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April 9-10, 2013 | Westborough, ma

April 9-10, 2013 | Westborough, ma. Matthew White. Senior Economist market development. A Strategic Planning Initiative. FCM Performance Incentives. Andrew Gillespie. Parviz Alivand. Principal analyst Market development. Senior Analyst Market monitoring. Ron Coutu. MANAGER,

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April 9-10, 2013 | Westborough, ma

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  1. April 9-10, 2013 | Westborough, ma Matthew White Senior Economistmarket development A Strategic Planning Initiative FCM Performance Incentives Andrew Gillespie Parviz Alivand Principal analyst Market development Senior Analyst Market monitoring Ron Coutu MANAGER, Bus. Tech. & Solutions

  2. Overview • Plan for discussion of related topics • Performance Incentives and Bidding Behavior • Explain the impact on the supply curve using three basic cases • Concept is also the foundation for the Impact Analysis • Establish mitigation framework • The Internal Market Monitor acknowledges and approves the concept presented (i.e., maximizing expected profits) • This concept is the basis for then evaluating any ‘risk’ premium – that is, a higher price required above this level to avoid any ‘downside’ in exchange for maximum expected profits

  3. Related Topics • Further elaboration on the details of this proposal will be the topic of future presentations to the Markets Committee, including but not limited to: • Mitigation ~ April • Balancing ratio & application to zones ~ April/May • Maximum Loss Limit (or stop loss) ~ May • Financial Assurance impacts (w/B&F committee) ~ June • Establishing the Performance Payment Rate ~ June • Bilateral trading ~ July • Reliability rejection of de-list bids ~ July

  4. The Basics • All resources (with and without a Capacity Supply Obligation) will be eligible for performance payments to the extent the resource is providing energy or reserves • A scarcity condition will be any 5-minute interval when the real-time reserve clearing price includes the Reserve Constraint Penalty Factor (RCPF) • Does not include spinning reserve shortages

  5. Fcm Performance incentives Impact on Bidding Behavior

  6. Current Supply Curve New Resource $/kW-mo Resource 1 Resource 2

  7. Resource 1

  8. Resource 1 • This would be a resource that would remain active even without a Capacity Supply Obligation (CSO) • Currently a ‘price-taker’ that is, zero net risk adjusted going forward costs (profits from energy and ancillary service revenues) • The decision for this resource is whether or not to assume a CSO • Which outcome maximizes expected profits over the entire commitment period – When is the resource better off clearing in the Forward Capacity Auction? • Let’s look at the two different decision choices • Revenue with a CSO (clears the FCA) • Revenue without a CSO (not cleared in FCA)

  9. Resource 1: Revenue with a CSO • Expected revenue if entering (clearing) in the FCA (obtain a CSO for the commitment period) = Pcapacity + Performance Payments w/CSO + Net Energy & Ancillary Service (E&AS) payments - Fixed Costs Where: • Pcapacity = FCA Clearing Price * MW Cleared • Performance Payments w/CSO = Net expected performance payments • Net Energy & Ancillary Service (E&AS) payments = Expected Energy and Ancillary Service revenues • Fixed Costs = Total fixed costs

  10. Resource 1: Revenue without a CSO • Expected revenue if not entering (not clearing) in the FCA (do not obtain a CSO for the commitment period) = Pcapacity + Performance Payments w/o CSO + Net Energy & Ancillary Service (E&AS) payments - Fixed Costs Where: • Pcapacity = FCA Clearing Price * MW Cleared = 0 (since it did not clear) • Performance Payments w/oCSO = Expected performance payments (all ‘upside’) • Net Energy & Ancillary Service (E&AS) payments = Expected Energy and Ancillary Service revenues (same as previous case) • Fixed Costs = Total fixed costs (same as previous case)

