Coordinated Transaction Scheduling (CTS) between NYISO & PJM - Fourth Joint Meeting Joint NYISO-PJM Meeting June 25, 2013 Hosted by PJM
Agenda Final Proposal Benefits Assessment Look Ahead Prices Fees and Transmission Charges Bid Guarantees and Make Whole Payments Expected Credit Requirements Expected Tariff Updates Next Steps and Proposed Timeline Q&A on proposal 2
PROPOSAL 3
CTS Background The objective of CTS is to improve interchange scheduling efficiency. This presentation provides more information about the market design for CTS between the PJM and NYISO market. The proposal is to add options for transactions: Market Participants would have the option to use either the existing economic evaluation process (LBMP Bid/Offer) or CTS (CTS Interface Bid/Offers). Both scheduling mechanisms (LBMP Bid/Offers and CTS Interface Bids) would coexist. All intra-hour scheduling of external transactions will be accelerated by 15-minutes The plan is to implement in 2014. 4
Flows between NY and PJM 5
Opportunity-PJM-NY Interface 2012 The percentage of inefficient schedules is generally around 33% 6
Opportunity in the Prices This chart shows the difference between the expected price differences (NY RTC- PJM IT SCED) and the actual price difference (NY RTD PJM RT LMP)* It shows that the expected price difference is generally consistent with the actual price difference. This indicates that there is opportunity for CTS transactions. The predicted price spread is in the right direction 73% of the time. *The NY Keystone price and the PJM NYIS price were used. August 2012 through February 2013. More analysis is presented in the Look Ahead Price section. 7
Opportunity Provide additional scheduling options for market participants in addition to options available today Increase price transparency The forward prices used in the evaluation are currently available from the NYISO and would now be made available from PJM. Increase market efficiency Scheduling transactions involves more than just the availability of the interface but providing an additional scheduling option will help marketers arbitrage the price differences between the two control areas. There are significant opportunities for increased efficiency: 31% of the time there is more than a $10 price difference between NY and PJM. There are efficiency gains to be had by stopping counter-intuitive flows (flows that go from the high priced control area to the low priced control area). Even when the flows are in the right direction there is usually space remaining on the interface. 8
Proposal Summary Bidding: Multiple bidding/scheduling options: Hourly evaluations of traditional wheel-through transactions (existing) Intra-hour evaluations of traditional LBMP Bid/Offers (existing) Intra-hour evaluations of CTS Interface Bid/Offers (new). Bidding: Intra-hour LBMP Bids and Intra-hour CTS Interface Bids may have up to four distinct bid $/MW pairs, one for each 15-minute scheduling interval of the hour. Scheduling: Intra-hour schedules established 15- minutes sooner than current intra-hour scheduling process. Scheduling: CTS Interface bids will be scheduled based on the projected price difference between PJM and NYISO at the interface. 9
Bidding Current: Import/export LBMP Bid: hourly Import/export LBMP Bid: 15 minute using second time step Wheel Bids : hourly Proposed: Import/export LBMP Bid: 15 minute using first time step Import/export CTS Interface Bid: 15 minute using first time step Wheel Bids: hourly With CTS we will be able to offer an earlier evaluation of LBMP Bids because we will use the first time step rather than the second time step of the NYISO RTC CTS interface bids/offers allow schedules to be based on the price differences projected by PJM and NYISO instead of relying on the marketer s assumptions about market conditions in the neighboring control area to provide an LBMP bid/offer. 10
Incorporate PJM s Supply Curve In Real Time, NYISO will use the real-time and lookahead prices resulting from PJM s existing SCED processes as the basis for determining which CTS Interface bids should be scheduled. The NYISO economic evaluation would schedule CTS Interface bids/offers that would be in the money given the projected prices at the interface. In practice, that means that each CTS Interface bidder identifies the price difference between PJM and NYISO s projected prices above which the transaction is willing to flow. To accomplish this evaluation, the CTS Interface bid/offer will be converted into a traditional LBMP bid (by adding/subtracting the CTS Interface bid/offer to PJM s projected proxy bus price) for consideration in NYISO s current economic scheduling software along with other, non-cts Interface bids 11
Scheduling Process The scheduling process will leverage PJM s existing Intermediate Term Security Constrained Economic Dispatch (IT SCED) that has a 2 hour look-ahead capability. The most recently available information on prices from IT SCED will be used by the Real Time Commitment (RTC) in the first time step as well as in the advisory schedules. Each RTC will also provide information on expected schedules to PJM and that information will be used in subsequent IT SCED runs. Appendix 4A provides an example of multiple marginal bids. 12
How it will work IT SCED (PJM) PJM Prices NYISO Schedules RTC (NYISO) In Real Time, NYISO will incorporate PJM s forward looking prices into its existing scheduling process for the purpose of evaluating CTS bids. PJM will incorporate advisory schedules from NYISO s scheduling process for the purpose of determining its forward-looking prices. 13
BENEFITS ASSESSMENT 14
