2% Shift Factor rule and associated price discrepancies

Kris Dixit

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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

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

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

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

Issues with the 2% rule

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• 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

Issue 1 Example – 2% rule at timestamp T = 0

A B

50 MW line loaded to 102%

C

Bus C has a +10% SF on this constraint but does not see any

price signal. There is no generator on this node.

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D

Bus D has a -10% SF on this constraint but does not see any

price signal. There is no generator on this node.

• 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

Issue 1 Example – 2% rule at timestamp T = 1

A B

50 MW line loaded to 102%

C

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%

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D

Bus D has a -10% SF on this constraint. This bus will now see a price signal associated with the

reliability issue

• 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 1 Summary

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• 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

Issue 2 Example – 1: CRR Market

A B

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D

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

Bus B has a load that is being driven by its LDF due to Load

Zone (sink) bids

Line is overloading due to flow that is being driven by sink bids

on the load zone in the CRR auction.

• 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

Issue 2 Example – 2: DAM Market

A B

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D

Gen D has a -10% SF on this constraint but there are no energy offers on this node

G

Bus B has a load that is being driven by its LDF due to Load

Zone (sink) bids

Line is overloading due to flow that is being driven by sink bids on the load zone in the DAM.

• 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

Issue 2 Example – 3: RT Market

A B

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D

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

Bus B has a load that is being driven by its demand

Line is overloading due to real time flow

• 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 2 Summary

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Issue 3 - Example

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• 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.

A B

50 MW line loaded to 102%

D

Generator on Bus X has a -10% SF on this constraint. And is

offline

X

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

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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

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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

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End of Presentation

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69kV Violations not activated (1 Day)

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RTCAExecutionTime ContingencyID Contingency From To From KV To KV RatingType Rating Post CTG Flow % Violation

5/2/2012 9:47 SAPACAD8 Apache Tnp to Caddo Sw Sta T HEIGHTTN CHOCTAP 69 69 EMER 95.86 133.95 139.74

5/2/2012 9:47 SAPACAD8 Apache Tnp to Caddo Sw Sta T HEIGHTTN HEIGHTTN 69 138 EMER 120.88 -138.13 114.27

5/2/2012 9:47 SAPACAD8 Apache Tnp to Caddo Sw Sta T LAMARQUE TNPRXTAP 69 69 EMER 91.22 101.71 111.50

5/2/2012 9:47 SAPACAD8 Apache Tnp to Caddo Sw Sta T HEIGHTTN HEIGHTTN 69 138 EMER 126.91 -137.97 108.71

5/2/2012 9:47 SAPAAMO8 Apache Tnp to Amoco Tnp 138 HEIGHTTN CHOCTAP 69 69 EMER 97.69 130.26 133.34

5/2/2012 9:47 SAPAAMO8 Apache Tnp to Amoco Tnp 138 HEIGHTTN TXCITYWT 69 69 EMER 94.22 114.14 121.14

5/2/2012 9:47 SAPAAMO8 Apache Tnp to Amoco Tnp 138 LAMARQUE TNPRXTAP 69 69 EMER 93.08 98.85 106.20

5/2/2012 9:47 SAPAAMO8 Apache Tnp to Amoco Tnp 138 HEIGHTTN HEIGHTTN 69 138 EMER 125.47 -132.28 105.43

5/2/2012 9:47 SAPAAMO8 Apache Tnp to Amoco Tnp 138 HEIGHTTN HEIGHTTN 69 138 EMER 126.91 -132.69 104.56

5/2/2012 9:47 SHALFLA8 Hallettsville to Flatonia 13 FLATON MOULTO 69 69 EMER 36.84 47.20 128.13

5/2/2012 9:47 SHALFLA8 Hallettsville to Flatonia 13 YOAKUM YOAKUM 69 138 EMER 21.92 27.63 126.05

5/2/2012 9:47 SHALFLA8 Hallettsville to Flatonia 13 HENKA MOULTO 69 69 EMER 37.59 -42.44 112.91

5/2/2012 9:47 SHALFLA8 Hallettsville to Flatonia 13 HENKA SHINER 69 69 EMER 37.70 40.72 108.03

5/2/2012 9:47 XROC89 Rockport 138_69a1 138/69 KV GREGORY RINCON 69 69 EMER 60.99 -65.79 107.87

5/2/2012 9:47 XROC89 Rockport 138_69a1 138/69 KV ARANSAS GREGORY 69 69 EMER 60.72 -62.42 102.79

5/2/2012 9:47 SROCRIN8 Rockport to Rincon 138 KV GREGORY RINCON 69 69 EMER 60.99 -65.78 107.85

5/2/2012 9:47 SROCRIN8 Rockport to Rincon 138 KV ARANSAS GREGORY 69 69 EMER 60.72 -62.41 102.77

5/2/2012 9:47 SAPACAD8 Apache Tnp to Caddo Sw Sta T HEIGHTTN TXCITYWT 69 69 EMER 92.56 117.11 126.52