Load Serving Entities and the Day-Ahead Market

Transcription

1 September 20, 2007 Load Serving Entities and the Day-Ahead Market Sheldon Fulton Director Market Structure

2 Presentation Outline 1. How is load currently represented in the market? 2. What are LSEs? What are the LSE model options? Results from Proof of Concept work? Future Direction - Recommendations? 3. What are the synergies between various market evolution initiatives? Day-Ahead Market LSEs 4. Putting it all together 2

3 Physical Market Who represents the Buyer? DEMAND SUPPLY LSE Large Industrial Commercial & Small Industrial MUSH Residential 20% 37% 8% 80% 35% Renewables CDM Nuclear CCGT/ SCGT OPG Merchant Generation NUGS OPA- Contracted Assets Non- Prescribed Assets Prescribed Assets 15% 20% 22% 43% 3 ***% by MWh

4 Ontario Market Evolution FORWARD CURVE LOAD LSE Marketers Industrial Commercial DR DAY-AHEAD MARKET Reliability Contracts HOEP Uplift FLP RMR SUPPLY Merchant OPA Contacts OPG Assets OPA Supply Mix ENVIRONMENTAL ATTRIBUTE BASIS 4

5 Load Serving Entity Concept Wholesale Market LSE $$ -Assemble usage data from LDCs into forward portfolio -Procure forward contracts based on agreed procurement plan -Mitigate risks between procured energy and actual consumption for agreed risk margin -Provide LSE Rate to LDCs as a charge schedule for default load -Settle price variances between: a) HOEP and LSE Rate, & b) Forward Hedges and Actual Consumption IESO Settlement $$ Retail Market LDC -Provide usage data to LSEs on default customer load -Compensated for admin costs (as add-on to Rate or part of distribution tariff) - Acquire energy from the IESO at HOEP for actual load $$ 5 $$ Suppliers (market) RPP customers Pay agreed LSE Rate for actual consumption to LDCs

6 LSE Process 1. Observations from LSE Working Group -Re Models -Re Objectives -Conclusions 2. Observations from Proof of Concept -Micro & Macro -Conclusions 3. Observations from Other Jurisdictions -Where we looked & what we looked for -Examples of what has not worked and what worked - Some lessons learned - Conclusions Suggested Path Forward 6

7 Potential LSE Models 1. Fixed Price Model with Uniform Prices Generators Wholesale Marketers OPA LDCs Customers 2. Fee for Service Model with Regional Prices Generators Fee for Service Providers Regional Entities Customers 3. Fee for Service Model with LDC Prices Generators Fee for Service Providers LDCs Customers 4. Regulated Entity Model with Provincial Prices Generators Regulated Entity Customers 7

8 Observations from LSE Working Group re Models Based on feedback received from the LSE Working Group and dialogue with interested stakeholders throughout the summer: Model 1 (provincial) good transition model, but not the ultimate end goal Model 2 (regional) considered three variations of a regional model, but there are complications with developing regions Model 3 (LDC specific) LDC involvement is favoured, but could add too much complexity to the market & LDCs may not have the technical capabilities Model 4 (gas model) - decided to park this model in part due to post period adjustments and unfavourable responses 8

9 Observations from the LSE Working Group re Objectives From dialogue and feedback, 10 objectives were identified as being important for a LSE model in Ontario. Of these, the following 6 objectives were determined to be the most critical across all participants: At a minimum, the LSE model should: Be market-based and not distort pricing Support market robustness (liquidity) and long-term sustainability Support market mechanisms to reduce exposure to price volatility Transfer risks to the marketplace Be publicly acceptable Have noticeably better benefits to customers than the current system (status quo) 9

10 Proof of Concept (POC) Observations Micro: 6 pricing scenarios comparative pricing cross subsidization - becomes a bigger issue when MUSH exits RPP in April 2008, coinciding with start of LSE transition TOU implications Macro: Analysis of comparative RPP Rates for the 3 Models LSE rates for Model 1 10

11 Calculating Cost of Shape (CoS) 1. Base portfolio level (MW) = simple average of all off-peak load within hedging period. (Peak portfolio level = simple average of all on-peak load) 2. Hourly Cost of Shape (CoS), (Portfolio Actual Load) * HOEP/Actual Load, is obtained for each hour over the time period under consideration. (Note: +ve = gain, -ve = loss) 11

