The Future of Nodal Trading.

Transcription

1 The Future of Nodal Trading. Moderator: Jim Krajecki, Director with Customized Solutions Panel: - Noha Sidhom, General Counsel for Inertia Power LP. - Shawn Sheehan, Principal with XO - Wes Allen, CEO of Red Wolf Trading - And you the audience 1

2 Benefit Of Financial Products in the Day Ahead Market Provide liquidity in the markets Converge Day Ahead and Real Time Price If a transaction converges the market, it is profitable If a transactions has resulted in divergence, it is unprofitable. Lower the risk and occurrence of Market Power Competition lowers cost to consumers Provide hedging tool to manage DA to RT price exposure Physical forced outage risk 2

3 Day Ahead Product Types By Market PJM Increment Offer(INC) Decrement Bid (DEC) All Nodes Available MISO Increment Offer(INC) Decrement Bid (DEC) All Nodes Available NYISO Increment Offer(INC) Decrement Bid (DEC) Seven Zones Congestion PJM Up to Congestion Subset of Nodes (~400 nodes) MISO Real-Time Congestion Hedge Under Development NYISO No congestion product available or under consideration until after nodal 3

4 Day Ahead Product Types By Market ERCOT Day Ahead Market (DAM) Offer DAM Bid All Nodes Available ISO-NE Increment Offer(INC) Decrement Bid (DEC) All nodes CAISO Convergence Bidding Most Nodes Available SPP (go-live March ) Virtual Offer (INC) Virtual Bid (DEC) All Nodes Available Congestion ERCOT Point to Point All nodes available that aren t electrically similar ISO-NE No Product under development CAISO No Product under development SPP (go-live March ) No congestion product available or under consideration 4

5 How are and Congestion Transactions Modeled differently in PJM s Day Ahead Market? INC/DEC INC is modeled as Generation at the Node Dec is modeled as Load at the node A single INC in the DA that is not physically delivered has to replaced by another resource. An equal volume of INCs/DECs within the same hour results in no Load/Gen imbalances INCs/DECs are modeled during the unit commitment run and have a large impact on the units committed in the DA market All nodes are available with a $1000 price cap Up to Congestion Modeled as a transfer of power between two nodes. By definition the transaction can not result in an energy imbalance Is modeled after the unit commitment run Does impact unit dispatch (the output level of a unit) Does Impact DA prices Only 400 nodes are available with a +/- $50 cap 5

6 Some PJM Statistics on INC/DECs vs. UTCs May 2012 April 2013 UTC (Gross) INCs/DECs (Gross) Delta (INC/DEC-UTC) Total Cleared (MWh) 367,504, ,297,775 (245,206,624) Average Daily Profit ($/day) $364,140 $188,806 ($175,334) Avg Profit/Cleared MWh ($/MWH) $0.36 $0.56 $0.20 Standard Deviation of Daily Gross Profit $628, $1,356,355 $728, % of Days Where Bid Type Has Negative Gross Profit 28.80% 51.50% 22.70% 6

7 PJM Analysis on INC/DECs vs. UTCs May 2012 April 2013 con t Each Cleared Inc/Dec transaction makes 36% more money than cleared UTC INC/DEC gross profits are more volatile than UTCs Per cleared MWh, INC/DECs are a higher risk, higher reward product compared to UTCs 7

8 PJM Performed UTC Analysis on 5 Recent Days (Total LMP) Date RT-DA (with UTCs) ($/MWh) RT-DA (w/o UTCs) ($/MWh) Improvement With UTCs Included ($/MWh) May 2, May 4, May 22, May 23, May 27,

9 Importance of Fees: Traders will only transact to the expectation of fees Therefore the DA and RT markets can only converge to the point of the expectation of the fees to be incurred Higher fees result in: More divergence Less liquidity Less competition An increase in market power concerns An increase in the cost of hedging Higher cost to consumers 9

10 PJM Transaction Fees Schedule 9: (~$.05/MWh) PJM Scheduling System Control and Dispatch PJM Settlement Market Monitoring Unit Funding DA Operating Reserves Average of $.086/MW (Jan-Sept) Balancing Operating Reserves Average of $3.72/MW East (Jan- Sept) Daily RT East Operating Reserve in 2013 has spiked to as high as $32/mw. At times can be higher than the LMP. Operating Reserve Fees are unknown until well after the transaction has settled. Congestion Schedule 9: (~$.05/MWh) PJM Scheduling System Control and Dispatch PJM Settlement Market Monitoring Unit Funding Application of Operating Reserves is under consideration Up-To Congestion charges paid $16.8 million in schedule 9 charges in 2012 and $11.5 million thus far in

11 MISO Transaction Fees Schedule 24 (Jan-Sept avg $.0137) Day Ahead Market Admin Day Ahead Schedule 24 Allocation Amount RT Net Inadvertent RT Miscellaneous Amount RT Demand Response Uplift DA RSG (DECs Only) RT RSG (INCs Only). Since a DEC can only cause more generation to be scheduled DA MISO does not apply RT uplift (RSGs) to DEC Transactions. This key difference that follows cost causation principals. Congestion What fees are to apply to the Real- Time congestion hedge is under consideration. Resettlement MISO s history of changing market rules and performing resettlements has discouraged market participation. 11

12 NYISO Transaction Fees ~10 cents/mwh total includes: NYPA Transmission Adjustment Charge (NTAC) Reserves payments for 10 and 30 minute spinning Regulation to maintain frequency NYISO cost of operation Uplift charges for out of market resources Voltage Support payments to Generators Black start charges 12

13 ERCOT Transaction Fees No market administration fees Day Ahead Make Whole Charges (~$ Per Cleared MWh) RUC Short Capacity Charges Very transaction dependant. Only applies if your transactions cause unit uplift. Congestion No market administration fees Day Ahead make whole charge (~$ Per Cleared MWh) 13

14 CAISO Transaction Fees Market Admin Fees (~$.39/MWh) Market Service Charge System Operation Charge CRR Service Charge Day Ahead Residual Unit Commitment (~$.17 per cleared MWh) 14

15 ISO-NE Transaction Fees Schedule 2 Charges (1) $ times the number of Increment Offers and Decrement Bids submitted; plus (2) $ times the number of Increment Offers and Decrement Bids cleared DA Economic NCPC - charged to day-ahead load (DEC s will pick up) This is usually under $1.00/MWh DA LSCR (local second contingency protection) NCPC - charged to DA load in the affected load (DEC s in affected load zone will pick up) This fluctuates but is generally low; it has been as high as $2.00/MWh at times in some zones RT Economic NCPC charged to RT deviation from DA schedules This charge fluctuates; it has been as low as zero and as high as $44/MWh of deviation ISO-NE is revisiting the allocation of NCPC charges and will be recommending changes soon. Both the internal and external Market Monitors believe that NCPC allocated to virtual transactions should be reduced or eliminated so changes along these lines are expected. The changes would go into effect in December 2014 at the earliest. 15

16 SPP Transaction Fees DA Virtual Transaction Fee ($0.005 per cleared Bid/Offer Curve) DA Make Whole Payment Distribution Charge Charged to both cleared Virtual Offers and Bids on a net basis per settlement location RUC Make Whole Payment Distribution Charge Similar to PJM Balancing Operating Reserve Charge. Only to be charged to Virtual Offers Congestion Not Applicable 16