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

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

Examples PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 101 Kammer #8 xfmr l/o Kammer-South Canton 765 kV line Flowgate Limit is 3695 3

Examples PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 1719 Mt. Storm-Doubs 500/Mt. Storm-Meadow Brook 500 Flowgate Limit is 2598 4

Examples PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 2337 Cook-Palisades345/BentnHrbr-Palisades345 Flowgate Limit is 2094 5

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: -1500 MW 6

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

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

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

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

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

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

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

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

New vs. Old Process PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 101 Kammer #8 xfmr l/o Kammer-South Canton 765 kV line Moderate Increase in Flows 15

New vs. Old Process PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 1719 Mt. Storm-Doubs 500/Mt. Storm-Meadow Brook 500 Mild Increase in Flows Some Firm became Non-Firm 16

New vs. Old Process PJM Impact Based on Distribution Factors calculated with PSS/e MUST and Generator Output from Jan 5, 2005 2337 Cook-Palisades345/BentnHrbr-Palisades345 Moderate Increase in Flows 17

Questions? 18

Reference Mathematical Explanation of Inequality 19