5/31 edits
Need to fix terminology “option” to “alternative on Figure 6-4
Do we have LMP contour maps showing projects in July in the reference
case and each alternative scenario?
Chapter 6 2013 Alternative Cases Modeled
The location of new generation is the primary factor determining the level of
congestion on the transmission system. Historically, transmission and generation
planning were conducted in tandem by vertically-integrated utilities. Nearly all of the
transmission constructed in the Western interconnection was built to move power from
specific new generating resources to the customers of utilities that constructed the
generation. FERC’s 1996 open access order effectively decoupled generation planning
from transmission planning.
The major challenge in evaluating transmission needs in 2013 is estimating the
location of new generation. To address this uncertainty, the RMATS RAWG developed
four alternative generation scenarios. One of the major difficulties in linking generation
expansion and transmission expansion is the mismatch between the time it takes to
develop new generation and the time it takes to develop the related transmission
expansion projects. Transmission projects typically require five to 10 years to complete,
comparable to the time required for the development of new coal-fired generation. Gasfired generation requires significantly less time (e.g., 2-3 years), but may not require
much additional transmission. Wind generation can be constructed in as little as 18
months but may require significant transmission additions.
Alternative 1 reflects the resource plans of the major load serving entities in the
RMATS region. Alternative 2 is a “pseudo” regional integrated resource plan for the
RMATS region that attempts to optimize the location of new generation within the region
to meet forecasted load (with added reserves) in 2013 (3,900 MW). Alternative 3 meets
forecasted load growth within the RMATS region and allows for exports from the region
equal to load growth within region (7,800 MW). Alternative 4 provides sufficient
generation to meet load growth in the RMATS region and exports equal to twice the load
growth within the region (11,700 MW).
To the maximum extent possible, Alternative 1 reflects company announced
generation plans within the RMATS region plus additional generation added by the
RAWG. In developing Alternative 2, the RAWG made its own judgments about the
location of new generation to lower overall costs for the sub-region. Alternatives 3 & 4
were developed by the RAWG with generation to support export from the sub-region.
Figure 6-1 shows the type and location of generation modeled in all four
scenarios.
6-1
Figure 6-1
Generation Alternatives for 2013
State
Bubble
Gen
Type
2013 ALTERNATIVE CASES
Colorado East
Colorado
Colorado West
KGB
Idaho
Mid Point/Boise/Snake
Montana West
Montana
Broadview
Colstrip/Crossover
Bonanza
IPP
Utah
Utah North
Utah South
Big Horn Basin
Black Hills
Wyoming
LRS
SW Wyoming
Wyoming
WYO(IDA)
WYO(MT)
Jim Bridger
Yellowtail
Total Coal
Total Gas
Total Wind Nameplate
Total Firm Energy
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Coal
Gas
Wind
Name Plate Generation Values
1
1250
210
800
125
575
2
500
210
500
125
3
1540
210
800
4
2500
603
1500
250
250
125
125
440
225
280
250
260
500
500
260
1000
750
359
950
609
1000
1109
50
100
200
0
200
950
950
250
575
525
100
575
140
200
575
140
120
320
575
140
250
250
250
250
250




Alternative 1- Compilation of existing
IRP’s - minimal new transmission
Configured incremental resource
additions in each state to meet projected
load growth plus reserves in that state.
(Load growth is 3900 MW from 2008 –
2013 for RM states). Major wind in
CO-E and SW Wyoming close to load
centers
Alternative 2- “Pseudo” IRP for subregion
Focus on Powder River coal and open
range wind. Solves for same load
growth as Alternative 1. Requires more
transmission than Alternative 1
Alternative 3- Export 1 X RM load
growth
Builds off Alternative 2. Additional
Powder River and Utah coal and open
range wind necessitating more
transmission for export
Alternative 4- Export 2 X RM load
growth
Still more Powder River (and Utah)
coal and open range wind, and
additional DC line
125
925
500
500
1500
1150
700
1000
1400
50
575
575
2450
2100
50
800
575
160
230
6149
660
4955
7800
8559
1053
10440
11700
50
2600
785
2575
3900
2959
350
2955
3900
6-2
Alternative 1: Compilation of Existing Utility Resource Plans
Alternative 1 reflects the generation proposed in the resource plans of the major
load serving entities within the RMATS region. These plans tend to emphasize the
development of new generation close to load centers and thus represent a minimal new
transmission case. Figure 6-2 shows the location and type of new generation in each of
the bubbles modeled. A total of 3,900 megawatts of new generation is added to meet
forecasted load growth within the RMATS region in 2013.