Benefits of CTS CTS will provide an additional mechanism to bring prices in closer alignment in NY and PJM. To show how the mechanism results in increased efficiency, PJM and NYISO performed a first phase analysis three hours when there were price differences between PJM and New York and calculated the increased flow necessary to (approximately) equalize prices between PJM and New York. The three hours (in black) were chosen based on hourly real time prices differences between NY and PJM at the interface. RTD and SCED were rerun to determine what the change in schedule would be that would approximately equalize the prices in NY and PJM. 1/3/2013 HB19: An increase of 350MW of flow from NY to PJM 1/20/2013 HB 11: An increase of 440MW of flow from NY to PJM 2/18/2013 HB 12: An increase of 400MW of flow from PJM to NY Benefits are achieved with relatively small changes in interchange 15
Benefits of CTS Original Prices Revised Prices LOCALHOUR NY PJM NY-PJM Change in MW NY PJM 1/3/2013 18:00 40.08 61.36-21.28 1/3/2013 19:00 37.5 70.03-32.53 +350 MW NY to PJM 54.39 64.52 1/3/2013 20:00 34.82 64.34-29.52 1/3/2013 21:00 33.72 45.92-12.2 1/20/2013 10:00 29.86 123.81-93.95 1/20/2013 11:00 25.52 129.65-104.13 +440MW NY to PJM 125.73 131.17 1/20/2013 12:00 31.72 51.9-20.18 1/20/2013 13:00 84.51 24.33 60.18 2/18/2013 11:00 75.7 41.28 34.42 2/18/2013 12:00 66.45 35.38 31.07 +400MW PJM to NY 45.89 36.09 2/18/2013 13:00 55.48 33.17 22.31 2/18/2013 14:00 43.92 30.66 13.26 PJM and the NYISO are working on an additional benefits assessment. The process has proved somewhat more lengthy than expected and a joint teleconference meeting will be scheduled in July to review the results with stakeholders. 16
LOOK AHEAD PRICES 17
Look-Ahead Prices In New York look-ahead prices are posted on the NYISO Website and are overwritten as new prices are produced. The prices are also available in the NYISO Decision Support System (DSS) public market data. PJM s IT SCED Application provides four look ahead solution intervals over a two hour period PJM is supportive of publishing Look-Ahead prices from IT SCED Currently evaluating the specifics of what will be published What solution interval? What pricing locations? Targeting summer 2014 implementation 18
Opportunity in the Prices This chart shows the difference between the expected price differences (NY RTC- PJM IT SCED) and the actual price difference (NY RTD PJM RT LMP)* It shows that the expected price difference is generally consistent with the actual price difference. This indicates that there is opportunity for CTS transactions. The table provides the summary statistics for both the expected and actual price differences as well as the difference between the expected and actual price differences. More information is included in Appendix 1. Expected Price Difference Actual Price Difference NY RTC - PJM IT SCED NY RTD - PJM LMP Average -1.91-3.99 Mean 0.82 0.38 Max 1420.68 905.25 Min -865.85-476.98 SD 46.45 43.41 Difference between the expected Price Difference and the Actual Price Difference (NY RTC - PJM IT SCED) - (NY RTD - PJM LMP) Average 2.08 Mean 0.45 Max 1392.75 Min -871.60 SD 51.01 *The NY Keystone price and the PJM NYIS price were used. August 2012 through February 2013. 19
Improving Predicted Price Differences Both NYISO and PJM have planned improvements in RTC & IT SCED (see next two slides) To illustrate the impact of improving look ahead prices, we show the impact of a 20% improvement in RTC and IT SCED. Note that the distribution becomes higher in the middle and lower on the tails Difference between the expected Price Difference and the Actual Price Difference (NY RTC - PJM IT SCED) - (NY RTD - PJM LMP) Average 2.08 Mean 0.45 Max 1392.75 Min -871.60 SD 51.01 Difference between the expected Price Difference and the Actual Price Difference with a 20% improvement in IT SCED and RTC (Improved NY RTC - Improved PJM IT SCED) - (NY RTD - PJM LMP) 1.67 0.36 1114.20-697.28 40.81 20
Continued Improvements PJM IT SCED Current Functions Commits CTs for energy and constraint control Performs the Three Pivotal Supplier Test Commits Demand Resources for energy Provides Intra hour commitment recommendations for Regulation and Reserve resources Opportunities for Improvements Evaluating accuracy of input data Enhanced Operator training Increased functionality 21
Continued Improvements NY RTC Current Functions Economic commitment of CTs and eligible Combine Cycle CTs Economic scheduling of interchange transactions Performs Automated Mitigation Processes (AMP) Opportunities for Improvements* More efficient RTD/RTC Coordination Continued Improvements to Load Forecasts * All projects subject to project prioritization. 22
FEES AND TRANSMISSION CHARGES 23
Fees and charges There was a request to report on the fees faced by transactions in both PJM and NYIOS. At the April 2 joint stakeholder meeting PJM and NY reviewed the different fee and charges that imports/exports and wheels are subject to and reported the approximate annual charges for each of those fees. Stakeholders requested that these fees be reported in $/MWh. Historical charges in NY and PJM from November 2012 through April 2013 are included the following slides. Appendix 6 also includes the month by month in the same format. 24
Fees and charges The fees and charges are grouped by type Administrative Charges Ancillary Services Other RS 1 Charges (NYISO only) Guarantee and Make Whole Payments Transmission service And are reported separately for Exports and Imports for November 2012 through January 2013. Additional data is reported in Appendix 6. 25