  11. Resource 1: Maximize Expected Profits • Expected Profits will be maximized at a capacity price where expected revenue with a CSO is equal to or exceeds expected revenue without a CSO (this would be the offer ‘threshold’ - i.e., the minimum economic offer price) • This can be solved for by subtracting the previously defined expected revenue of the resource without a CSO from the expected revenue of the resource with a CSO, and solving for Pcapacity • At auction clearing prices equal to or greater than Pcapacity (the minimum economic offer price, or expected ‘break-even’ offer price) the resource will maximize expected profits

  12. Resource 1: Solving for Pcapacity (Expected Break-Even Offer Price) Clear in the FCA Pcapacity + Performance Payments w/CSO + Net E&AS payments - Fixed Costs minus, Not clearing in the FCA 0 + Performance Payments w/oCSO + Net E&AS payments - Fixed Costs Subtracting the two equations, and solving for Pcapacity Pcapacity = Performance Payments w/oCSO - Performance Payments w/CSO Note: ‘Net Energy & Ancillary Service (E&AS) payments’ and ‘Fixed Costs’ terms cancel

  13. Performance Payments recall, Performance Payment = Performance Payment Rate (PPR) x [Actual MW – (Balancing Ratio x CSO)] Performance Payment Rate (PPR) = $5,000/MWh(The exact value is yet to be determined, but will be constant for the commitment period) Let: (terms are for entire commitment period) A = Expected average actual MW (energy and/or reserves) Br = Expected average balancing ratio H = Expected total scarcity hours So, Performance payments = PPR x [A – (Br x CSO)] x H

  14. Resource 1: Performance Payments w/oCSO Pcapacity = Performance Payments w/oCSO - Performance Payments w/CSO Performance payments = PPR x [A – (Br x CSO)] x H Performance Payments w/oCSO = PPR x A x H Because the CSO = 0

  15. Resource 1: Performance Payments w/CSO Pcapacity = Performance Payments w/oCSO - Performance Payments w/CSO Performance payments = PPR x [A – (Br x CSO)] x H Performance Payments w/CSO = PPR x [A – (Br x CSO)] x H Let: CSO = 1MW (per unit of capacity)so that this can be rewritten as, Performance Payments w/CSO= PPR x A x H – PPR x Br x H

  16. Resource 1: Expected Break-Even Offer Price Pcapacity = Performance Payments w/oCSO - Performance Payments w/CSO Putting the terms together: Pcapacity= {PPR x A x H} – {PPR x A x H – PPR x Br x H} Simplified: Pcapacity= PPR x Br x H

  17. Resource 1: Expected Break-Even Offer Price (continued) • The resource will maximize expected profits at capacity prices equal to or greater Pcapacity • This is the minimum, or expected ‘break-even’ offer price Pcapacity≥ PPR x Br x H Note: ‘ Break-even’ meaning indifferent to having a CSO or not having a CSO, it does not mean the price making the resource profitable overall

  18. Resource 1: Expected Break-Even Offer Price (continued) Pcapacity≥ PPR x Br x H • At this price or greater, the resource will maximize expected profits • This is not the expected profit, but at this price for capacity the resource can, based on expected performance, maximize profits

  19. Resource 1: Expected Break-Even Offer Price (continued) Pcapacity≥ PPR x Br x H • What about the resource’s performance? • This does not imply performance doesn’t matter – it does! • With or without a CSO, every hour of scarcity is worth the Performance Payment Rate - $5,000/MWh in this example • Because this resource does not rely on the capacity market to recover going forward costs (covered by E&AS revenues) it is better off without any CSO when the capacity price is less than Pcapacity

  20. Resource 1: Example Pcapacity= PPR x Br x H Assumptions: PPR = $5,000/MWh Br = 0.75 H = 10 hours Pcapacity = 5,000 x 0.75 x 10 = $37,500/MW-yr, or= $3.125/kW-mo This is the participant’s estimate of the average annual balancing ratio during expected scarcity conditions This is the participant’s estimate of the expected annual total hours of scarcity conditions