Figure 6-2
Alternative 1 Incremental Resource Additions (MW)
225
Wind
250
Wind
575
Coal
125
Wind
50
Gas
925
Wind
250
Wind
200
Coal
575 Coal
525 Gas
1250
Coal
210 Gas
800
Wind
6-3
Figure 6-3 shows the most congested transmission paths in the RMATS region the
generation in Alternative 1. The percentage within the blue circles is the percentage of
time during a year that the transmission constraint would prevent economic power
transfers. The dollar number next to the transmission constraint represents how much
interconnection-wide variable operating and maintenance costs would decline by adding
one additional megawatt to the transfer capacity of the path. This value will decline as
each additional megawatt of transfer capacity is added.
3,900 MW added to Rocky Mtn. States
%
Montana
5%
Percent of Time at Binding Limit
Interface Name
Opportunity Cost/Savings ($)
Montana – NW
$9,136
Idaho
Alternative 1- no transmission additions
Figure 6-3
Congestion in Alternative 1 If No Transmission Is Added
Wyoming
6%
Utah
Path C
$19,322
14%
30%
Bridger West
$61,729
West of Naughton
$40,571
9%
Bonanza West
$17,736
40%
TOT 2C
$74,557
Colorado
Graphs were developed to show the duration of congestion on each of the
highlighted paths. For example, the blue line on Figure 6-4 shows the duration of
transmission congestion on Path C in eastern Idaho that Figure 6-3 shows as congested
6% of the time. The horizontal brown line at 1000 megawatts shows the capacity of the
line to handle flows moving from East to West. The blue line is above that capacity 6%
of the time. The turquoise line at minus 1000 megawatts shows the capacity of the line to
move power from West to East. The other lines of the graph show congestion in the
other generation scenario alternatives assuming the generation is built, but not
transmission is added. These graphs were used to help the TAWG target proposed
transmission additions. In some cases, the frequency of congestion and the value of
relieving the congestion were too small to warrant making transmission investments to
relieve the congestion.
6-4
Duration curves for the each of the major paths can be found in Appendix 1.
Figure 6-4
Duration of Congestion in Different Scenarios
Path C
Desired power transfers in Alternative 1 exceed
the capacity of the line 6% of the time
1,500
1,000
MW
500
0
(500)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
(1,000)
(1,500)
(2,000)
Percent of Time
No Tx Additions
Option 1
Option 2
Option 3
Option 4
Current Forward Capacity
Current Reverse Capacity
Figure 6-5 shows the transmission additions identified by the RMATS TAWG
(LINK) that would alleviate much of the congestion identified in Alternative 1. A phase
shifter would be added on existing path between Montana and Idaho. A transformer
would be added at Flaming Gorge. In addition a new 345 KV line would be added from
Miners to Ben Lomond and a new to 230 KV line would be added between Midpoint in
Boise. No transmission would be added to alleviate constraints outside the RMATS
region.
6-5
Figure 6-5
Transmission Additions in Alternative 1
Transmission Additions
Alternative 1
500 kV
Boise
345 kV
Midpoint
Jim Bridger
230 kV
Naughton
Ben Lomond
Miners
Added Phase Shifter
Added Transformer
The addition of new generation and transmission in Alternative1 would lower
annual variable and operating maintenance costs by $3.1 billion throughout the Western
Interconnection. Most of those savings would occur outside the RMATS region. Within
the RMATS region, the largest benefit would accrue to eastern Colorado.
Figure 6-6 shows the table developed to calculate the change in variable operating
and maintenance from the base case when new generation and transmission are added in
Alternative 1. The four right columns show the change in variable operating and
maintenance cost from the reference scenario. The annual interconnection-wide savings
in variable operating and maintenance costs would be $1.333 billion. Most of that annual
savings ($1.318 billion) is from the addition of generation. The annual savings
attributable to adding the transmission in Figure 6-5 would be $15 million. If sufficient
transmission was added to alleviate all congestion in Alternative 1(last column), the
annual savings would be $133 million. However, the TAWG judged that cost of
transmission investments to relieve all the congestion would be higher than the $133
million in savings.