EXPORTS NYISO NYISO PJM PJM FEE CATEGORY* Nov2012 Rate ($/MWh) Nov2012 Settlement ($) Nov2012 Rate ($/MWh) Nov2012 Settlement ($) ADMINISRATIVE CHARGES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.64) ($109,354) ($0.27) ($137,112) ANCILLARY SERVICES Voltage Support Service (RS2 NYISO and PJM) ($0.37) ($63,220) ($0.18) ($131,029) Operating Reserves (RS5 NYISO) ($0.36) ($61,511) n/a n/a Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) ($46,422) Schedule 6A - Black Start (PJM) n/a n/a ($0.02) ($11,819) OTHER RS1 CHARGES (NYISO) Ramapo PAR Operation ($0.02) ($3,417) n/a n/a Station 80 Operation ($0.00) ($283) n/a n/a DAM Energy Residual ($1.01) ($172,574) n/a n/a DAM Loss Residual $1.57 $268,258 n/a n/a RT Energy Residual $0.08 $13,669 n/a n/a RT Loss Residual $0.03 $5,126 n/a n/a RT Congestion Residual $0.03 $5,126 n/a n/a Financial Impact Charge Credit $0.00 $399 n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS Import Supplier Guarantee (NYISO) ($0.00) ($442) n/a n/a DAMAP (NYISO) ($0.08) ($13,669) n/a n/a DAM PS BPCG (NYISO) ($0.12) ($20,504) n/a n/a RT PS BPCG (NYISO) ($0.78) ($133,275) n/a n/a DAM TRANS BPCG (NYISO) ($0.00) ($12) n/a n/a RT TRANS BPCG (NYISO) ($0.02) ($2,929) n/a n/a Supplemental Event Credit (NYISO) ($0.00) ($540) n/a n/a Operating Reserve (PJM) n/a n/a ($1.99) ($206,895) TRANSMISSION SERVICE NTAC(NYISO) ($0.79) ($134,983) n/a n/a Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) ($5.03) ($859,451) ($0.67) ($670,208) TOTAL FEES ($7.51) ($1,283,587) ($1,203,485) Total Export MWh 170,865 *The Fees do not include charges for Energy, Losses and Congestion 26
EXPORTS NYISO NYISO PJM PJM FEE CATEGORY* Dec2012 Rate ($/MWh) Dec 2012 Settlement ($) Dec2012 Rate ($/MWh) Dec 2012 Settlement ($) ADMINISRATIVE CHARGES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.64) ($77,253) ($0.26) ($233,601) ANCILLARY SERVICES Voltage Support Service (RS2 NYISO and PJM) ($0.37) ($44,662) ($0.18) ($200,394) Operating Reserves (RS5 NYISO) ($0.22) ($26,556) n/a n/a Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) ($81,023) Schedule 6A - Black Start (PJM) n/a n/a ($0.09) ($101,257) OTHER RS1 CHARGES (NYISO) Ramapo PAR Operation ($0.02) ($2,414) n/a n/a Station 80 Operation ($0.00) ($200) n/a n/a DAM Energy Residual ($0.79) ($95,359) n/a n/a DAM Loss Residual $1.29 $155,713 n/a n/a RT Energy Residual $0.07 $8,450 n/a n/a RT Loss Residual $0.07 $8,450 n/a n/a RT Congestion Residual $0.14 $16,899 n/a n/a Financial Impact Charge Credit $0.00 $282 n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS Import Supplier Guarantee (NYISO) ($0.00) ($312) n/a n/a DAMAP (NYISO) ($0.05) ($6,035) n/a n/a DAM PS BPCG (NYISO) ($0.09) ($10,864) n/a n/a RT PS BPCG (NYISO) ($0.20) ($24,142) n/a n/a DAM TRANS BPCG (NYISO) ($0.00) ($9) n/a n/a RT TRANS BPCG (NYISO) ($0.02) ($2,069) n/a n/a Supplemental Event Credit (NYISO) ($0.00) ($382) n/a n/a Operating Reserve (PJM) n/a n/a ($2.74) ($129,589) TRANSMISSION SERVICE NTAC(NYISO) ($0.88) ($106,484) n/a n/a Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) ($5.01) ($604,747) ($0.67) ($1,209,637) TOTAL FEES ($6.72) ($811,696) ($1,955,501) Total Export MWh 120,708 *The Fees do not include charges for Energy, Losses and Congestion 27
EXPORTS NYISO NYISO PJM PJM FEE CATEGORY* Jan2013 Rate ($/MWh) Jan2013 Settlement ($) Jan2013 Rate ($/MWh) Jan2013 Settlement ($) ADMINISRATIVE CHARGES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.69) ($106,576) ($0.30) ($267,770) ANCILLARY SERVICES Voltage Support Service (RS2 NYISO and PJM) ($0.36) ($55,605) ($0.18) ($256,436) Operating Reserves (RS5 NYISO) ($0.40) ($61,783) n/a n/a Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) ($2,188) Schedule 6A - Black Start (PJM) n/a n/a ($0.09) ($130,273) OTHER RS1 CHARGES (NYISO) Ramapo PAR Operation ($0.02) ($3,089) n/a n/a Station 80 Operation ($0.00) ($256) n/a n/a DAM Energy Residual ($1.61) ($248,677) n/a n/a DAM Loss Residual $2.50 $386,145 n/a n/a RT Energy Residual $0.24 $37,070 n/a n/a RT Loss Residual $0.14 $21,624 n/a n/a RT Congestion Residual $0.25 $38,615 n/a n/a Financial Impact Charge Credit $0.00 $360 n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS Import Supplier Guarantee (NYISO) ($0.00) ($400) n/a n/a DAMAP (NYISO) ($0.14) ($21,624) n/a n/a DAM PS BPCG (NYISO) ($0.44) ($67,962) n/a n/a RT PS BPCG (NYISO) ($0.81) ($125,111) n/a n/a DAM TRANS BPCG (NYISO) ($0.00) ($11) n/a n/a RT TRANS BPCG (NYISO) ($0.02) ($2,648) n/a n/a Supplemental Event Credit (NYISO) ($0.00) ($488) n/a n/a Operating Reserve (PJM) n/a n/a ($7.10) ($1,253,714) TRANSMISSION SERVICE NTAC(NYISO) ($0.84) ($129,745) n/a n/a Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) ($4.97) ($767,656) ($2.16) ($1,685,109) TOTAL FEES ($7.17) ($1,107,818) ($3,595,490) Total Export MWh 154,458 *The Fees do not include charges for Energy, Losses and Congestion 28
IMPORTS NYISO NYISO PJM PJM Fee Category Nov2012 Rate ($/MWh) Nov 2012 Settlement ($) Nov2012 Rate ($/MWh) Nov 2012 Settlement ($) ADMINISRATIVE FEES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.26) ($258,662) ($0.27) ($6,887) ANCILLARY SERVICES Voltage Support Service (RS2 PJM) n/a n/a ($0.18) ($291) Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) ($3) Schedule 6A - Black Start (PJM) n/a n/a ($0.02) ($26) GUARANTEE/ "MAKE WHOLE" PAYMENTS Operating Reserve (PJM) n/a n/a ($1.97) ($203,413.06) TRANSMISSION SERVICE Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) n/a n/a ($2.16) ($1,072.67) TOTAL FEES ($0.26) ($258,662) ($4.69) ($211,693.59) Total Import MWh 997,064 29
IMPORTS NYISO NYISO PJM PJM Fee Category Dec2012 Rate ($/MWh) Dec 2012 Rate ($) Dec2012 Rate ($/MWh) Dec 2012 Rate ($) ADMINISRATIVE FEES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.26) ($346,592.76) ($0.26) ($4,638.95) ANCILLARY SERVICES Voltage Support Service (RS2 PJM) n/a n/a ($0.18) ($131.82) Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) ($13.68) Schedule 6A - Black Start (PJM) n/a n/a ($0.09) ($66.61) GUARANTEE/ "MAKE WHOLE" PAYMENTS Operating Reserve (PJM) n/a n/a ($2.68) ($13,064.09) TRANSMISSION SERVICE Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) n/a n/a ($2.16) ($502.50) TOTAL FEES ($0.26) ($346,592.76) ($5.46) ($18,417.64) Total Import MWh 1,341,894 30
