1. Frank Koza – PJM Dave Zwergel – Midwest ISO
PJM/MISO Update on CO-114
Frank Koza – PJM
Dave Zwergel – Midwest ISO 1

2. CO 114 Behavior
TLR results on PJM Coordinated Flowgates have been questionable since AEP and DPL joined PJM
Calculations produce “unrealistically excessive flow” across all priorities (7-Firm, 6-Non-Firm Network, and 2-Hourly)
PJM flows have often increased tenfold
Results add uncertainty to operations
How much is relief should I ask for?
How much is relief will I get? 2

3. Examples PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Kammer #8 xfmr l/o Kammer-South Canton 765 kV line
Flowgate Limit is 3695 3

4. Examples PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Mt. Storm-Doubs 500/Mt. Storm-Meadow Brook 500
Flowgate Limit is 2598 4

5. Examples PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Cook-Palisades345/BentnHrbr-Palisades345
Flowgate Limit is 2094 5

6. Results and Consequences
RCs may have to request much more relief than is actually necessary to effect curtailments
RCs may believe flows represent available relief, when in fact, the flows are reported erroneously and no relief is available
Operator Flow Change Request: MW 6

7. Analysis
Since the RTO is responsible for calculating Market Flow, PJM and MISO jointly investigated the discrepancies to find the cause
Assumptions hid an inequality in the basic calculation mechanism
Testing was done with generators at the same output levels, but shifts in output levels would have demonstrated the inequality
Load Shift Factor aggregations must be consistent between pre- and post-expansion models
Since CE joined PJM as a separate Control Area, problem remained hidden until AEP and DPL joined and the LSFs were merged 7

8. Historic Footprint 390 NNL Control Area 1 Control Area 2 Flowgate X
Gen 1
1100 MW Output
GSF = 0.10
Gen 2
900 MW Output
GSF = -0.20
Flowgate X
Load 1
1000 MW Demand
LSF = -0.20
Load 2
1000 MW Demand
LSF = -0.30
Gen Out
(Scaled to meet Load)
GSF
LSF
GLDF
Impact on Flowgate
Control Area 1
1000
0.10
-0.20
0.30
300
Control Area 2
900
-0.30 90
390 NNL
PTP Tag would be 100MW * (.10 – (-.20)) = 30MW 8

9. Merged 430 MF Control Zone 1 New Control Area Control Zone 2
Gen 1
1100 MW Output
GSF = 0.10
Gen 2
900 MW Output
GSF = -0.20
Flowgate X
Load 1
1000 MW Demand
LSF = -0.20
Load 2
1000 MW Demand
LSF = -0.30
Gen Out
(Raw, Unscaled)
GSF
LSF
GLDF
Impact on Flowgate
Control Zone 1
1100
0.10
-0.25
0.35
385
Control Zone 2
900
-0.20
0.05 45
430 MF
No Point to Point Tag (becomes internalized) 9

10. Comparison 420 NNL 430 MF Plus Point to Point Impact Control Area 1
Gen Out
GSF
LSF
GLDF
Impact on Flowgate
Control Area 1
1000
0.10
-0.20
0.30
300
Control Area 2
900
-0.30 90 30
420 NNL
Plus Point to Point Impact
Gen Out
GSF
LSF
GLDF
Impact on Flowgate
Control Zone 1
1100
0.10
-0.25
0.35
385
Control Zone 2
900
-0.20
0.05 45
430 MF 10

11. Solution Considered multiple solutions Best Solution Found
Threshold change
Netting
Partial netting
Best Solution Found
RTOs use load shift factors similar to those used in the firm usage calculation
Control Zone impacts will be determined as if Historic CAs remain in place (GLDF = GSF – Historic LSF)
Inter-Zone Transfer Impacts will be determined as if Historic CAs remain in place (Xfer TDF = Historic TDF – Historic TDF)
Generation in a Zone in excess of Zone Load will be considered transfer MW (but sum of all Zonal Gen + Transfer Gen will not exceed RTO Load)
Market flow values will regain accuracy consistent with firm usage 11

12. Gen Out (Min of Gen or Load)
Solution Step 1
Control
Area 1
New Control Area
Control
Area 2
Gen 1
1100 MW Output
GSF = 0.10
Gen 2
900 MW Output
GSF = -0.20
Flowgate X
Load 1
1000 MW Demand
LSF = -0.20
Load 2
1000 MW Demand
LSF = -0.30
Gen Out (Min of Gen or Load)
GSF
LSF
GLDF
Impact on Flowgate
Control Area 1
1000
0.10
-0.20
0.30
300
Control Area 2
900
-0.30 90
390 MF
Calculate GTL Impacts as if Historic Footprint still existed 12

13. Solution Step 2 30 MF Control Area 1 New Control Area Control Area 2
Gen 1
1100 MW Output
GSF = 0.10
Gen 2
900 MW Output
GSF = -0.20
Flowgate X
Load 1
1000 MW Demand
LSF = -0.20
Load 2
1000 MW Demand
LSF = -0.30
Excess Gen
TDF 1
TDF 2
PTP TDF
Impact on Flowgate
1 to 2 Transfer
100
0.10
-0.20
0.30 30
30 MF
Calculate PTP Impacts of Transferring Excess MW 13

14. Comparison 420 NNL 420 MF Plus Point to Point Impact Control Area 1
Gen Out
GSF
LSF
GLDF
Impact on Flowgate
Control Area 1
1000
0.10
-0.20
0.30
300
Control Area 2
900
-0.30 90 30
420 NNL
Plus Point to Point Impact
Gen Out
GSF
LSF
GLDF
Impact on Flowgate
Control Zone 1
1000
0.10
-0.20
0.30
300
Control Zone 2
900
-0.30 90
1 to 2 Transfer
100 30
420 MF 14

15. New vs. Old Process
PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Kammer #8 xfmr l/o Kammer-South Canton 765 kV line
Moderate Increase in Flows 15

16. New vs. Old Process
PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Mt. Storm-Doubs 500/Mt. Storm-Meadow Brook 500
Mild Increase in Flows
Some Firm became Non-Firm 16

17. New vs. Old Process
PJM Impact Based on Distribution Factors calculated with
PSS/e MUST and Generator Output from Jan 5, 2005
Cook-Palisades345/BentnHrbr-Palisades345
Moderate Increase in Flows 17

18. Questions? 18

19. Reference Mathematical Explanation of Inequality19