6-6
Figure 6-6
Summary Table of Annual Savings in Operating and Maintenance Costs
in Alternative 1
Annual VOM with Transmission Solutions
Alternative 1 – ($Millions)
Reference
Case
ID
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
18
19
20
22
23
24
25
26
28
29
30
32
33
Area
New Mexico
Arizona
Nevada
WAPA- LC
Mexico- C
Imperial
San Diego
So. California
LADWP
IPP
PG AND E
Northwest
BC Hydro
Aquila
Alberta
Idaho- West
Montana- West
Sierra
Wyoming- Central
Bonanza
Utah- North
Utah- South
Colorado- East
Colorado- West
Black Hills
LRS
JB
Broadview
CRSOVRCO
Total
(a)
No Tx
Add
Add
Constraints Gen/No Tx Gen/Add Tx
(b)
( c)
(d)
Value of
Gen
Additions
Delta
Value of
Gen & Tx
Additions
Delta
482
4,245
1,226
503
888
22
896
1,684
358
253
3,599
2,329
585
33
1,452
14
0
305
50
69
213
369
931
200
76
83
261
17
165
470
4,295
1,215
514
943
15
647
1,016
202
275
2,813
2,188
553
34
1,743
0
0
253
68
69
173
589
911
200
66
83
307
17
165
449
3,958
1,192
448
880
18
780
1,493
304
274
3,359
2,191
540
32
1,433
0
0
235
62
68
163
524
732
200
58
83
331
17
165
449
3,934
1,145
453
879
18
787
1,510
290
274
3,315
2,202
540
32
1,434
2
0
235
65
68
162
538
783
200
60
83
334
17
165
(c - a)
(34)
(286)
(33)
(55)
(8)
(3)
(116)
(191)
(54)
21
(240)
(138)
(44)
(1)
(19)
(14)
0
(70)
13
(1)
(50)
155
(199)
(1)
(19)
(0)
69
(0)
(0)
(d - a)
(33)
(310)
(81)
(50)
(8)
(4)
(108)
(174)
(68)
21
(284)
(127)
(45)
(1)
(18)
(13)
0
(70)
15
(0)
(51)
169
(148)
(0)
(16)
0
72
(0)
(0)
21,307
19,826
19,989
19,974
(1,318)
(1,333)
Value of Tx
Additions
Delta
VOM
Savings
with No Tx
Constraints
(d - c)
(b - c)
1
(24)
(48)
5
(0)
(0)
7
17
(13)
0
(44)
11
(1)
(0)
1
1
0
0
2
0
(1)
14
51
0
2
0
3
(0)
(0)
21
337
23
65
64
(3)
(133)
(476)
(101)
0
(546)
(3)
13
2
310
(0)
0
18
6
1
10
65
180
1
9
0
(24)
0
0
(15)
(163)
 Negative (red) values indicate
reduction in fuel cost due to displacement
Total Annual VOM
Savings
 Positive (black) values indicate
increased fuel cost due to higher dispatch
Similar tables were developed for each of the alternative generation scenarios and
can be found in Appendix 1.
6-7
Alternative 2: “Pseudo” IRP for the RMATS Region
Figure 6-7 shows the location and type of new generation that would be added in
the RMATS region under a “pseudo” regional integrated resource plan to meet load
growth of 3,900 megawatts. The major differences between Alternative 1 and
Alternative 2 are the addition of 359 megawatts of coal generation and 380 megawatts of
wind. New gas-fired generation would drop from 785 megawatts to 350 megawatts. But
the location of new coal and wind generation would move from eastern Colorado, Idaho,
and Utah to the Powder River Basin and southern Wyoming. The rationale for relocating
the generating resources was the assumed lower cost of mine-mouth coal plants in the
Powder River Basin compared to hauling coal by rail to a plant elsewhere and the higher
quality wind resources in southern Wyoming. Continuing proposals by generation
developers for coal-by-rail power plants in Nevada rather than coal-by-wire plants in
Wyoming challenge the cost assumptions used in Alternative 2.
Figure 6-7
Incremental Resource Additions in Alternative 2
250
Coal
280
Wind
359 Coal
50 Wind
250
Wind
125
Wind
700
Coal
575
Coal
1150
Wind
500
Wind
100
Wind
500 Coal
575 Coal
140 Gas
210 Gas
500 Wind
Figure 6-8 shows the resulting congestion from the generation additions in
Alternative 2. Congestion duration curves can be found in Appendix 1.
6-8
Figure 6-8
Congestion is No Transmission Is Added in Alternative 2
Alberta - BC
$53,112
B.C.
