2% Shift Factor dispatchable rule discussion and alternatives for the 2% rule

1. 2% Shift Factor dispatchable rule discussion and alternatives for the 2% rule Kris Dixit

2. Goals • Discuss the merits of the 2% shift factor dispatchable rule and conceptually understand its impact on convergence • Discuss 2% rule and possible options that will meet the original intent while maintaining convergence between the three markets

3. Example – 1: CRR Market Gen D has a -10% SF on this constraint but there are no counter flow offers on this node. This is the only generator with a –ve shift factor on the constraint G Line is overloading due to flow that is being driven by sink bids on the load zone in the CRR auction. • With no CRR counter-flow bids, there is technically no generation on D in the auction. Within this model, Gen D is offline • The fact that Gen D is offline, allows for line to congest and create a shadow price, thus causing a price difference between A and B in the CRR auction D Bus B has a load that is being driven by its LDF due to Load Zone (sink) bids A B

4. Issue 2 Example – 2: DAM Market Gen D has a -10% SF on this constraint but there are no energy offers on this node G Line is overloading due to flow that is being driven by sink bids on the load zone in the DAM. • With no offers on bus D (TPO or energy), generator D is offline in the DAM. This generator may have no offers because it may intend to come online as merchant or has sold capacity bilaterally. • The fact that Gen D is offline, allows for line to congest and create a shadow price, thus causing a price difference between A and B in the DAM D Bus B has a load that is being driven by its LDF due to Load Zone (sink) bids A B

5. Example – 3: RT Market Gen D has a -10% SF on this constraint. Gen D is offline. This is the only generator with a -ve shift factor on the constraint X Line is overloading due to real time flow • Generator D is offline. • Due to loads on B line A-B starts to congest • ERCOT operations would use the 2% rule to identify all generators with > 2% shift factor on the constraint that are dispatchable. • In this case there are no dispatchable generators with greater than 2% shift factor and the constraint is deactivated D Bus B has a load that is being driven by its demand A B

6. Summary • Identical situation occur in DAM, CRR and RT markets. However, congestion only occurs in DAM and CRR markets and not in RT • Nearly impossible for ERCOT’s DAM and CRR Team to account for these constraints since they are being driven by information on dispatchable generators that is not available in advance • The 2% dispatchable rule creates a fundamental disconnect between the CRR, DAM and RT markets, that cannot be accounted for in the CRR and DAM markets • This leads to divergence between the three markets

7. The 2% rule • The 2% rule has been discussed in detail at CMWG and WMS • The intent of the 2% rule was to make sure that the market did not show price signals for smaller lines that may have no locational benefit once generation is built • However the 2% rule does not remain consistent through generation development cycles (see slides 10,11,12) • The 2% rule cannot be seamlessly transitioned to the CRR and the DAM markets, since the minimum shift factor used is 0.0001 in those markets

8. Our Proposal • Eliminate 2% dispatchable rule. • Reapply the 2% rule differently by deactivating constraints on lines lower than a specific MVA threshold • For example: if we deactivated all transmission lines with capacities less than 50MVA • Such a rule can be seamlessly used across all three markets and could remain consistent through development cycles • Creates certainty for market participants that are trying to understand market exposures

9. Appendix

10. Issue 1 Example – 2% rule at timestamp T = 0 Bus C has a +10% SF on this constraint but does not see any price signal. There is no generator on this node. Bus D has a -10% SF on this constraint but does not see any price signal. There is no generator on this node. • In this specific example the line A to B is overloading and there is no generator that has > 2% shift factor on this constraint. • If there was a generator at bus C, it would have a +10% shift factor on the constraint • If activated this constraint would create a negative price on bus C, consistent with the reliability state. • Based on the 2% rule, this constraint is deactivated and SCED does not produce a price signal at bus C consistent with this state. • Prices at all four points are identical, masking the underlying reliability issue C D 50 MW line loaded to 102% A B

11. Issue 1 Example – 2% rule at timestamp T = 1 There is now a generator on this bus with a +10% SF on this constraint. Now we see price signals since there are generators with shift factors greater than 2% Bus D has a -10% SF on this constraint. This bus will now see a price signal associated with the reliability issue • Based on the historical price signals produced by SCED, bus C seems to have a good pricing profile and a developer decides to build a generator on bus C. • Since there are no historical price signals, developer will never recognize reliability issues • ERCOT and TDSP screening studies may catch this issue, only if they show up in typical base cases. If not, developer builds generation. • When developer builds the intended generation, ERCOT would activate the constraint and the generator would become a discount to the rest of the system • The only remedy would be a SPS, specifically at higher SF levels. • Point D would have been a better siting location C D 50 MW line loaded to 102% A B

12. Issue 1 Summary • The 2% rule is inconsistent through generation development cycles • The 2% rule masks potential reliability issues that are supposed to be discovered through price signals • The 2% rule is a throwback to zonal congestion management and is no longer relevant to the design intent of the nodal market