Draft
Appendix F.6- RMATS Economic Comparison Tables
Purpose
The purpose of the economic comparison tables is to compare the value of resource and
transmission expansion alternatives on a screening study basis. The comparison takes into
account the production (fuel and other variable O&M) costs of each alternative, the capital
investment requirements in new resources and transmission, and associated annualized fixed
costs. The annualized costs of each alternative are then compared to Reference Cases to establish
annual net savings or costs.
Economic Comparison Tables
The data in the economic comparison tables were developed in three steps: 1) determine
production costs using ABB Market Simulator 2) determine total initial capital investment
requirements; 3) calculate annualized costs associated with each required investment.
Step 1:
Production costs were determined using ABB Market Simulator and described in detail in
Chapter 2.
Step 2:
Total initial capital investments requirements of each alternative are shown in the column labeled
“Initial Investment” and are grouped into generating resource and transmission investments.
Resource costs include wind, gas and coal capital
investment amounts as well as associated transmission
integration costs of the above mentioned resource
additions in the Rocky Mountain States (Table F.6.1,
lines 5:11).
Table F.6. 1: Sample Table
Initial
Investment
1
2
3
4
5
6
In the case of Recommendation 2, the resource costs
are adjusted downward to the extent that the Rocky
Mountain region builds resources for export (Table
F.6.1, line 12).
Resource capital investment requirements are based on
the development and construction cost estimates by
resource category from draft Northwest Power and
Conservation Council’s (NWP&CC) reports, “New
Resource Characterization for the Fifth Power Plan”
and from a California Energy Commission report on
renewable resources.
Transmission costs include capital investment
amounts associated with transmission lines as well as
any required customized equipment costs (Table F.6.1,
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Production Costs (Fuel & Other VOM)
Change from All Gas Case [Column A]
Change from IRP- Based Case [Column B]
Resource Costs:
RM Resource Additions Capex
Wind
Gas thermal
Coal thermal
Incremental Transmission Integration Capex
RM Resource Capex Sub Total
Adj. Outside RM Resource Additions Capex
Other RM Costs
Incremental Capital Charge @ 10%
Incremental Fixed O&M
Wind "wear and tear"
Subtotal Other RM Costs
Adj. Other Costs Outside RM
Total Resource Costs
3,766
373
7,857
311
12,306
(2,257)
Transmission Costs:
Incremental Line Capex
Customized Equipment Capex
RM Transmission Capex Sub Total
3,872
393
4,265
26
27
28
Incremental Fixed O&M
Incremental Capital Charge @ 10%
RM Transmission Costs
4,265
29
30
Annualized Costs
22
23
24
25
31
32
Total Initial Investment
Annual Net (Savings)/Cost from All Gas Case
34 Annual Net (Savings)/Cost from IRP- Based Case
14,315
33
Appendix F
78
Draft
lines 21:24). Transmission costs were estimated on a line by line basis using historical data and
professional judgment of the members of the RMATS Resource and Transmission Addition
Work Groups.
Step 3:
Annualized costs associated with each alternative are shown in the column labeled
“Representative Year”. In this column, the production costs developed by ABB Market
Simulator (as described in Chapter 2) are combined with annual fixed costs associated with the
total investment requirements of each alternative.
Table F.6. Sample Table
The production costs are fuel and other
variable O&M and are compared to the
Reference case’s production costs (Table
F.6.2, lines 1:3).
Annualized fixed costs include resource and
transmission capital charges associated with
initial investment and fixed O&M (Table
F.6.1, lines 13:19 and lines 26:28).
1
2
3
4
5
6
7
8
9
10
11
12
Annual capital charges are shown as a
percentage of the initial investment. In
general, annual capital charge is calculated
by discounting back at the rate of the cost of
capital inflation adjusted (real) streams of
depreciation, return on capital, property and
income taxes, interest, replacements and
administrative and general costs over the
depreciable life of the asset. In this analysis,
the capital charge is assumed to be 10% of
the initial investment for both generation
and transmission resources based on research
by Cambridge Energy Research Associates
(CERA) (Table F.6.1, line 14 and 27).