7,800 MW added to Rocky Mtn. States
%
Percent of Time at Binding Limit
Alberta
71%
Interface Name
Opportunity Cost/Savings ($)
Montana
60%
Wash.
West of Broadview
$187,948
Montana – NW
$157,469
100%
Idaho
Black Hills – C. Wyoming
$288,392
82%
Oregon
Alternative 3- no transmission additions
73%
Bridger West
$241,727
Wyoming
Utah
31%
Nevada
TOT 3
$140,590
50%
Bonanza West
$48,990
IPP DC
$69,519
TOT 2C
$157,912
Colorado
California
90%
46%
New Mexico
Arizona
Mexico
Figure 6-9 shows the transmission added to relieve congestion in Alternative 2.
The transmission additions in Alternative 2 incorporate the additions in Alternative 1 plus
new 345 KV lines from Wyoming to the Colorado Front Range, from Idaho to Utah, and
from Wyoming to Idaho. A new 500 KV line would be added from Montana to Idaho
which would include a phase shifter.
6-9
Figure 6-9
Transmission Additions in Alternative 2
Townsend
Broadview
Ringling
500 kV
Midpoint
Boise
345 kV
230 kV
Existing 500kV
Borah
Treasureton
Dave Johnson
Ant Mine/Reno
Jim Bridger
LRS
Naughton
Ben Lomond
Miners
Cheyenne Tap
Ault
Green Valley
Added Phase Shifter
Added Transformer
Under Alternative 2, the Interconnection-wide changes in annual operating and
maintenance costs would be $1,520 billion, of which $250 million is attributable to the
transmission added. A complete table of changes in annual operating and maintenance
costs under Alternative 2 can be found in Appendix 1.
Alternative 3: Exports to Load Growth in the RMATS Region
Figure 6-10 shows the generation additions in Alternative 3 which equal 7,800
megawatts (3900 megawatts to serve load growth in the RMATS region; 3900 megawatts
for export outside the RMATS region). The type and location of new generation reflects
the known plans of generation developers.
6-10
Figure 6-10
Incremental Generation Additions in Alternative 3
500 Coal
950 Wind
260 Gas
500
Wind
609 Coal
100 Wind
250 Wind
1400
Coal
125
Wind
50 Gas
575 Coal
160 Wind
1000
Wind
500 Wind
200 Wind
950
Coal
250
Wind
1540 Coal
575 Coal
210 Gas
140 Gas
800 Wind
120 Wind
Figure 6-11 shows congestion in Alternative 3 if no transmission is added. The
map shows congestion on paths within and outside the RMATS region. The addition of
generation for export significantly increases the amount of congestion and the value of
relieving such congestion through transmission expansion. See Appendix 1 for duration
curves associated with transmission paths identified in Figure 6-11.
6-11
Figure 6-11
Congestion If No Transmission Is Added in Alternative 3
Alberta - BC
$53,112
B.C.
7,800 MW added to Rocky Mtn. States
%
Percent of Time at Binding Limit
Alberta
71%
Interface Name
Opportunity Cost/Savings ($)
Montana
60%
Wash.
West of Broadview
$187,948
Montana – NW
$157,469
100%
Idaho
Black Hills – C. Wyoming
$288,392
82%
Oregon
Alternative 3- no transmission additions
73%
Bridger West
$241,727
Wyoming
Utah
31%
Nevada
TOT 3
$140,590
50%
Bonanza West
$48,990
IPP DC
$69,519
TOT 2C
$157,912
Colorado
California
90%
46%
New Mexico
Arizona
Mexico
There are a number of options for relieving transmission in Alternative 3. The
TAWG determined that it is necessary to have at least two 500 KV transmission paths out
of the RMATS region and that such paths should not be in the same corridor. Figure 612 shows the four optional combinations of 500 KV lines that were modeled. Additional
combinations are feasible but were not examined because the analysis showed little
difference in variable and operating maintenance costs among the four paths that were
studied.
6-12
Figure 6-12
Transmission Additions in Alternative 3
Transmission Additions
Alternative 3
Bell
Noxon
Great Falls
Taft
Ashe
Hot Springs
Broadview
Missoula
Colstrip
Ringling
Grizzly
Midpoint
500 kV
Boise
Kinport
345 kV
Dave Johnson
Borah
LRS
Ben Lomond
Naughton
Table Mtn.