IMPORTS NYISO NYISO PJM PJM Fee Category Jan2013 Rate ($/MWh) Jan 2013 Rate ($) Jan2013 Rate ($/MWh) Jan 2013 Rate ($) ADMINISRATIVE FEES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.28) ($333,577) ($0.30) ($7,096.20) ANCILLARY SERVICES Voltage Support Service (RS2 PJM) n/a n/a ($0.18) ($18.25) Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a ($0.09) $0.00 Schedule 6A - Black Start (PJM) n/a n/a ($0.09) ($9.27) GUARANTEE/ "MAKE WHOLE" PAYMENTS Operating Reserve (PJM) n/a n/a ($6.86) ($611,252.69) TRANSMISSION SERVICE Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) n/a n/a ($2.16) ($67.00) TOTAL FEES ($0.28) ($333,577) ($9.69) ($618,443.42) Total Import MWh 1,199,497 31
Cross-Border Transaction Fees The Coordinated Transaction Scheduling (CTS) project did not initially include the elimination of fees allocated to external transactions. Stakeholders asked PJM and NYISO to revisit this issue. PJM currently does not support the elimination of Schedule 7 and 8 Fees (i.e. Regional Through and Out Rates) until NYISO and PJM reach additional agreements on Interregional Planning and Regional Transmission Enhancement Cost Allocation Maintains the realization of benefits from transmission system upgrades by the RTO funding the upgrades PJM and NYISO are continuing discussions but no date certain at this point on when an agreement may be reached PJM does propose the exemption of BOR charges for CTS transactions. 32
Cross-Border Transaction Fees (2) The PJM proposal for the exemption of BOR charges for CTS transactions includes: CTS transactions economically benefit both NYISO and PJM CTS transactions are cleared and scheduled in response to near-term projected operating conditions in NYISO and PJM BOR charges remain as they are today for traditional transactions BOR charges will also be applied in the instance of a day ahead schedule being served via a CTS transaction that is not dispatched in real time 33
Cross-Border Transaction Fees (3) The NYISO supports the reciprocal elimination fees allocated to external transactions. Given PJM s proposal, we consider the equivalent fees in NY to be the BPCG/Make Whole fees paid by CTS transactions. The NYISO is proposing to eliminate the following fees for exports and wheels: Import Supplier Guarantee, DAMAP, DAM PS BPCG, RT PS BPCG, DAM TRANS BPCG, RT TRANS BPCG, and Supplemental Event Credit for CTS transactions. 34
BID GUARANTEES/MAKE WHOLE PAYMENTS 35
Bid Guarantees/Make Whole Payments PJM and NY will both change their Make Whole Payments for external transactions: PJM will not provide make whole payments for CTS transactions. NYISO will not provide make whole payments for CTS transactions or LMBP transactions with PJM. CTS Transaction imports bids will not be protected from the latency between the scheduling (RTC) and settlement prices (RTD) and will also not be eligible for Import Curtailment Guarantees. RT LBMP bids are moving from second time step to the first time step in the NY market, and Because it would also not be appropriate to protect some RTC scheduled 15 minute transaction from latency and not others, The proposal eliminates real-time Bid Production Cost Guarantees (BPCG) and eligibility for Import Curtailment Guarantees for RT LBMP bids. It is not readily apparent what bid guarantees/make whole payments should apply for CTS Transactions: For example, the marketer agrees to flow for a $5 price difference. PJM IT SCED projects $17/MWh and NY RTC projects $23/MWh. The transaction is scheduled. The final settlement prices are $20/MWh in PJM and $24/MWh in NY (a $4/MWh difference). What could be due the marketer and which loads should pay? 36
Bid Guarantees/Make Whole Payments (2) Currently, in NY, only 15 minute scheduled transactions with PJM are eligible for BPCGs and Import Curtailment Guarantees. Summary of NY BPCG and Import Curtailment Guarantees: RT BPCGs at the PJM interface (Keystone, Neptune and Linden) 2012 Total $952,145 27 Billing Organizations received payments Average $35,265 to billing organizations receiving RT BPCGs for transactions. 2013 through April: Total $43,341 2012 January through April: Total $ 306,614 12 Billing Organizations received payments Average $3,612 to billing organizations receiving RT BPCGs for transactions. Import Curtailment Guarantees at the PJM interface (Keystone, Neptune and Linden) 2012 Total $172,030 5 Billing Organizations received payments Average $34,406 to billing organizations receiving Import Curtailment Guarantees. 2013 through May: Total $113,578 2012 January through April: Total $47,272 4 Billing Organizations received payments Average payout: $28,395 to billing organizations receiving Import Curtailment Guarantees. 37
EXPECTED CHANGES TO CREDIT REQUIREMENTS WITH CTS 38
Credit Requirement Changes At the last February meeting a stakeholder requested that information be provided on credit requirements for CTS transactions. PJM and NYISO will continue to maintain separate credit requirements. Discussion of NYISO s Credit Requirement changes has begun in the NYISO Credit Policy Working Group. The next meeting is scheduled for July 12 th. PJM is discussing Credit Requirement changes in the Credit Subcommittee and the Market Implementation Committee 39
Credit Requirement Changes No changes expected to Day-Ahead Scheduling so there are no changes expected to credit requirements for Day-Ahead Imports, Exports or Wheel Through transactions in either PJM or NYISO. In Real-time, CTS Transaction Bids will likely impact Export credit requirements in PJM and the NYISO including: the way in which the credit coverage per megawatt is determined, the megawatt amount for which credit coverage would be required, and the timing of credit coverage adjustments. The credit requirements for Real-time Imports and Wheels Through are not expected to change. 40