  21. Resource 1: Impact on Supply Curve $/kW-mo Resource A $3.125

  22. Other Resources Like Resource 1 • Other resources like Resource 1 may not have precisely the same expected values for the balancing ratio and the expected number of scarcity conditions (different Br and H values) • The ‘flat’ part of the current curve would become upward sloping to some degree • For instance, for different expected values for H and Br: • H = 11; Br = 0.75; Pcapacity = $3.438 • H = 12; Br = 0.70; Pcapacity = $3.500 • H = 10; Br = 0.85; Pcapacity = $3.542

  23. Impact on Supply Curve PPR x Br x H $/kW-mo $3.542 $3.500 $3.438 $3.125

  24. Resource 2

  25. Current Supply Curve New Resource $/kW-mo Resource 1 Resource 2

  26. Resource 2 • This would be a resource that would not remain active without a Capacity Supply Obligation (CSO) • Currently this resource relies on the capacity market to contribute to making up the difference between the resource’s fixed costs and net E&AS revenues (i.e., the going forward costs, GFCs) • But similarly, the decision for this resource is whether or not to assume a CSO • Which outcome maximizes expected profits over the entire commitment period – When is the resource better off clearing in the Forward Capacity Auction? • Again, let’s look at the two different decision choices • Revenue with a CSO (clears the FCA) • Revenue without a CSO (not cleared in FCA)

  27. Resource 2: Revenue with a CSO (Same as Resource 1) • Expected revenue if entering (clearing) in the FCA (obtain a CSO for the commitment period) = Pcapacity + Performance Payments w/CSO + Net Energy & Ancillary Service (E&AS) payments - Fixed Costs Where: • Pcapacity = FCA Clearing Price * MW Cleared • Performance Payments w/CSO = Net expected performance payments • Net Energy & Ancillary Service (E&AS) payments = Expected Energy and Ancillary Service revenues • Fixed Costs = Total fixed costs

  28. Resource 2: Revenue without a CSO • Expected revenue if not entering (not clearing) in the FCA (do not obtain a CSO for the commitment period) = Pcapacity + Performance Payments w/o CSO + Net Energy & Ancillary Service (E&AS) payments - Fixed Costs Where: • Pcapacity = FCA Clearing Price * MW Cleared = 0 (since it did not clear) • Performance Payments w/oCSO = 0 (since it will not operate) • Net Energy & Ancillary Service (E&AS) payments = 0 (since it will not operate) • Fixed Costs = ‘unavoidable’ fixed costs

  29. Resource 2: Maximize Expected Profits • Like Resource 1, expected profits for Resource 2 will be maximized at a capacity price where expected revenue with a CSO is equal to or exceeds expected revenue without a CSO (the offer ‘threshold’ - i.e., the minimum economic offer price) • Likewise, this can be solved for by subtracting the previously defined expected revenue of the resource without a CSO from the expected revenue of the resource with a CSO, and solving for Pcapacity • At auction clearing prices equal to or greater than Pcapacity (the minimum economic offer price, or expected ‘break-even’ offer price) the resource will maximize expected profits

  30. Resource 2: Solving for Pcapacity (Expected Break-Even Offer Price) Clear in the FCA Pcapacity + Performance Payments w/CSO + Net E&AS payments - Fixed Costs minus, Not clearing in the FCA 0 + 0 + 0 – ‘unavoidable’ Fixed Costs Subtracting the two equations, and solving for Pcapacity Pcapacity = – Performance Payments w/CSO + (Fixed Costs – ‘unavoidable’ Fixed Costs – Net E&AS payments) Pcapacity = Going Forward Costs – Performance Payments w/CSO Note: If there were no expected performance payments, the Pcapacity price would be equal to the resource’s going forward costs