IPP
Additional DC
Added Series Compensation Only
Ant Mine
Jim Bridger
230 kV
This export alternative
requires two- 500 kV
lines
Option 1
Miners
Mona
Cheyenne Tap
Ault
Option 2
Emery
Grand Junction
Tesla
Green Valley
Red Butte
Crystal
Added Phase Shifter
Option 3
Market Place
Added Transformer
Option 1 only
Adelanto
Option 4
Option 2, 3, &4 only
The major differences in new transmission between Alternative 2 and Alternative
3 within the RMATS region were: elimination of a second 345 KV line from Wyoming
to the Colorado front Range; the addition of a 345 KV line from Colorado to Utah; the
upgrading of transmission from Wyoming to Idaho and from Wyoming to Utah from 345
KV to 500 KV; the addition of a 500 KV lines between Idaho and Utah; and additional
series compensation on the existing 500 KV line within Montana. To move power from
Montana to Washington State a new 500 KV line was investigated. To move power from
Utah to Southern Nevada a new 500 KV line was investigated. Three optional 500 KV
lines were identified to move power from Idaho to southern Nevada, Northern California,
and central Oregon. The combined options modeled were:




New transmission from Montana to Washington plus from Idaho to Northern
California;
New transmission from Utah to southern Nevada plus from Idaho to Northern
California;
New transmission from Utah to southern Nevada plus from Idaho to central
Oregon; and
New transmission from Idaho to southern Nevada plus from Idaho to California.
Common to all the options was the addition new converter equipment to the 500 KV DC
line from Utah to Southern California (the IPP line) to increase its capacity by 500 MW.
The TAWG did not propose two new 500 Kv lines terminating in the Northwest because
6-13
it is believed the delivery of that much power in the Northwest would require upgrades of
the Pacific Intertie to then move the power to California.
All of these combinations of optional routes to move power out of the RMATS
region resulted in roughly similar reductions in annual variable operating and
maintenance costs throughout the interconnection, between $741 million and $774
million. Most of those savings in reduced variable operating and maintenance costs fell
outside the RMATS region. DO WE KNOW HOW MUCH OF THE SAVINGS IS
ATTRIBUTABLE TO TRANSMISSION CONSTRUCTION? A complete table of
changes in annual operating and maintenance costs under Alternative 3 can be found in
Appendix 1.
The analysis showed that each of the transmission configurations for exports
under Alternative 3 would result in significant cycling of coal-fired power plants due to
the addition of large amounts of wind generation. Such cycling of coal generation can
create transmission instability and excessive wear and tear on power plants. However,
this analysis needs additional refinement since the dispatch of hydroelectric generation
and wind generation were “hardwired” into the model (as opposed to allowing the model
to optimizing the dispatch of generation based on variable costs, as is done for other
resources) and did not consider ways of altering hydroelectric and wind generation to
minimize cycling of coal-fired power plants.
Alternative 4: Exports Equal Two Times RMATS Load Growth
Figure 6-13 shows resource additions in Alternative 4. As with Alternative 3, the
additions reflect the announced plans of generation developers. No attempt was made to
optimize the location of new generation to minimize costs. Generation in Alternative 4 is
sufficient to meet load growth within the RMATS region and export power equal to two
times the load growth within the region. Total generation in Alternative 4 is 11,700
megawatts.
6-14
Figure 6-12
Incremental Resource Additions in Alternative 4
750 Coal
1000
Wind
260 Gas
1000
Wind
1109
Coal
100 Wind
250 Wind
440 Wind
2100 Coal
125 Wind
125 Wind
50 Gas
800 Wind
575 Coal
230 Wind
320
Wind
1500
2450
Wind
950
Coal
Wind
2500 Coal
575 Coal
140 Gas
250 Wind
603 Gas
1500 Wind
250 Wind
Alternative 4 would create significantly more congestion than Alternative 3.
6-15
B.C.
11,700 MW added to Rocky Mtn. States
%
Percent of Time at Binding Limit
Alberta
Wash.
Interface Name
Opportunity Cost/Savings ($)
Montana
42%
West of Broadview
$128,921
79%
Montana – NW
$251,693
Idaho
9%
Idaho- Montana
$103,932
100%
Black Hills – C.
Wyoming $175,556
96%
Oregon
Bridger West
$272,351
Wyoming
Utah
60%
Nevada
TOT 3
$100,932
55%
Bonanza West
$132,741
IPP DC
$73,000
Alternative 4- no transmission additions
Figure 6-14
Congestion If No Transmission Is Added in Alternative 4
(I don’t think the following figure could be right for Alternative 4.)