PJM Settlements PJM supports changing the settlement time frame for all interchange transactions from hourly settlement currently to 15 minute settlements to align with interchange scheduling time frames Will require discussion and approval within the PJM stakeholder process Implementation timing to be determined 41
EXPECTED TARIFF CHANGES 42
Tariff Changes Each ISO/RTO will pursue tariff changes, as needed, with their stakeholders. Expected process and timeline: NYISO: MIWG Review of tariff changes (June/July) Approval by the Business Issues Committee (BIC) (August) Approval by the Management Committee (MC) (August) PJM: MIC Review of tariff changes (June/July) MRC Review of tariff changes (July/August) Approval by Members Committee (MC) (August) 43
PJM Tariff and OA Changes CTS will require changes to the PJM Tariff and Operating Agreement with respect to: Definitions; Look-ahead price concept; Bid/offer requirements and mechanisms; Credit requirements and mechanisms; Clearing mechanisms; Settlement mechanisms; Fees, charges, and uplift mechanisms, as applicable; Various carve-outs that reflect the different treatment of CTS transactions as compared to other types of transactions 44
NY Expected Tariff Changes For the most part we can leverage all the drafting that was done for CTS with ISO NE so the changes are not expected to be extensive however the revisions will impact a number of sections. Revisions are expected to the following tariff sections: MST 2.2 Definitions - B MST 2.3 Definitions - C MST 4.4 Real-Time Markets and Schedules, MST 17.1 Pricing rules, MST 31 Need to clarify that this section applies to CTS with ISO NE only, OATT 1.3 the equivalent to MST 2.3, OATT 6.1,6.2, and 6.5 these are the sections that relate to fees and charges. We are still reviewing the NYISO Tariffs and Operating Agreements to evaluate if additional changes are needed. 45
NEXT STEPS 46
Proposed Timeline Final Joint Stakeholder Meeting Benefit Assessment Tele- Conference NYISO and PJM FERC Filing Independent NYISO Bidding Platform MP Sandbox Testing Implement PJM Stakeholder Process FERC approval Independent PJM Sandbox Testing NYISO Stakeholder Process 47
Proposed Next Steps Proposed Implementation Timeline EOY-2012: Introduce to Stakeholders Mid-2013: Market Design Approved Q4 2014: Implement A joint Benefits Assessment teleconference will be scheduled. Each ISO/RTO will pursue tariff changes, as needed, with their stakeholders. 48
APPENDIX 49
List of Appendices Appendix 1: Predicted & Actual Price Differences Appendix 2: CTS Timeline Appendix 3: Feedback Loop Appendix 4: Expanded Example with Timeline Appendix 4A: Example With Multiple Offers on the Margin Appendix 5: Look Ahead Price Analysis Appendix 6: Monthly Fees and Charges for November 2012 through April 2013 50
APPENDIX 1: PREDICTED & ACTUAL PRICE DIFFERENCES 51
Predicted Price Difference & Actual Price Difference The predicted price spread is in the right direction 73% of the time (i.e., in the top right or bottom left quadrant) And the data is generally around the 45 degree diagonal. Perfectly predicted prices would be on the 45 degree diagonal. Points above/below the 45 degree line indicate that the predicted price difference is greater than/less than the real time price difference. 52
There is month to month variation January 2013 was more volatile than December 2012. 53
APPENDIX 2: CTS PROPOSAL SUMMARY 54
Proposal Summary Bidding: Multiple bidding/scheduling options: Hourly evaluations of traditional wheel-through transactions (existing) Intra-hour evaluations of traditional LBMP Bid/Offers (existing) Intra-hour evaluations of CTS Interface Bid/Offers (new). Bidding: Intra-hour LBMP Bids and Intra-hour CTS Interface Bids may have up to four distinct bid $/MW pairs, one for each 15-minute scheduling interval of the hour. Scheduling: Intra-hour schedules established 15- minutes sooner than current intra-hour scheduling process. Scheduling: CTS Interface bids will be scheduled based on the projected price difference between PJM and NYISO at the interface. 55
Bidding Current: Import/export LBMP Bid: hourly Import/export LBMP Bid: 15 minute using second time step Wheel Bids : hourly Proposed: Import/export LBMP Bid: 15 minute using first time step Import/export CTS Interface Bid: 15 minute using first time step Wheel Bids: hourly With CTS we will be able to offer an earlier evaluation of LBMP Bids because we will use the first time step rather than the second time step of the NYISO RTC CTS interface bids/offers allow schedules to be based on the price differences projected by PJM and NYISO instead of relying on the marketer s assumptions about market conditions in the neighboring control area to provide an LBMP bid/offer. 56
Bidding (2) All Bids/offers will continue to be provided no later than 75 minutes before the market hour. Intra-hour LBMP Bids and Intra-hour CTS Interface Bids may have up to four distinct bid curves (each with up to eleven $/MW pairs), one curve for each 15-minute scheduling interval of the market hour. Each bid curve must be submitted by 75-minutes prior to the scheduling hour. Participants who do not want to be price sensitive can use their bids/offers to make their transactions appear more like price takers. 57
Maintaining the Existing Bid Window CTS Interface bids allow schedules to be based on price differentials instead of relying on the Marketer s assumptions about market conditions in the neighboring control area to inform an LBMP bid/offer. CTS Interface bids will be evaluated 15 minutes in advance of the scheduling period. Participants may provide a distinct bid curve for each 15-minute scheduling interval. The 75 min bid window allows for the consolidated input of all relevant bid/offer information for the forward looking energy and ancillary service co-optimization. Developing schedules based on the cooptimized procurement of energy and ancillary services helps ensure a least-bid cost solution, as well as consistent schedules and prices, minimizes uplift, and provides time to implement needed market power & manipulation protections. 58
