PJM Reliability Pricing Model

Transcription

1 Note: Presentation by B. Hobbs et al. on the dynamic analysis of the RPM is attached PJM Reliability Pricing Model Murty P. Bhavaraju PJM Interconnection IEEE/PES General Meeting Tampa, FL June 27, 2007 PJM 2007

2 Forward Procurement of Capacity Resources Reliability Pricing Model (RPM) is PJM s new resource adequacy construct that will replace the existing capacity construct effective June 1, RPM s FORWARD procurement of resources through a base residual auction three years prior to the delivery year: Provides long-term price signal for capacity resources. Encourages Load Serving Entities (LSEs) to make longterm bilateral contracts to hedge their locational reliability charges. Supports the Regional Transmission Expansion Planning Process (RTEPP). 2

3 Locational Value of Capacity Resources RPM recognizes import capability limitations in certain areas as identified in the PJM Regional Transmission Expansion Planning Process (RTEPP). RTEPP has currently identified 23 sub-regions as Locational Deliverability Areas (LDAs) for evaluating the locational constraints. LDA with import capability limit less than 105% of import capability requirement will be modeled as constrained LDA in RPM. RPM auction could result in higher capacity prices in the constrained areas that would encourage new generation additions or keep generating units from retiring. 3

4 Variable Resource Requirement Stabilizes Prices Variable Resource Requirement (VRR) is also referred to as Demand Curve. Defines a relationship between level of reserve and capacity price based on the net annual cost of a new combustion turbine. Recognizes the value of additional capacity above the reserve required to meet the reliability criterion. Higher price accepted when there is shortage in meeting the required capacity. VRR curves established for PJM Region and each constrained Locational Deliverability Area (LDA). 4

5 RTO Variable Resource Requirement Curve RTO Variable Resource Requirement Curve UCAP Price, $/MW-Day Quanitity, UCAP MW RTO VRR Curve 5

6 Participation in RPM Participation by LSEs for load served in PJM region is mandatory, except for those LSEs that have elected Fixed Resource Requirement (FRR) Alternative. Each LSE shall be responsible for paying a Locational Reliability Charge. May choose to hedge Locational Reliability Charges by offering capacity into the auction. Participation by resource providers is subject to the market power mitigation rules described in the tariff. 6

7 Supply in RPM Auctions Eligible Capacity Resources: Existing & planned generation in PJM Existing external generation Bilateral contracts for unit-specific capacity resources Existing & planned demand resources Qualifying Transmission Upgrades Resources must meet the requirements specified in PJM Agreements and Business Rules. 7

8 2007/2008 RPM Auction Resource Clearing Prices, $/MW-Day $40.80 $ $ LDA RTO EMAAC SWMAAC System Marginal Price [$/MW-day] $40.80 $40.80 $ Locational Price Adder [$/MW-day] $0.00 $ $ Resource Clearing Price [$/MW-day] $40.80 $ $ Final Zonal ILR Price/ Prelim. Load Obligation Rate [$/MW-day] $40.80 $ $140.16

9 Eastern MAAC Results EMAAC 07/08 $ $ $ $ $50.00 $ /08 EMAAC VRR Curve intersect 9

10 Southwestern MAAC Results SWMMAC 07/08 $ $ $ $ $50.00 $ /08 SWMAACVRRCurve intersect 10

11 RTO Results (Excluding FRR Obligations) RTO07/08 $ $ $ $ $ $50.00 $ /08 RTOVRRCurve intersect 11

12 Discussion of Results MW of demand response cleared Approx. 350 MW of new capacity offered of which 311 MW cleared Total value of CTRs = $1.48 million/day Resource clearing prices in Eastern MAAC and Southwestern MAAC above net Cost of New Entry Uncleared MW in RTO: 1,443.5 (UCAP) 12

13 3 Years Timing of RPM Auctions 23 months 13 months 4 months June May Base Residual Auction EFORd Fixed Interruptible Load for Reliability (ILR) Delivery Year First Incremental Auction 13 Second Incremental Auction Third Incremental Auction Ongoing Bilateral Market (shorter-term reconfiguration)

14 Demand Variable Resource Requirement (VRR) Curves for Base Residual Auction Locational Buy Bids for Incremental Auctions RPM Auction Process Supply Resourcespecific Sell Offers Optimization Algorithm Auction Results Resource Commitments Resource Clearing Prices UCAP Obligation values Capacity Transfer Rights Zonal Capacity Prices ILR Prices CTR Rates Locational Constraints 14

15 Bilateral Market Provides LSEs the opportunity to self-supply and hedge against the Locational Reliability Charge determined through the Base Residual and Second Incremental Auction. Provides resource providers an opportunity to cover any commitment shortages due to resource cancellations, delays, deratings, or EFORd increases, or decrease in nominated value of a planned demand resource. 15