TOT 2C
$176,124
TOT 2A
$86,407
California
Colorado
47%
82%
50%
New Mexico
Arizona
Mexico
To accommodate the addition of new resources for export, the Transmission
Work Group investigated two 500 KV DC lines from Wyoming to northern or southern
California.
6-16
Figure 6-15
Transmission Additions in Alternative 4
Transmission Additions
Alternative 4
Taft
Missoula
Broadview
Colstrip
Ringling
DC
Grizzly
Midpoint
500 kV
Wyodak
Boise
Kinport
345 kV
Dave Johnson
Borah
Option 1
Jim Bridger
230 kV
LRS
Ben Lomond
Naughton
IPP
Additional DC
Added Series Compensation Only
Miners
Mona
Cheyenne Tap
Ault
Option 2
Emery
Grand Junction
Tesla
Midway
Green Valley
Red Butte
Added Phase Shifter
Added Transformer
Ant Mine
Crystal
Market Place
Vincent
Adelanto
Mira Loma
Reductions in variable operating maintenance costs in Alternative 4 would
amount to approximately $4.397 billion annually, of which $1.742 billion is attributable
to the transmission additions. A complete table of changes in annual operating and
maintenance costs under Alternative 4 can be found in Appendix 1.
Summary of Variable Operating and Maintenance Costs in Scenarios
Figure 6-16 summarizes the Interconnection-wide variable operating and
maintenance (VOM) costs in the scenarios compared with a reference case. The
reference case assumes that resources added outside the RMATS region are those
assumed in the natural gas scenario in the transmission study done by the Seams Steering
Group-Western Interconnection (SSG-WI) released in October 2003.
6-17
Figure 6-16
Total Interconnection-wide Variable Operating and
Maintenance Costs in Scenarios
Alt 4- Opt 2
Alt 4- Opt 1
Alt 3- Opt 4
Alternativ
Alt 3- Opt 3
e
Alt 3- Opt 2
Alt 3- Opt 1
Alt 2
Alt 1
Reference Case
16,000
17,000
18,000
19,000
20,000
21,000
22,000
Total VOM Cost ($Millions)
Sensitivity Analysis
Note: I can’t put this note above “Sensitivity Analysis” so I’ll put it here. We need an
additional figure with the deltas form the graph above.
To examine the sensitivity of the model to different assumptions, the results of
Alternative 3, option 3 (export of 3900 megawatts by the addition of new 500 kV lines
from Utah the southern Nevada, from Idaho to Northern California, and from Utah to
Southern California) were tested using alternative assumptions about hydro conditions,
natural gas prices, and the addition of new generation in Nevada. In addition, model
results were tested to determine the impact of potential carbon dioxide constraints and
more aggressive demand side management programs.
Hydro, Gas Price, Nevada Generation Sensitivity Analysis: High and low
hydro conditions were assumed to be those which occur once every ten
years.
Low gas prices were assumed to be $4.50/mmbtu in 2013 nominal dollars ($3.60 in
2004$), compared with the base case of $6.50/mmbtu in 2013 nominal dollars ($5.20 in
2004$). To reflect the transmission impacts of potential new coal-fired generation and
wind development in Nevada, the existing 1580 megawatt Mojave power plant in
southern Nevada was assumed to be on line. The base case assumption is that the
Mojave plant would be retired.
Figure 6-17 shows the sensitivity of an export case (Alternate 3, option 3) to
assumptions about additional generation in Nevada, low natural gas prices, high hydro
conditions, and low hydro conditions.
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Figure 6-17
Summary of Sensitivity Analyses
Total Interconnection-wide Variable Operating and Maintenance Costs
(Millions of Dollars)
Add Mohave
$4.50 Gas
High Hydro
Low Hydro
Alt 3- Option 3
14,000
15,000
16,000
17,000
18,000
19,000
20,000
21,000
VOM Cost ($Millions)
In summary, additional generation in Nevada, $4.50 gas prices and high hydro
conditions would result in lower variable operating and maintenance costs than the
reference case (Alternative 3, Option 3). Low hydro conditions would result in greater
variable operating and maintenance costs than the reference case.
Demand-side sensitivity analysis: To reflect more aggressive demand-side
management programs, it was assumed that energy use within the RMATS region would
grow by 1.0% less per year than assumed in the reference case and energy use outside the
RMATS region would grow by 0.5% less per year than assumed in the reference case.
