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PTP Clearing Discrepancies and Related Critical LMP & CRR Award Issues

PTP Clearing Discrepancies and Related Critical LMP & CRR Award Issues. Shams Siddiqi, Ph.D. Crescent Power, Inc. (512) 619-3532 shams@crescentpower.net QMWG Meeting April 13, 2017. Background. Modeling of PTP Obligation in DAM under T-1 that result in Islanding

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PTP Clearing Discrepancies and Related Critical LMP & CRR Award Issues

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  1. PTP Clearing Discrepancies and Related Critical LMP & CRR Award Issues Shams Siddiqi, Ph.D. Crescent Power, Inc. (512) 619-3532 shams@crescentpower.net QMWG Meeting April 13, 2017

  2. Background • Modeling of PTP Obligation in DAM under T-1 that result in Islanding • Any PTP containing a disconnected settlement point (SP) will be ignored in the post-contingency (T-1) flow • DAM SPP is arbitrarily calculated for disconnected SP assuming a 0 shift factor for T-1 • Results in potentially large discrepancies between PTP Obligation bid price and DAM clearing price based on SPP difference • ERCOT proposed solution: To maintain power balance in the post-contingency power flow, rather than ignoring PTP in post-contingency power flow, distribute the PTP MW from the disconnected Settlement Point to all the other connected generators • Would make optimization price and settlement price consistent within a small tolerance • Considerations: • PTP flow could contribute to congestion far removed from the path • Would have to consider changing CRR auction to make consistent • Requires system change and extensive testing

  3. Related Consensus Issues Identified • G-1, L-1 and T-1 with SPS/RAS are not modeled in CRR and DAM but are modeled in SCED to set prices • Potential large uplift and gaming opportunities exist • Min 10*G1 + 20*G2 + 50*G3 ST: a) G1+G2+G3 = 100; b) G2+0.5*G1 <= 40 • G1=80, G2=0, G3=20, Spa=50, SPb =-80, LMP1=$10, LMP2=-$30, LMP3=$50 • Congestion rent = 100*50-80*10-20*50 = $3,200 • CRR payments = 40*(50-(-30))+200*(50-10) = $11,200 • Uplift = $8,000

  4. Solution to Related Issues • Do not model G-1, L-1 and T-1 with SPS/RAS in SCED pricing run but additional SCED run to determine base points • All market models that set prices – CRR, DAM and SCED pricing run – are consistent eliminating inconsistencies that can result in large uplifts and gaming • SCED base points may result in instances of HDL Override and some uplift

  5. Solution to PTP Obligation Issue • T-1 that results in Islanding of Generation (G-1) is exactly equivalent to T-1 with G-1 SPS/RAS except the G-1 SPS/RAS isn’t a predefined SPS/RAS but happens automatically with the T-1 • Treat T-1 that results in G-1 exactly like T-1 with G-1 SPS/RAS: • Do not model T-1 that results in G-1 in CRR, DAM and SCED pricing run; model G-1, L-1, T-1 with SPS/RAS, and T-1 that results in G-1 in SCED dispatch run • Makes CRR, DAM and SCED pricing models consistent and treats all G-1, L-1 and T-1 with pre-defined or automatic SPS/RAS consistently

  6. Concerns with ERCOT’s Solution • If a node is islanded in base case, there should be no energy or CRR award sourcing from that node and LMP at that node is “Undefined”. A credible T-1 network is treated just like base case network. • If a T-1 reduces export to 10MW from a 1000MW plant, then DAM will not award TPO with LSL>10MW. But if the T-1 islands the plant (which at best can be considered to set flow limit on the T-1 to 0), then all of a sudden DAM would award maybe up to 1000MW under ERCOT's proposal. The only way to justify this is that the resource now has an “automatic” SPS/RAS. • CRR and DAM are financial markets with no governor response modeled. Modeling such response in CRR and DAM with uncertainties around which units will online in RT and their available capacity to respond will lead to discrepancies. • The only reason to model G-1, L-1 and T-1 with G-1 in RTM is to ensure reliable physical operation post these contingencies – there is no such NERC requirement for a financial market • Thus, since a defined price is needed at each node, the better alternative is to not model T-1 that results in Islanding except in SCED dispatch run

  7. Concerns with ERCOT’s Solution • The market was and still is getting weird outcomes like having to pay more than their bid price, congestion, prices and dispatch that didn't quite make sense looking at the lightly loaded transmission system, etc. • these are typically not very significant until they blow up and the market couldn't figure out these discrepancies but trusted the black box. • Now we know the root cause of these issues and the market will want to know exactly how is works, how they can model it to predict pricing and dispatch outcomes, and how they should participate based on this information. • To understand and model T-1 with islanding (same with G-1 and L-1): • there must be transparency into how ERCOT distributes the islanded generation or energy/CRR bids/offers to other generators or Settlement Points in SCED, DAM and CRR engine. • For accurate modeling, this information will reveal ERCOT's knowledge or estimate of which units will be available, on outage, available headroom (which could vary every 5 minutes), even differences between QSEs on how they commit units within their fleet.

  8. Concerns with ERCOT’s Solution • The pricing and dispatch outcome from T-1 with islanding is quite unpredictable, depends on QSE behavior and can be manipulated: • In 3-bus example, the price at G2 is -$30/MWh and at G3/Load is $50/MWh even though the transmission system is lightly loaded. The reason is the contingency of the large, low cost generator G1 and the resulting governor response of G2. If that response is turned off, G2 and G3/Load prices become $10/MWh - there will be pressure from Load and some generators to turn off governor response.

  9. Concerns with ERCOT’s Solution • The pricing and dispatch outcome from T-1 with islanding is quite unpredictable, depends on QSE behavior and can be manipulated: • If there were another unit G1' similarly connected in a separate node (even the same node for G-1 contingencies) owned by the same QSE as G1, then if the QSE commits both G1 and G1' with exactly the same total generation, there is no congestion and prices are $10/MWh everywhere. By committing only one of those units or keeping G1' at LSL of say 10MW, the QSE gets paid $50/MWh for the 10MW at G1' and $40/MW for each CRR from Node 1-3. This is much more profitable than getting $10/MWh for all its generation and $0 for its CRRs. Thus prices throughout the market are impacted by how this QSE decides to commit and dispatch its units and it's perfectly reasonable for the QSE to commit only G1 since Load is low.

  10. Suggested Path Forward • Urgent NPRR827 has been filed to address current issue: “PTP Obligation Bids shall not be awarded where the DAM clearing price for the PTP Obligation is greater than the PTP Obligation Bid price.” • Work on correcting the issues identified by not modeling T-1 that result in islanding in CRR and DAM (use the same filter as T-1 with SPS/RAS), and not modeling G-1, L-1 and T-1 with predefined or “automatic” G-1 in SCED pricing run and add a SCED dispatch run with all contingencies modeled

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