13
14
15
16
17
18
19
20
21
22
23
24
Production Costs (Fuel & Other VOM)
Change from All Gas Case [Column A]
Change from IRP- Based Case [Column B]
Resource Costs:
RM Resource Additions Capex
Wind
Gas thermal
Coal thermal
Incremental Transmission Integration Capex
RM Resource Capex Sub Total
Adj. Outside RM Resource Additions Capex
Other RM Costs
Incremental Capital Charge @ 10%
Incremental Fixed O&M
Wind "wear and tear"
Subtotal Other RM Costs
Adj. Other Costs Outside RM
Total Resource Costs
Representative
Year
18,458
(2,560)
(1,588)
1,231
245
94
1,570
(254)
1,316
Transmission Costs:
Incremental Line Capex
Customized Equipment Capex
RM Transmission Capex Sub Total
25
26
27
28
Incremental Fixed O&M
Incremental Capital Charge @ 10%
RM Transmission Costs
29
30
Annualized Costs
85
427
512
1,828
31
32
Total Initial Investment
Annual Net (Savings)/Cost from All Gas Case
34 Annual Net (Savings)/Cost from IRP- Based Case
(986)
(525)
33
Fixed O&M amounts are calculated
separately for each type of resource based on estimates provided by NWP&CC (Table F.6.1, line
15).
In the case of wind resources, a “wear and tear” impact on non- wind resources was included
(line 16). Transmission fixed O&M is assumed to be 20% of the annual capital charge based on a
recent transmission study by CERA. (Table F.6.1, line 26).
Resource and transmission capital charges and fixed O&M were combined to produce
annualized costs of each alternative (Table F.6.1, line 30). The production costs as well as
Appendix F
79
Draft
annualized fixed costs associated with each alternative were compared to Reference Cases and
other alternatives to obtain annual net savings and confirm economic viability.
Distribution of Economic Gains and Losses
The economic comparison tables show the costs and savings on an aggregate, interconnectionwide basis. The question then becomes where the economic gains and losses may fall within the
West. Table F.6.3 below takes a first look at the spatial distribution of costs and savings by
regional area and by load (consumers) and generator category.
These tables are predicated on LMPs, which are driven by loads, fuel prices, generation levels,
and other variables at the nodal level. (See Chapter 2 for a discussion of LMPs.) LMPs are
transitory, and arguably they are insufficient for predicting where benefits will fall.
The distributions reflect fuel and other VOM on an economic modeling basis. They do not
include capital & fixed O&M costs.
Effectively, the distributions assume a real-time
competitive market in which pricing is on an hourly, LMP basis. In fact, state regulatory
treatment of these gains and losses could change the mix between loads and generators
substantially. The net impact on a region can be estimated by subtracting the Generator Gross
Margin column from the Load column
LMP is the Load Cost
divided by GWhEssentially this is the
average regional LMP
for the year
LMP is the Generator
Revenue divided by
GWh- Essentially this
is the average regional
LMP for the year
Table F.6. 3: Economic Gross Gains & Losses Table
Load
Region
Rocky Mountain
Northwest
Canada
Mexico
California
Desert Southwest
Total
Total energy
demanded by loads
represented in GWh
Appendix F
GWh
161,635
193,131
142,702
19,848
335,938
162,512
1,015,766
LMP
48.24
49.22
48.83
48.20
51.47
49.02
49.70
Total generator
production costincludes fuel and
other VOM
Generator
Cost (MM)
7,797
9,505
6,968
957
17,291
7,967
50,484
The hourly demand at
each load node times the
hourly LMP ($), summed
for the year.
GWh
195,545
201,812
146,257
25,404
221,372
225,373
1,015,763
LMP
47.10
48.67
48.63
47.75
52.04
48.36
49.00
Revenue
(MM)
9,209
9,821
7,113
1,213
11,521
10,899
49,777
VOM (MM)
2,361
2,404
1,996
879
6,117
6,024
19,780
Gross Margin
(MM)
6,848
7,418
5,117
334
5,404
4,875
29,997
The hourly generation at
each generator node times
the hourly LMP, summed
for the year.
