Comparison of PCG Calculations
Pseudo-Unit vs Plant Basis
Combined-Cycle Modeling
April 16, 2009
Pseudo-Unit vs Plant Basis PCG
• The calculations are based on the methods presented on April 8, 2009 for pseudo‐unit basis and December 18, 2008 for plant basis
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Example: Combined-Cycle Plant
• 2 CTs and 1 ST represented by 2 pseudo‐units
• Will use a single ST share for each pseudo‐unit
• Omitted start‐up and speed no‐load values
Physical Units
Pseudo‐Units
CT1 = 100MW
PS1 = 150MW
CT2 = 100MW
PS2 = 150MW
ST = 100MW
• The ST share of each pseudo‐unit is ⅓
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Example: Day-Ahead Results
For Hour, H
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PS1 offer is $65/MW
PS2 offer is $75/MW
PS1 day‐ahead schedule is 120MW
PS2 day‐ahead schedule is 150MW
Implicit ST share of PS1’s day‐ahead schedule is
⅓ × 120MW = 40MW • Implicit ST share of PS2’s day‐ahead schedule is
⅓ × 150MW = 50MW
• The ST has an implicit day‐ahead schedule of
40MW + 50MW = 90MW
• CT1 has an implicit day‐ahead schedule of
(1 ‐ ⅓) × 120MW = 80MW
• CT2 has an implicit day‐ahead schedule of
(1 ‐ ⅓) × 150MW = 100MW
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Example: Real-Time Results
For Hour, H
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•
•
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Real‐time MCP is $70/MW
Real‐time offer for all physical units is also $70/MW
CT1 real‐time dispatch is 90MW
CT2 real‐time dispatch is 85MW
ST real‐time dispatch is 95MW
PS1 has an expected allocation of real‐time ST output of
⅓/(1 ‐ ⅓) × 90MW = 45MW
• PS2 has an expected allocation of real‐time ST output of
⅓/(1 ‐ ⅓) × 85MW = 42.5MW
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Example: Parameters
PCG on Pseudo-Unit Basis
Physical Unit
Implicit Day‐
Ahead Schedule
Implicit ST Share of Day‐
Ahead
Schedule for Pseudo‐Unit Associated with CT
Real‐Time
Dispatch
Expected Allocation of Real‐time ST Output for Pseudo‐Unit Associated with CT
CT1
80MW
40MW
90MW
45MW
CT2
100MW
50MW
85MW
42.5MW
ST
90MW
n/a
95MW
n/a
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Example: Component 1
PCG on Pseudo-Unit Basis
Implicit DA ST Schedule = 90MW
RT ST Dispatch = 95MW
Pseudo‐Unit 1
Pseudo‐Unit 2
DA Schedule
120MW
150MW
Implicit DA CT Schedule
80MW
100MW
Implicit ST Share of DA Schedule
40MW
50MW
RT CT Dispatch
90MW
85MW
Implicit RT ST Output
45MW
42.5MW
RT CT Dispatch Amounts in Calculation
min(80MW, 90MW) = 80MW
min(100MW, 85MW) = 85MW
Portion of RT ST Dispatch Amounts in Calculation
40MW
since RT ST dispatch exceeds implicit day‐ahead ST schedule (component 1 rule a)
50MW
since RT ST dispatch exceeds implicit day‐ahead ST schedule (component 1 rule a)
DA As‐Offered Costs
(80MW + 40MW) × $65/MW = $7,800
(85MW + 50MW) × $75/MW = $10,125
RT Energy Revenues
(80MW + 40MW) × $70/MW = $8,400
(85MW + 50MW) × $70/MW = $9,450
Component 1
$0, since RT revenues exceed DA as‐
offered costs
$10,125 ‐ $9,450 = $675
Example: Component 2
PCG on Pseudo-Unit Basis
Implicit DA ST Schedule = 90MW
RT ST Dispatch = 95MW
Pseudo‐Unit 1
Pseudo‐Unit 2
DA Schedule
120MW
150MW
Implicit DA CT Schedule
80MW
100MW
Implicit ST Share of DA Schedule
40MW
50MW
RT CT Dispatch
90MW
85MW
Implicit RT ST Output
45MW
42.5MW
RT CT Dispatch Amounts in Calculation
80MW
as determined for component 1
85MW
as determined for component 1
Portion of RT ST Dispatch Amounts in Calculation
40MW
as determined for component 1
50MW
as determined for component 1
Value of MW Amount to Increase Using DA Offer
[120MW ‐ (80MW + 40MW)] ×
$75/MW = $0
[150MW ‐ (85MW + 50MW)] ×
$75/MW = $1,125
Value of MW Amount to Increase
Using RT Offer
(80MW ‐ 80MW) × $70/MW + (40MW ‐ 40MW) × $70/MW = $0
(100MW ‐ 85MW) × $70/MW + (50MW ‐ 50MW) × $70/MW = $1,050
Component 2
$0
$1,125 ‐ $1,050 = $75
Example: PCG Payment
PCG on Pseudo-Unit Basis
• Assuming that there are no revenues from CMSC and OR
• Pseudo‐unit 1 receives no PCG
• Pseudo‐unit 2 receives a PCG of
$675 + $75 = $750
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Example: Parameters
PCG on Plant Basis
Physical Unit
Implicit Day‐
Ahead Schedule
Real‐Time
Dispatch
Amount of Day‐Ahead
Schedule Dispatched in Real‐Time
(For Component 1 Calculation)
Amount of Day‐Ahead
Schedule Not Dispatched in Real‐Time (For Component 2 Calculation)
CT1
80MW
90MW
80MW
0MW
CT2
100MW
85MW
85MW
15MW
ST
90MW
95MW
90MW
0MW
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Example: Component 1
PCG on Plant Basis
• Total day‐ahead as‐offered costs
Day‐ahead schedules × day‐ahead offers
= PS1 DA schedule × DA offer + PS2 DA schedule × DA offer
= 120MW × $65/MW + 150MW × $75/MW = $7,800 + $10,125
= $17,925
• Total real‐time revenues
Day‐ahead schedule dispatched in real‐time × real‐time price
= (CT1 RT dispatch + CT2 RT dispatch + ST RT dispatch) × RT price
= (80MW + 85MW + 90MW) × $70/MW
= $17,850
• Short‐fall in payment
Day‐ahead as‐offered costs ‐ Real‐time revenues
= $17,925 ‐ $17,850
= $75
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Example: Component 2
PCG on Plant Basis
• Amount of day‐ahead scheduled MW not dispatched in real‐time
CT1 amount = 0MW
CT2 amount = 15MW
ST amount = 0MW
• Component 2
Total DA schedule not dispatched in RT × Change in offer from DA to RT
= 15MW × ($75/MW ‐ $70/MW) = $75
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Example: PCG Payment
PCG on Plant Basis
• Assuming that there are no revenues from CMSC and OR
• Plant receives PCG of
$75 + $75 = $150
• In comparison to PCG on a pseudo‐unit basis, this is $600 less – why?
The ‘margins’ from pseudo‐unit 1 of $8,400 ‐ $7,800 = $600 was used to offset the loss from pseudo‐unit
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