  31. Resource 2: Pcapacity(Expected Break-Even Offer Price) Pcapacity = Going Forward Costs - Performance Payments w/CSO Performance Payments w/CSO = PPR x [A – (Br x CSO)] x H Let: CSO = 1MW (per unit of capacity)so that this can be rewritten as, Performance Payments w/CSO= PPR x A x H – PPR x Br x H Pcapacity= GFC - [PPR x A x H – PPR x Br x H], or = PPR x Br x H + (GFC – PPR x A x H) Note: First term is exactly the same as Pcapacity for Resource 1

  32. Resource 2: Expected Break-Even Offer Price Pcapacity≥PPR x Br x H + (GFC – PPR x A x H), or ≥GFC – {PPR x [A – (Br x CSO=1)] x H} • At this price or greater, the resource will maximize expected profits • This is not the expected profit, but at this price for capacity the resource can, based on expected performance, maximize profits

  33. Resource 2: Expected Break-Even Offer Price Pcapacity≥PPR x Br x H + (GFC – PPR x A x H), or ≥GFC – {PPR x [A – (Br x CSO=1)] x H} • For resources like Resource 2, the offer price will include the same common component as Resource 1, and may include some or all of the going forward costs • If the going forward costs are offset by the expected performance, the offer will be no less than the common component (PPR x Br x H)

  34. Resource 2: Example Pcapacity=PPR x Br x H + (GFC – PPR x A x H), or = GFC – {PPR x [A – (Br x CSO=1)] x H} Assumptions:PPR = $5,000/MWhBr = 0.75H = 10 hours GFC = $27,000/MW-yr ($2.25/kW-mo)A = 0.3 (average annual expected performance)Pcapacity = 5,000 x 0.75 x 10 + (27,000 – [5,000 x 0.3 x 10]) = 37,500 + (27,000 – 15,000) = $49,500, or= 3.125 + (2.25 – 1.25) = 4.125/kW-mo These are the same system level parameters These are resource specific parameters

  35. Resource 2: Example (continued) Pcapacity=PPR x Br x H + (GFC – PPR x A x H), or = GFC – {PPR x [A – (Br x CSO=1)] x H} • In the prior example, the $27,000 ($2.25/kW-mo) of going forward costs were partially offset by the $15,000 ($1.25/kW-mo) of expected performance payments • If the expected performance (A) was higher, the expected performance payments may completely offset the going forward costs, and the resource would then not need to rely on the base payment to cover going forward costs – these would be covered by expected performance payments alone • In that case, the resource’s offer to maximize expected profits would then be the same as Resource 1 (PPR x Br x H)

  36. Resource 2: Example (continued) Pcapacity=PPR x Br x H + (GFC – PPR x A x H), or = GFC – {PPR x [A – (Br x CSO=1)] x H} • If the expected performance was nil (A=0), there would be no expected performance payments to offset the going forward costs • In this case, the resource’s offer to maximize expected profits would be the same as Resource 1 (PPR x Br x H) plus the resource’s going forward costs

  37. Resource 2: Impact on Supply Curve Resource 2 $/kW-mo $4.125 = $3.125 + $2.25 - $1.25 GFC = $2.25

  38. Other Resources Like Resource 2 • Other resources like Resource B may not have precisely the same expected values for the system level parameters (the balancing ratio and the expected number of scarcity conditions) and will have unique resource specific parameters (going forward costs and expected annual performance) • The resulting magnitude of each resource’s capacity price will vary and may shift the order of resources in the supply curve

  39. Impact on Supply Curve PPR x Br x H + (GFC – PPR x A x H) $/kW-mo In this example, Resource 2 is now lower in the supply stack

  40. New Resource

  41. Current Supply Curve New Resource $/kW-mo Resource 1 Resource 2

  42. New Resource • This would be a resource that would only enter the market with a Capacity Supply Obligation (CSO) • The decision for this resource is whether or not to assume a CSO (i.e., at what price would it assume a CSO) • Again, let’s look at the two different decision choices • Revenue with a CSO (clears the FCA) • Revenue without a CSO (not cleared in FCA) – which would be zero

