5th Plan Electricity Market Price
“Scenarios”
200.00
180.00
160.00
140.00
120.00
100.00
80.00
60.00
40.00
20.00
0.00
80%
70%
60%
50%
40%
30%
20%
10%
0%
Sep-21
Sep-19
Sep-17
Sep-15
Sep-13
Sep-11
Sep-09
Sep-07
Sep-05
Council's Forecast
Sep-03
2004 $/MWh .
Comparison with Council's Electricity Price
Forecast
90%
Which Market Price Forecast Should be Used for
“Illustrative” Determination of Cost
Effectiveness?
100
80
60
40
20
0
20
07
20
09
20
11
20
13
20
15
20
17
20
19
20
21
20
23
20
25
Real Market Price (2006$/MWH)
120
5th Plan Final Base
RPS HCAPTL HFUEL
HIGHCO2 HD
RPS HCAPTL HFUEL
HIGHCO2_70 HD
RPS HCAPTL HFUEL
VHCO2 HD
RPS HCAPTL HFUEL HD
Levelized Price of Future Market Price
Scenarios
90
80
70
60
50
40
30
20
10
0
5th Plan Final
Base
35
NORPS HCAPTL
RPS HCAPTL
RPS HCAPTL
HD
HFUEL HIGHCO2
HFUEL
HD
HIGHCO2_70 HD
RPS HCAPTL
HFUEL VHCO2
HD
RPS HCAPTL
HFUEL HD