Maintaining the Existing Bid Window (2) The existence of uncertainty about market conditions in both control areas has led to concerns that the 75 minute ahead bid window is too far in advance of the economic evaluation. Interface bids allow schedules to depend on price differentials instead of relying on the Marketer s assumptions about market conditions in the neighboring control area to inform an LBMP bid/offer. Interface bids will be evaluated15 minutes in advance of the scheduling period. Participants may provide a distinct bid $/MW pair for each 15-minute scheduling interval. We believe this scheduling flexibility substantially addresses the impact of uncertainty and that there is little to be gained by a shorter bid window. The 75 min bid window allows for the consolidated input of all relevant bid/offer information for the forward looking energy and ancillary service cooptimization. This provides least-bid cost as well as consistent schedules and prices, and minimizes uplift and needed market power & manipulation protections. 59
Maintaining the Existing Bid Window (3) The NYISO has considered a rolling 75 minute close prior to each 15 minute scheduling period Unable to accommodate a rolling 75 minute close because it would need to apply to all types of customers (to efficiently schedule the look ahead there needs to be a variety of resources available and their nearterm offers need to be locked) There are also concerns of significant software performance degradation because it would be a four-fold increase in the number of bids/offers that need to be handled on a daily basis It is not apparent that there are meaningful incremental benefits to market efficiency with a rolling 75 minute close. Would also conflict with the NERC tagging requirement during Transmission Loading Relief (TLR) events when all next-hour information must be available by forty-minutes prior to the operating hour. Therefore, this proposal allows a distinct bid $/MW pair for each 15- minute scheduling interval but they will still be subject to the existing 75 minute ahead bidding window. 60
Bidding Time Line 61
PJM Transmission and Ramp Reservations Current PJM Timing Requirements (Transmission Service): Hourly Transmission Service Earliest Request 08:00 day-ahead (09:00 Spot-In) Latest Request 0 minutes ahead Provider Response within 15 minutes (automated done in seconds) Customer Confirmation within 15 minutes Automated Release or Annulment of Spot-In service (30 minutes after queued if no valid Tag) Assumes same day request. Day ahead requests annulled within 2 hours of queue Aligns with NAESB Wholesale Electric Quadrant (WEQ) 001-4.13 62
PJM Transmission and Ramp Reservations (2) Current PJM Timing Requirements (Ramp Reservations and Energy Scheduling): Ramp Reservations and Expirations Latest request 30 minutes ahead Pending status maintained 10 minutes if queued within 1 hour of start-time 15 minutes if 1 hour < queued < 4 hours Hourly Energy Scheduling No earliest submittal requirement Latest Schedule 20 minutes ahead Aligns with NAESB WEQ 004-D and NERC INT-006-3 63
Scheduling Real Time scheduling determination. Looking to maintain NYISO s economic schedule market design & potentially leverage existing NYISO software capabilities and look ahead features. Looking to maintain PJM s market evaluation, leverage PJM s existing software and minimize any build out of the software. No changes expected to Day Ahead Scheduling As the Real Time market outcomes change we expect existing/proposed arbitrage mechanisms to be effective in arbitraging the Day Ahead and Real Time markets. 64
Scheduling Process Proposing to set schedules every 15 minutes for the period of time 30 to 45 minutes out from when the system information is gathered by the dispatch software ( initialization ). This is referred to as First Time Step The current intra-hour scheduling of LBMP bids/offers with PJM sets schedules 45 to 60 minutes from initialization ( Second Time Step ). Implications Wheel-though transactions will continue to only be scheduled hourly (They will be the only transactions with hourly scheduling at the NYISO/PJM interfaces) 65
Scheduling Process (2) The scheduling process will leverage PJM s existing Intermediate Term Security Constrained Economic Dispatch (IT SCED) that has a 2 hour look-ahead capability. The most recently available information on prices from IT SCED will be used by the Real Time Commitment (RTC) in the first time step as well as in the advisory schedules. Each RTC will also provide information on expected schedules to PJM and that information will be used in subsequent IT SCED runs. 66
Incorporate PJM s Supply Curve In Real Time, NYISO will use the PJM s proxy bus process and resulting real-time and look-ahead prices to determine which CTS Interface bids should be scheduled. The NYISO economic evaluation would schedule CTS Interface bids/offers that would be in the money given the projected prices at the interface. In practice, that means that each CTS Interface bidder identifies the price difference between PJM and NYISO s projected prices above which the transaction is willing to flow. To accomplish this evaluation, the CTS Interface bid/offer will be converted into a traditional LBMP bid (by adding/subtracting the CTS Interface bid/offer to PJM s projected proxy bus price) for consideration in NYISO s current economic scheduling software along with other, non-cts Interface bids 67