  43. New Resource: Revenue with a CSO • Expected revenue if entering (clearing) in the FCA (obtain a CSO for the commitment period) = Pcapacity + Performance Payments w/CSO + Net Energy & Ancillary Service (E&AS) payments - Fixed Costs Where: • Pcapacity = FCA Clearing Price * MW Cleared • Performance Payments w/CSO = Net expected performance payments • Net Energy & Ancillary Service (E&AS) payments = Expected Energy and Ancillary Service revenues • Fixed Costs = Total Required Entry Costs

  44. New Resource: Maximize Expected Profits • The new resource will want to enter the market at a capacity price where expected profits are maximized • This minimum or ‘break-even’ offer price (Pcapacity ) can be solved for using the same methodology as used for Resource 2 • At auction clearing prices equal to or greater than Pcapacity the resource will maximize expected profits

  45. New Resource: Solving for Pcapacity (Expected Break-Even Offer Price) Clear in the FCA Pcapacity + Performance Payments w/CSO + Net E&AS payments - Fixed Costs Solving for Pcapacity; Pcapacity = - Performance Payments w/CSO + (Fixed Costs - Net E&AS payments) Currently (no performance incentives), the minimum price a participant would require to proceed with the new resource is the difference between the Total Required Entry Costs (shown above as Fixed Costs) and the expected Net E&AS payments – let’s call this the Minimum Required Price (MRP) Pcapacity = Minimum Required Price – Performance Payments w/CSO Note: If there were no expected performance payments, the Pcapacity price would be equal to the resource’s Minimum Required Price

  46. New Resource: Pcapacity(Expected Break-Even Offer Price) Pcapacity = Minimum Required Price - Performance Payments w/CSO Performance Payments w/CSO = PPR x [A – (Br x CSO)] x H Let: CSO = 1MW (per unit of capacity)so that this can be rewritten as, Performance Payments w/CSO= PPR x A x H – PPR x Br x H Pcapacity= MRP - [PPR x A x H – PPR x Br x H], or = PPR x Br x H + (MRP – PPR x A x H) Note: First term is similar to Pcapacity for Resource 1

  47. New Resource: Expected Break-Even Offer Price Pcapacity≥PPR x Br x H + (MRP – PPR x A x H), or ≥MRP – {PPR x [A – (Br x CSO=1)] x H} • At this price or greater, the resource will maximize expected profits • This is not the expected profit, but at this price for capacity the resource can, based on expected performance, maximize profits

  48. New Resource: Expected Break-Even Offer Price Pcapacity≥PPR x Br x H + (MRP – PPR x A x H), or ≥MRP – {PPR x [A – (Br x CSO=1)] x H} • For new resources, the offer price will include the same common component as Resource 1, and will include some portion of the minimum required price • Part of the minimum required price is offset by the expected performance, but the offer will still be no less than the common component (PPR x Br x H), even if all MRP is offset

  49. New Resource: Example Pcapacity=PPR x Br x H + (MRP – PPR x A x H), or = MRP – {PPR x [A – (Br x CSO=1)] x H} Assumptions:PPR = $5,000/MWhBr = 0.75H = 10 hours MRP = $120,000/MW-yr ($10.0/kW-mo)A = 0.9 (average annual expected performance)Pcapacity = 5,000 x 0.75 x 10 + (120,000 – [5,000 x 0.9 x 10]) = 37,500 + (120,000 – 45,000) = $112,500, or= 3.125 + (10.00 – 3.75) = 9.375/kW-mo These are the same system level parameters These are resource specific parameters

  50. New Resource: Example (continued) Pcapacity=PPR x Br x H + (MRP – PPR x A x H), or = MRP – {PPR x [A – (Br x CSO=1)] x H} • In the prior example, the $120,000 ($10.00/kW-mo) minimum required price was partially offset by the $45,000 ($3.75/kW-mo) of expected performance payments • For new resources, the performance (A) may reflect the average expected value over the life of the resource

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