Peak load reduction would be 1.5 times the energy reduction. With a couple of years of
phase in and the 5 year period between 2008 and 2013, peak loads in the RMATS region
in 2013 would be reduced by 12% and energy by 8% while in the coastal states the
deduction would be half that due to their already more aggressive demand-side programs
See Appendix 1 for discussion of these assumptions. Figure 6-18 shows load growth in
each of the regions of the Western interconnection using these assumptions. For
example, using these demand-side management assumptions, load growth in the RMATS
region between 2008 and 2013 would be only 100 megawatts.
6-19
Figure 6-18
Change in Loads with DSM
Est. Load After Assumed DSM Factor
Region
Annual Energy
MWh
RMATS
149,196,529
Az, NM, S. Nv
149,915,758
California
323,394,364
Or,Wa, N. Nv
185,403,864
Canada
134,489,410
Mexico
19,896,003
Totals
Summer Peak
MW
23,803
29,432
58,965
25,610
16,446
3,626
962,295,928
Winter Peak
Peak Growth
MW Summer (from 2008)
21,823
100
21,241
883
45,070
522
31,003
753
21,831
132
2,600
1,130
157,882
143,568
3,520
Using these assumptions, there is little need for new generation or transmission to
meet demand within the RMATS region in 2013.
To test the value of transmission to support exports from the RMATS region
under the DSM assumptions, the resources in Alternative 2 (“Pseudo” IRP for the
RMATS region) were modeled using two of the 500 kV transmission additions in
Alternative 3 (MT to the Northwest and Utah to Southern California).
( Replace this figure with Alternative 3 or eliminate it.)
Transmission Additions
Alternative 4
Taft
Missoula
Broadview
Colstrip
Ringling
DC
Grizzly
Midpoint
500 kV
Wyodak
Boise
Kinport
345 kV
Dave Johnson
Borah
Option 1
Jim Bridger
230 kV
LRS
Ben Lomond
Naughton
IPP
Additional DC
Added Series Compensation Only
Miners
Mona
Cheyenne Tap
Ault
Option 2
Emery
Grand Junction
Tesla
Midway
Green Valley
Red Butte
Added Phase Shifter
Added Transformer
Ant Mine
Crystal
Market Place
Vincent
Adelanto
Mira Loma
Total Interconnection-wide variable operating and maintenance costs under these
assumptions were $17,905 million annually, which is $1,921 million less than the
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variable operating and maintenance costs in Alternative 1 (RMATS utility IRPs and
predominately gas-fired generation additions outside the RMATS region).
Carbon constraints: To reflect potential carbon dioxide constraints, a sensitivity
analysis was conducted assuming a $5/ton tax on carbon and a $15/ton tax applied to new
plants (not existing plants). This level of taxation does not impact on the dispatch of
plants that the model assumes are built.
The impact of a CO2 adder on the decision on which existing plants to dispatch is
much less than the impact of the adder on the choice of generation plant to build. Just as
economics of choosing between driving a car or riding a bus become dramatically
different if you already own a car, all the fixed costs of owning the car are not relevant
and you only have the incremental running costs of the car to compare with the cost of
the bus ticket. Thus, the greatest ability to reduce CO2 emissions occurs in the choice of
which resources to build. The ABB Market Simulator focuses on the use of the
transmission system and has limited abilities to analyze resource choices. Models
utilities use in IRP efforts are better at evaluating resource addition options, however,
these types of models typically have very limited capabilities to model the transmission
system.
For example, a quick analysis using various assumptions (e.g., $6/mmBtu gas,
35% capacity for wind, 85% for coal and gas, and assumptions on capital costs and
carrying charges), shows that at a $5/ton CO2 adder coal is the lowest cost option.
However, at $10/ton CO2 adder, wind becomes the lowest cost option. [LINK TO
KURT’S SPREADSHEET ANALYSIS]
6-21
Summary of Changes in Monthly Locational Marginal Prices in the Alternatives
The following maps show average monthly locational marginal prices in July
2013 in the reference case and for each of the four alternatives after transmission is
added. DO WE HAVE SUCH CONTOUR MAPS?
Transmission Technology Options
The identification of transmission solutions to reduce variable operating
maintenance costs in 2013 focused on the addition of new 230 kV, 345 kV, and 500 kV
transmission lines, the addition of series compensation, and installation of phase shifters.