Total energy
generated in
GWh
Revenues minus
VOM=
Generator Gross
Margin
Load Minus
Generator
949
2,088
1,850
623
11,887
3,091
20,488
Load Cost minus
Generator Gross
Margin, used to
calculate total
benefits in
Chapter 3
80
Draft
Tables B.6.4 – B.6.7 display the gross amounts used to calculate the regional gains and losses in
Chapter 3. For example, to calculate the Load Benefit for the Rocky Mountain Region in Table
3.7 (chapter 3), subtract the Rocky Mountain Load Cost in Table B.6.4 ($7,797 Million) from the
Rocky Mountain Load Cost in Table B.6.7 ($7,920 million). This yields a load benefit of $123
million.
Table F.6. 4: Recommendation 1
Load
Region
Rocky Mountain
Northwest
Canada
Mexico
California
Desert Southwest
Total
GWh
LMP
161,635
193,131
142,702
19,848
335,938
162,512
1,015,766
48.24
49.22
48.83
48.20
51.47
49.02
49.70
Generator
Cost (MM)
7,797
9,505
6,968
957
17,291
7,967
50,484
GWh
195,545
201,812
146,257
25,404
221,372
225,373
1,015,763
LMP
47.10
48.67
48.63
47.75
52.04
48.36
49.00
Revenue
(MM)
9,209
9,821
7,113
1,213
11,521
10,899
49,777
VOM (MM)
2,361
2,404
1,996
879
6,117
6,024
19,780
Gross Margin
(MM)
6,848
7,418
5,117
334
5,404
4,875
29,997
Load Minus
Generator
949
2,088
1,850
623
11,887
3,091
20,488
Table F.6. 5: Recommendation 2
Load
Region
Rocky Mountain
Northwest
Canada
Mexico
California
Desert Southwest
Total
GWh
161,635
193,131
142,702
19,848
335,938
162,512
1,015,766
LMP
43.57
46.88
47.52
47.24
49.71
47.32
47.45
Generator
Cost (MM)
7,042
9,053
6,781
938
16,699
7,689
48,202
GWh
217,225
196,704
144,743
25,173
216,187
215,731
1,015,762
LMP
41.75
46.38
47.34
46.84
49.75
46.73
46.33
Revenue
(MM)
9,070
9,123
6,852
1,179
10,755
10,081
47,060
VOM (MM)
2,340
2,178
1,919
867
5,562
5,592
18,458
Gross Margin
(MM)
6,729
6,945
4,933
312
5,193
4,489
28,602
Load Minus
Generator
313
2,108
1,847
626
11,505
3,200
19,600
Table F.6. 6: IRP Based Reference Case
Load
Region
Rocky Mountain
Northwest
Canada
Mexico
California
Desert Southwest
Total
GWh
161,635
193,131
142,702
19,848
335,938
162,512
1,015,766
LMP
48.21
49.55
48.97
48.24
51.63
49.08
49.84
Generator
Cost (MM)
7,793
9,570
6,988
957
17,345
7,976
50,629
GWh
190,671
202,593
146,500
25,421
224,726
225,851
1,015,762
LMP
47.30
49.02
48.77
47.79
52.19
48.39
49.19
Revenue
(MM)
9,018
9,931
7,144
1,215
11,728
10,930
49,966
VOM (MM)
2,465
2,435
2,007
880
6,214
6,046
20,046
Gross Margin
(MM)
6,554
7,496
5,137
335
5,514
4,884
29,920
Load Minus
Generator
1,239
2,075
1,851
622
11,831
3,091
20,709
Table F.6. 7: All Gas Reference Case
Load
Region
Rocky Mountain
Northwest
Canada
Mexico
California
Desert Southwest
Total
Appendix F
GWh
161,635
193,131
142,702
19,848
335,938
162,512
1,015,766
LMP
49.00
49.88
49.08
48.17
51.74
49.02
50.07
Generator
Cost (MM)
7,920
9,634
7,004
956
17,381
7,966
50,862
GWh
188,658
203,853
146,785
25,432
224,434
226,603
1,015,765
LMP
48.58
49.38
48.86
47.72
52.29
48.32
49.52
Revenue
(MM)
9,165
10,066
7,171
1,214
11,736
10,950
50,303
VOM (MM)
3,300
2,488
2,019
880
6,256
6,075
21,018
Gross Margin
(MM)
5,865
7,578
5,152
333
5,480
4,875
29,284
Load Minus
Generator
2,055
2,055
1,852
623
11,901
3,091
21,577
81