2% Shift Factor rule and associated price discrepancies

2% Shift Factor rule and associated price discrepancies Kris Dixit

Goals • Discuss the merits of the 2% shift factor rule and understand it’s application to ERCOT Operating Procedures • Discuss price discrepancies created by the 2% shift factor rule from a generation development and market convergence standpoint • Collaborate with ERCOT, IMM and MPs to develop a mathematically consistent process to manage transmission congestion while meeting original intent of the nodal market

Managing Constraints in SCED – ERCOT Transmission and Security Operating Procedure: Section 4

2% Rule Defined – ERCOT Transmission and Security Operating Procedure: Section 4.5

Issues with the 2% rule Issue 1 – Is inconsistent though development cycles Issue 2 – Creates divergence between the CRR, DA and RT Issue 3 – Creates a situation where ERCOT may inadvertently release proprietary generation (on/off) status

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

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

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

Issue 2 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

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

Issue 2 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

Issue 2 Summary • Identical situation occurs 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 • This creates a fundamental disconnect between the three markets, leading to divergence

Issue 3 - Example Generator on Bus X has a -10% SF on this constraint. And is offline X • Based on the 2% rule constraint A-B should be active. • However Generator D is offline and the constraint is made inactive • It is a fairly trivial exercise for MPs to calculate shift factors on A-B and infer that generator D is offline, since the constraint is inactive. • This could span multiple generators if multiple generators are offline and the constraint is made inactive. D 50 MW line loaded to 102% A B

Issues Summary • The 2% rule has created locational uncertainty, not originally intended • The 2% rule does not remain consistent through a generation development process • The 2% 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 • ERCOT risks inadvertently releasing confidential generation information (ON/OFF Status) • A nodal market was intended to provide signals not only for where to build but also for where not to build. • The financial downside of a decision to build new generation based on the existing price signals provided by SCED could be enormous

What should we do? • Eliminate 2% rule, and activate all constraints irrespective of generation SF • Eliminate all 69kV lines in SCED, DAM and CRR markets or further reduce shadow price caps on 69kV lines ($500?) • Reduce shadow price caps on 69/138kV auto transformers

Pros and Cons Pros • Eliminates the fundamental disconnect between the three markets • Eliminates possibility of confidential generator information (on/off status) being inadvertently released to the market by virtue of the constraint being deactivated • Addresses concerns that considerable generation may need to be moved to move MWs on small 69kV lines. • Provides consistent price signals which are not liable to change once new generation is built, merely due to a procedural threshold • Provides better visibility of good and bad pricing locations on the grid • Could provide greater efficiencies in SCED, DAM and CRR Markets (ERCOT?) • Eliminates uncertainty, since (on/off) status of a generator with high SF is no longer a driver in congestion management • Eliminates any discrepancies between the three markets that stem from constraint management (SCED, DAM and CRR) Cons • Would create uplift if a generator is built and has a +ve SF on a 69kV constraint. ERCOT would have to manage congestion outside of SCED • Would eliminate price signals for larger 69kV lines that are currently allowed to congest

End of Presentation

69kV Violations not activated (1 Day)

2% Shift Factor rule and associated price discrepancies