New technologies are being developed to increase transfer capacity on existing lines
within existing corridors. Many of these technologies may become commercial in the
next few years. Figure 6- __ summarizes these technologies
Figure 6Emerging Transmission Technologies
Technology
High-Temperature
Superconducting
Cables
Overview of Technology
Superconducting ceramic cables can carry much more current than standard wires of the
same size, with extremely low resistance, allowing more power to flow in existing right-ofways. But the required refrigeration results in higher initial and ongoing costs.
Underground
Cables
Underground cables transmit power with very low electromagnetic fields in areas where
overhead lines are impractical or unpopular. Costs are 5 to 10 times that of overhead lines,
and electrical characteristics limit AC lines to about 25 miles.
New transmission conductors with composite cores, as opposed to steel cores, are both
lighter and have greater current carrying capacity, allowing more power to flow in existing
right-of-ways. A new core consisting of composite fiber materials shows promise as
stronger than steel-core aluminum conductors and is 50 percent lighter in weight with up to
2.5 times less sag.
New computer-optimized transmission line tower designs allow for more power to flow in
existing right-of-ways.
Advanced
Composite
Conductors
More Compact
Transmission Line
Configurations
Polyphase (six or
twelve phase)
Transmission Line
Configurations
Modular
Equipment
Ultra High Voltage
Lines
High-Voltage DC
(HVDC)
Practically all AC high voltage power transmission is performed using three phases. The
use of six or even twelve phases allows for greater power transfer in a particular right-ofway with reduced electromagnetic fields due to greater phase cancellation.
Modular equipment designs provide greater transmission system flexibility, allowing the
grid to quickly adapt to changing usage. They could also facilitate emergency deployment
from a “strategic reserve” of critical devices, such as transformers.
Higher voltage lines can carry more power than lower voltage lines. The highest
transmission voltage line in North America is 765 kV. Higher voltages are possible, but
require much larger right-of-ways, increase need for reactive power reserves, and generate
stronger electromagnetic fields.
HVDC provides an economic and controllable alternative to AC for long distance power
transmission. DC can also be used to link asynchronous systems and for long distance
transmission under ground/water. Conversion costs from AC to DC and then back to AC
6-22
Technology
Flexible AC
Transmission
System
(FACTS) devices
Energy Storage
Devices
Controllable Load
Enhanced Power
Device Monitoring
Direct System State
Sensors
Overview of Technology
have limited usage. Currently there are several thousand miles of HVDC in North America.
FACTS devices use power electronics to improve power system control, helping to
increase power transfer levels without new transmission lines. But currently they are
expensive, making FACTS uneconomic for most transmission owners.
Energy storage devices permit use of lower cost, off-peak energy during higher-cost peakconsumption periods. Some specialized energy storage devices can be used to improve
power system control. Technologies include pumped hydro, compressed air,
superconducting magnetic energy storage(SMES), flywheels, and batteries.
Fast-acting load control has the potential to become an important part of transmission
system control. Flexible load allows higher normal-power transfer levels since during
system emergencies the load can be rapidly curtailed. Automatic load shedding (underfrequency, under-voltage), operator-initiated interruptible load, demand-side management
programs, voltage reduction, and other load-curtailment strategies have long been an
integral part of coping with unforeseen contingencies as a last resort, and/or as a means of
assisting the system during high stress, overloaded conditions. Future advances in loadcontrol technology will leverage the advent of real-time pricing, enabling consumers to
“back off ” their loads (either automatically through grid friendly appliances or through
manual intervention) when the price is right.
The operation of many power system devices, such as transmission lines, cables, and
transformers is limited by the device’s thermal characteristics. The high operating voltages
of these devices make direct temperature measurement difficult. Lack of direct
measurements required conservative operation, resulting in less power transmission
capacity. Newer dynamic sensors have the potential to increase transmission system
capacity.
In some situations the capability of the transmission system is limited by region-wide
dynamic constraints. Direct system voltage and flow sensors can be used to rapidly
measure the system operating conditions, allowing for enhanced system control.
Wide area measurement systems (WAMS) use phasor measurements that are synchronized
digital transducers that can stream data, in real time, to phasor data concentrator (PDC)
units. The general functions and topology of this network resemble those of dynamic
monitor networks. Data quality for phasor technology appears to be very high, and
secondary processing of the acquired phasors can provide a broad range of signal types.
Source: J. Hauer, T. Overbye, J. Dagle, and S. Widergren. 2002. Advanced Transmission Technologies. Issue Papers
Several of these technologies have the potential of minimizing environmental
impacts and local opposition to transmission expansion projects. Project sponsors should
carefully examine the application of such technologies in their transmission plans.
6-23