16 Base Residual Auction Allows for procurement of unit-specific resource commitments required, after accounting for selfsupply, to satisfy the region s unforced capacity obligation for a future Delivery Year (less an amount reserved for Interruptible Load for Reliability (ILR)). Cost of procurement is allocated to LSEs serving load in the actual Delivery Year through the Locational Reliability Charge. 16

17 Incremental Auctions: First and Third Allow for an incremental procurement of resource commitments for future Delivery Year to accommodate adjustments to participants resource positions due to resource cancellations, delays, deratings, or EFORd increases, etc. Buyers pay suppliers with no change in the Locational Reliability Charge assessed to LSEs during the Delivery Year. 17

18 Incremental Auctions: Second Incremental Auction Second Incremental Auction is held ONLY to mitigate reliability concern. If increased obligation (due to increase in peak load forecast) compared with capacity cleared in the Base Residual Auction > 100 MW UCAP, the auction is conducted. Cost of procurement is allocated to LSEs serving load during the actual Delivery Year through the Locational Reliability Charge. 18

19 Locational Deliverability Areas (LDA) 1. AE 2. AEP 3. APS 4. BGE 5. ComEd 6. Dayton 7. DLCO 8. Dominion 9. DPL 10.JCPL 11.MetEd 12.PECO 13.Penelec 14.PEPCO 15.PPL 16.PSEG 17.Mid-Atlantic Area Council (MAAC) Region 18.ComEd, AEP, Dayton, APS, and Duquesne 19.Eastern MAAC (PSE&G, JCP&L, PECO, AE, DPL & RECO) 20.Southwestern MAAC (PEPCO & BG&E) 21.Western MAAC (Penelec, MetEd, PPL) 22.PSEG northern region (north of Linden substation); and 23.DPL southern region (south of Chesapeake and Delaware Canal) PJM required to make a filing with FERC before adding a new LDA. 19

20 LDAs for Transition Period Transition Delivery Year 2007/2008, 2008/2009, & 2009/2010 Locational Deliverability Areas PJM Mid-Atlantic Region and APS Eastern MAAC (PSE&G, JCP&L, PECO, AE, DPL, and RECO) Southwestern MAAC (PEPCO & BG&E) Rest of Market - ComEd, AEP, Dayton, Dominion and Duquesne 2010/2011 All 23 LDAs 20

21 Zonal Capacity Prices Base Residual Auction Results Preliminary Zonal Capacity Prices Preliminary Zonal ILR Prices Base Zonal Capacity Transfer Right (CTR) Credit Rate Second Incremental Auction Results Adjusted Zonal Capacity Prices Final Zonal ILR Prices Final Zonal CTR Credit Rate ILR Certification Final Zonal Capacity Prices Locational Reliability Charge = Daily Zonal UCAP Obligation * Final Zonal Capacity Price 21

22 Unforced Capacity Obligations Zonal W/N Summer Peak 4 yr Preliminary RTO Peak Load Forecast Forecast Pool Requirement Zonal W/N Summer Peak 4 yr Forecast Pool Requirement Forecast Zonal ILR Obligation Base Residual Auction Base RTO UCAP Obligation Base Zonal RPM Scaling Factors Base Zonal UCAP Obligation Preliminary Zonal Peak Load Forecast Final Zonal Peak Load Forecast Zonal W/N Summer Peak 1 yr Forecast Pool Requirement Second Incremental Auction Zonal Allocation of Incremental Obligation Satisfied in 2 nd IA Final Zonal UCAP Obligation Final Zonal RPM Scaling Factors Delivery Year LSE Allocation of Zonal W/N Summer Peak 1 yr LSE Obligation Peak Load LSE Daily UCAP Obligation 22

23 Summary of RPM Activities Pre-Delivery Year Activity RPM Auctions Base Residual Auction 1 st Incremental Auction 2 nd Incremental Auction 3 rd Incremental Auction Interruptible Load for Reliability Nomination Delivery Year Activity Auction Credits/Charges ILR Credits Daily Unforced Capacity Obligations & Locational Reliability Charges CTR Credits Resource Performance Assessments Deficiency & Penalty Charges/Credits Non-Unit Specific Capacity Transactions Charges/Credits On-going Bilateral Market 23

24 Model-based Assessment of the PJM Reliability Pricing Model Benjamin F. Hobbs, Ming-Che Hu, and Javier Inon Whiting School of Engineering The Johns Hopkins University Murthy Bhavaraju PJM Interconnection, LLC This is a summary of work conducted at JHU sponsored by PJM Interconnection; however, the authors are solely responsible for all opinions expressed, which do not necessarily represent the position of the sponsor.

25 Outline Dynamic Model Analysis of PJM RPM Questions asked Model assumptions & structure Simple model of representative agent Transient simulation with random shocks Results Conclusions

26 Dynamic Analysis: Questions 1. How do different curves affect. Stability of capacity market? Costs to consumers? Ability to meet reserve requirement, reliability criterion? 2. How robust are these conclusions to different assumptions about: Generator behavior? Demand curve parameters?