How it will work IT SCED (PJM) PJM Prices NYISO Schedules RTC (NYISO) In Real Time, NYISO will incorporate PJM s forward looking prices into its existing scheduling process for the purpose of evaluating CTS bids. PJM will incorporate advisory schedules from NYISO s scheduling process for the purpose of determining its forward-looking prices. 68
APPENDIX 3: FEEDBACK LOOP 69
Feedback loop The next slide shows a single loop from IT SCED to RTC and back again to IT SCED. The following slide shows the interaction of multiple loops. 70
Information flow from PJM s IT SCED to NYISO s RTC to PJM s IT SCED 71
72
APPENDIX 4: EXPANDED EXAMPLE WITH TIMELINE 73
Example with Timeline At the February meeting there was a request to add a timeline to an example. This is an expansion of the first example presented at the that joint Stakeholder meeting and it was presented at the April joint Stakeholder meeting. This example includes the following simplifying assumptions: The marketer is assumed to be purchasing in PJM at the PJM price, importing energy from PJM into NY and selling the energy in NY at the NY price. Note that in this example we are no longer assuming that the settlement price in NYISO is equal to the scheduling (RTC) price This example (in purple) focuses on scheduling a single 15 minute interval from T to T+15 Every 15 minutes the NYISO provides RTC advisory schedules to PJM which are incorporated into the PJM ramp calculation and every 15 minutes RTC incorporates the expected prices from IT SCED. The example only includes time steps relevant to scheduling a transactions for the interval from T to T+15. 74
Example with Timeline (2) Before T-75: Marketer requests transmission, and ramp from PJM, PJM approves transmission reservation, ramp and etags In the NYISO MIS the marketer enters an import (from PJM to NY) CTS Transaction bid of $5/MWh for the first fifteen minutes of hour T, The marketer also enters import CTS Transaction bids for the other three intervals in hour T 75
Example with Timeline (3) T-75: NYISO locks bids, removes bids with no etags and curtails to zero etags with no bids Marketers etags requests after this point for hour T will not be approved. T-60: RTC sends schedules to IT SCED T-40: IT SCED sends prices for T to RTC: IT SCED projects an Interval 2 price of $17/MWh 76
Example with Timeline (4) T-30 to T-15: Rolling RTC evaluates and posts, CTS schedules are established for first fifteen minutes of hour T, The RTC projects prices of $23/MWh for the first interval of hour T. Since PJM s IT SCED price projection was $17/MWh and RTC s projected price is $23/MWh, the CTS Transaction is scheduled ($17/MWh+$5/MWh= $22/MWH< $23/MWh). etags updated with the RTC schedules RTC sends look-ahead schedules for the PJM interfaces to IT SCED 77
Example with Timeline (5) T-10 to T-5: Rolling RTD evaluates and posts for T-5 to T. T-5 NYISO Interchange Ramp Begins for T. T-5 to T: T: Rolling RTD post and sets first 5 minute NYISO settlement price of $24/MWh. PJM first 5 minute RT LMP price of $15/MWh. 78
Example with Timeline (6) T to T+5: Rolling RTD posts second 5 minute NYISO settlement price for t+5 to t+10 of $19/MWh T+5: PJM second 5 minute RT LMP of $20/MWh T+5 to T+10: Rolling RTD post third 5 minute NYISO settlement price for t+10 to t+15 of $29/MWh T+10 NYISO Interchange Ramp Begins for T+15 T+10: PJM third 5 minute RT LMP of $25/MWh. 79
Example with Timeline (7) Balance sheet: The CTS Transaction purchased energy at an average of $20/MWh in PJM. PJM first 5 minute RT LMP price of $15/MWh. PJM second 5 minute RT LMP of $20/MWh PJM third 5 minute RT LMP of $25/MWh. Average PJM price: ($15+$20+$25)/3= $20 80
Example with Timeline (8) Balance sheet (continued): The CTS Transaction was paid an average of $24/MWh in NY. NYISO first 5 minute settlement price of $24/MWh. NYISO second 5 minute settlement price for t+5 to t+10 of $19/MWh. NYISO third 5 minute settlement price for t+10 to t+15 of $29/MWh. Average NY price: ($24+$19+$29)/3=$24 The final price difference was $4/MWh. PJM Final Price= $20 NY Final Price= $24 81
APPENDIX 4A: EXAMPLE WITH MULTIPLE OFFERS ON THE MARGIN 82
Example with Timeline Before T-75: Marketers requests transmission, and ramp from PJM, PJM approves transmission reservation, ramp and etags In the NYISO MIS one marketer enters a 100MW import (from PJM to NY) CTS Transaction bid of $6/MWh for the first fifteen minutes of hour T, Another marketer enters a 100MW import (from PJM to NY) LBMP Transaction bid of $23/MWh for the first fifteen minutes of hour T The marketers also enter import CTS and LBMP Transaction bids for the other three intervals in hour T, respectively 83
Example with Timeline (2) T-75: NYISO locks bids, removes bids with no etags and curtails to zero etags with no bids Marketers etags requests after this point for hour T will not be approved. T-60: RTC sends schedules to IT SCED T-40: IT SCED sends prices for T to RTC: IT SCED projects an Interval 2 price of $17/MWh 84
Example with Timeline (3) T-30 to T-15: Rolling RTC evaluates and posts, CTS and LBMP import schedules are established for first fifteen minutes of hour T, The RTC projects prices of $23/MWh for the first interval of hour T, based on needing 140MW of PJM to NY imports to economically meet its load. 100MW LBMP OFFER 140MWs Needed 100MW CTS OFFER 85
Example with Timeline T-30 to T-15: Since PJM s IT SCED price projection was $17/MWh and RTC s projected price is $23/MWh, the CTS Transaction is marginally scheduled to 70MW ($17/MWh+$6/MWh= $23/MWH= $23/MWh). Since RTC s projected price is $23/MWh, the LBMP Transaction is also marginally scheduled to 70MW CTS Schedule = 70MWs LBMP Schedule = 70MWs 140MWs Needed 86
APPENDIX 5 LOOK AHEAD PRICE ANALYSIS 87
NYISO Look-Ahead Prices The following analysis covers the first interval of the RTC and compares those prices to the average RTD prices for that same time period. The first interval is the interval that CTS will be using along with the PJM IT SCED prices. Data covers two time periods: August 2012 to February 2013-15 Minute Scheduling was activated in August 2012. January 2013 to February 2013 this analysis provides information on the winter peak. Pricing point used is the PJM Keystone (the PJM reference bus) The presentation of this data at the February stakeholder meeting incorrectly labeled the data as First Interval when it was Second Interval. The results have been relabeled correctly and the results for the First Interval added to the August 2012-February 2013 slide. 88
NYISO Look-Ahead Price Analysis: August 2012-February 2013 The price difference between the RTC LBMP and the average of the three RTD LBMPs $ Difference % Occurrence First Interval Second Interval >20 3 2 RTC Interval First Interval Second Interval Mean (RTC- RTD) Median (RTC- RTD) Mean Squared Error -0.26 0.05 1152.93-2.20-0.06 670.74 10 to 20 3 3 5 to 10 6 6-5 to 5 72 72-10 to -5 6 7-20 to -10 4 5 < -20 5 5 89
NYISO Look-Ahead Price Analysis: January 2013-February 2013 The price difference between the RTC LBMP and the average of the three RTD LBMPs % Occurrence $ Difference Second Interval >20 4 10 to 20 5 RTC Interval Mean Median Second Interval Mean Squared Error -3.32-0.08 1385.83 5 to 10 7-5 to 5 64-10 to -5 7-20 to -10 6 < -20 8 90
PJM Look-Ahead Price Analysis PJM s IT SCED Application provides four look ahead solution intervals over a two hour period Analysis was performed to compare the accuracy of the IT SCED forecasted LMPs to the Real Time (RT) LMP Data referenced from January and February 2013 Pricing point representative of the NYISO Interface price 91
PJM Look-Ahead Price Analysis IT SCED Interval Mean Median Standard Deviation 1 6.38057 0.53167 55.4997 The 2 nd Interval is the solution data that will be used in the CTS process 2 6.96919 0.48667 59.0518 3 2.72133 0.15667 72.4996 4-0.22039 0.01667 78.9419 % Occurrence by Interval $ Difference 1 2 3 4 >20 15 16 16 17 10 to 20 4 5 4 4 5 to 10 6 5 5 6-5 to 5 56 54 47 42-10 to -5 4 5 6 5-20 to -10 4 4 5 6 < -20 11 11 17 20 92
APPENDIX 6: MONTHLY FEES AND CHARGES ( NOVEMBER 2012 THROUGH APRIL 2013). 93
EXPORTS NYISO NYISO PJM PJM FEE CATEGORY* Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) ADMINISRATIVE CHARGES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.68) ($718,017) Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) ANCILLARY SERVICES Voltage Support Service (RS2 NYISO and PJM) ($0.36) ($385,218) Operating Reserves (RS5 NYISO) ($0.36) ($382,262) n/a n/a Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a Schedule 6A - Black Start (PJM) n/a n/a OTHER RS1 CHARGES (NYISO) Ramapo PAR Operation ($0.02) ($19,632) n/a n/a Station 80 Operation ($0.00) ($1,758) n/a n/a DAM Energy Residual ($1.18) ($1,246,787) n/a n/a DAM Loss Residual $1.82 $1,934,479 n/a n/a RT Energy Residual $0.13 $139,052 n/a n/a RT Loss Residual $0.06 $60,862 n/a n/a RT Congestion Residual $0.22 $230,705 n/a n/a Financial Impact Charge Credit $0.00 $2,474 n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS Import Supplier Guarantee (NYISO) ($0.0026) ($2,746) n/a n/a DAMAP (NYISO) ($0.0921) ($97,683) n/a n/a DAM PS BPCG (NYISO) ($0.2569) ($272,513) n/a n/a RT PS BPCG (NYISO) ($0.3478) ($369,024) n/a n/a DAM TRANS BPCG (NYISO) ($0.0001) ($77) n/a n/a RT TRANS BPCG (NYISO) ($0.0171) ($18,186) n/a n/a Supplemental Event Credit (NYISO) ($0.0032) ($3,354) n/a n/a Operating Reserve (PJM) n/a n/a TRANSMISSION SERVICE NTAC(NYISO) ($0.88) ($935,865.86) n/a n/a Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) ($4.49) ($4,761,170.20) TOTAL FEES ($6.45) ($6,846,722) Total Export MWh 1,060,873 *The Fees do not include charges for Energy, Losses and Congestion 94
WHEELS NYISO NYISO PJM PJM Fee Category* Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) ADMINISRATIVE FEES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.68) ($58,064) ANCILLARY SERVICES Voltage Support Service (RS2 NYISO and PJM) ($0.36) ($31,151) Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a Schedule 6A - Black Start (PJM) n/a n/a Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) OTHER RS1 CHARGES (NYISO) Ramapo PAR Operation ($0.02) ($1,588) n/a n/a Station 80 Operation ($0.00) ($142) n/a n/a DAM Energy Residual ($1.18) ($100,823) n/a n/a DAM Loss Residual $1.82 $156,434 n/a n/a RT Energy Residual $0.13 $11,245 n/a n/a RT Loss Residual $0.06 $4,922 n/a n/a RT Congestion Residual $0.22 $18,656 n/a n/a Financial Impact Charge Credit $0.00 $200 n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS GUARANTEE/ "MAKE WHOLE" PAYMENTS ($0.00) ($222.08) n/a n/a DAMAP (NYISO) ($0.09) ($7,899.29) n/a n/a DAM PS BPCG (NYISO) ($0.26) ($22,037.17) n/a n/a RT PS BPCG (NYISO) ($0.35) ($29,841.66) n/a n/a DAM TRANS BPCG (NYISO) ($0.00) ($6.24) n/a n/a RT TRANS BPCG (NYISO) ($0.02) ($1,470.62) n/a n/a Supplemental Event Credit (NYISO) ($0.00) ($271.23) n/a n/a TRANSMISSION SERVICE NTAC(NYISO) ($0.88) ($75,680) Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) ($4.49) ($385,019) TOTAL FEES ($6.09) ($522,758) Total Wheel MWh 85,789 *The Fees do not include charges for Losses and Congestion 95
IMPORTS NYISO NYISO PJM PJM Fee Category Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) ADMINISRATIVE FEES Schedule 1 (NYISO)/Schedule 9 (PJM) ($0.26) ($1,735,042) ANCILLARY SERVICES Voltage Support Service (RS2 PJM) n/a n/a Schedule 1A - Transmission Owner Scheduling, System Control and Dispatch Service (PJM) n/a n/a Schedule 6A - Black Start (PJM) n/a n/a GUARANTEE/ "MAKE WHOLE" PAYMENTS Operating Reserve (PJM) n/a n/a TRANSMISSION SERVICE Transmission Service Charge(NYISO)/ Schedule 7 or 8 (PJM) n/a n/a TOTAL FEES ($0.26) ($1,735,042) Total Import MWh 6,552,976 Nov2012 through April13 Rate ($/MWh) Nov 2012 through April2013 Settlement ($) 96
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