27 Dynamic Analysis: Basic Assumptions Capacity additions are a dynamic process. Investment depends on: 1. Forecast revenue streams Based on capacity and energy prices from recent auctions More forecast net revenue investment 2. Revenue stream variability Variations due to forecast changes and weather Highly variable energy and capacity prices investment (due to risk aversion) 3. Risk attitudes: No hedges (incomplete market) Risk aversion Short-sightedness Random shocks (weather, economic fluctuations) cause variation in returns Result: boom/bust cycles in investment Use of demand curve changes the market dynamics

28 Dynamic Model Overview 1. Simple & transparent model simulates: annual construction of turbine capacity, revenues from energy, ancillary services, & capacity markets, market stability in face of random demand shocks, consumer costs 2. Allows exploration of assumptions 3. The model assesses profitability of CTs needed to meet the reliability requirement Other generation types and profitability not modeled Representative Agent approach Annual time step

29 Simulation Overview: Auction in Year y-4 for Capacity Installed by Year y: Repeated for 100 years Actual and Estimated Profits: Blue = Known at Auction in Year y-4; Brown = Estimated Year y-7: Profit = P RPM + E/AS Gross Margin Fixed Cost Year y-6: P RPM + E/AS GM FC Year y-5: P RPM + E/AS GM FC Year y-4: P RPM + E/AS GM FC Year y-3: P RPM + E/AS GM FC Year y-2: P RPM + E/AS GM FC Year y-1: P RPM + E/AS GM FC Year y: P RPM + E/AS GM FC Risk-Adjusted Forecast Profit (RAFP y ) ( if profits higher, if profits more variable) Forecast Weights for Profits in y-7,, y Risk averse utility function penalizes variable profits NCA y 1.7% Maximum New Capacity Additions NCA y P RPM,y Capacity Price from Demand Curve 0 (Assume existing capacity bids 0, and NCA y bids B) 0% RAFP y Total CAP

30 Risk Adjusted Forecast Profit (RAFP) Calculation Actual and anticipated combustion turbine profits π π = Gross Margin (Energy, A/S) + P RPM Gross margin based on reserve margins, experience $10,000 + Simulated Scarcity Rent Historical E/AS Net Revenues E/AS Net Revenue $/Installed MW/yr ``` Ratio of (Unforced Reserve Margin) / (Target IRM) RAFP = single profit with same utility as 7 years of experienced/estimated profit

31 Determination of Capacity Price P CAP,y Capacity Demand Curve Capacity Bid Curve New Capacity Chosen B Max New Capacity Existing Capacity Total Cap

32 PJM Analysis: Five Curves Considered Vertical Demand

33 Results: Summary 1. Sloped curve stabilizes capacity payments 2. More stable payments even out investment, forecast reserves 3. More stable revenues lowers capital costs. Consumer costs (capacity, scarcity) fall: $129/peak kw/yr for vertical $71/peak kw/yr for sloped (values depend on assumptions) 4. Results robust Capacity Price ($/MW/yr). Reserve/IRM Ratio. 160, ,000 80,000 40, Time Time VRR (IRM+1%) Vertical at Target IRM VRR (IRM+1%) Vertical at Target IRM

34 Sample Results: Average (Risk aversion parameter = 0.7; Results depend on specific assumptions) Curve % Years meet or Exceed IRM Average % Reserve over IRM Generation Profit $/kw-yr {Return on Equity} Scarcity Rev. $/kw-yr E&A/S Revenue $/kw-yr RPM Payment $/kw-yr Scarcity + RPM Payment by Consumers (Peak Load Basis) 1. Vertical Demand {35%} Original PJM Curve, Based on VOLL {21%} Alternate Curve with New Entry Net Cost at IRM {17%} Alternate Curve with New Entry Net Cost at IRM + 1% {17%} Alternate Curve with New Entry Net Cost at IRM + 4% {17%} Alternate (sloped) curves have lower consumer cost and better adequacy

35 Sensitivity Analyses Demand Curve Shapes: Where right-hand tail drops to zero Max. P: dropped by 25%, 40% Investment Assumptions: Percent CT added when profit is equal to cost (base: 7%) + 2% Degree of risk aversion: risk neutral very risk averse Relative weight placed on earlier year profits in forecast: low high Bidding Assumptions: Existing capacity bids positive Potential capacity bids various amounts B Result: Sloped demand always preferred to vertical

36 5. Conclusions: Advantages of Sloped Demand Logically reflects reality of capacity value: If there are extra reserves, the marginal value of capacity can be close to but not equal to zero If reserves are short, payments should be higher Compared to vertical demand, it lowers risk to generators. Result: Lower required return to capital More investment in generation Dampened capacity cycles Lower consumer cost Elasticity mitigates market power in capacity market