12 LSE Price Component and Hedge Cost Calculations LSE Price Component = ((Hedge Cost + Cost of Shape) x risk margin) + admin charge Hedge Cost = ((Base vol x Base Hedge price) + (Peak vol x Peak hedge price)) (Base volume + Peak volume) = $61.56 Example: Hedge Cost = ((100 MW x $60) x 8760) + ((25 MW x $75) x 4064) (100 x 8760) + (25*4064) LSE Price Component = (($ $1.60*) X 1.06**) + $0.50*** = $67.45 Cost of Shape = $1.60 Risk Margin = 6% Administration Charge = $0.50/MWh 12

13 Pricing Scenario #1 6 month rate based on procuring 6,12,18, and 24 month blocks for 25% each Timing coincides with RPP rates Transition Blocks Actual Blocks % of load in 25% increments Nov06 May07 Nov07 May08 Nov08 May09 13

14 Scenario 1 LSE Rate Calculation as of Nov 06 LSE Rate Adjustment Total Rate % Relative Weight 6 months $ $7.15 $ % $ months $ $7.15 $ % $ months $ $7.15 $ % $ months $ $7.15 $ % $15.32 Total $

15 Pricing Scenario #2 Blended RPP & procured rates to determine implications of staged phase-in of LSEs: 6 month rate based on procuring 12-month blocks Every 6 months 50% of the load is procured Timing coincides with RPP rates As RPP decreases in relative weight the charge/credit for the variance account increases per MWh LSE LSE LSE % of load in 25% increments RPP RPP LSE LSE LSE LSE RPP LSE Transition Period Nov-06 May-07 Nov-07 May-08 Nov-08 May-09 15

16 (Example of a gain month) (Example of a loss month) 16

17 Load Shape Comparison Power Stream TOU & Enersource Load Shape Comparison and Temperature ( C) June

18 Model #1 Pricing Prescribed Asset Allocations May-Oct 07 LSE Rate Product Cost of Hedges ($/MWh) Shape of Cost ($/MWh) Risk Margin 6% ($/MWh) Admin Margin ($/MWh) Full Load Price ($/MWh) % of LSE Rate Relative Weights ($/MWh) 1 Year $67.27 $1.60 $4.13 $0.50 $ % $ Years $68.36 $1.60 $4.20 $0.50 $ % $ Years $68.69 $1.60 $4.22 $0.50 $ % $ Years $68.84 $1.60 $4.23 $0.50 $ % $ Years $68.90 $1.60 $4.23 $0.50 $ % $15.05 LSE Rate ($/MWh) $74.71 OPG Heritage Asset Credit ($/MWh) ($8.87) Global Adjustment + OPG Rebate ($/MWh) ($3.85) LSE Rate after Heritage Asset Credit ($/MWh) $

19 Recommendations for Implementation (1) Based on the identified 6 critical objectives for a LSE model, a LSE Fee for Service Model in between Model 2 and Model 3 is recommended LDCs would have the choice to select their LSE to serve their load via an RFO Process Smaller LDCs would opt to include load with selected LSE/LDC areas The Regulator (OEB) would ensure the RFO process was fair and competitive LSEs would serve LDC territories/regions, up to a maximum of 25% of the total ON electricity load Supply service contracts/licences would be no more than 7-10 years 19

20 Recommendations for Implementation (2) LSE compliance will be driven by posted LDC rates for transparency (customer pressure and reputation for future contracts/licence) and by OEB oversight of the procurement process A 3-year transition is recommended starting May 1, 2008 to be completed May 1, 2011 LSE portfolios would require staggered, layered and blended contracts (multi-year product), with a minimum percentage acquired publicly A 6-month rate is recommended for the 3-year transition period. Quarterly rates could be considered once TOU meters are fully implemented. 20

21 Physical Market Who represents the Buyer? DEMAND SUPPLY LSE Large Industrial Commercial & Small Industrial MUSH Residential 20% 37% 8% 80% 35% Renewables CDM Nuclear CCGT/ SCGT OPG Merchant Generation NUGS OPA- Contracted Assets Non- Prescribed Assets Prescribed Assets 15% 20% 22% 43% 21 ***% by MWh

22 Market Evolution Synergies Day-Ahead Market Load Serving Entities OPG Regulation and Allocation 22

23 Market Evolution Synergies: LSE/DAM Volume: LSEs provide default buy-side representation in DAM DAM load is dependent on accurate at-risk forecast by LSEs Price: DAM participation may allow for potential avoidance of reliability charges (IOG, SGOL, etc) Heritage Benefit: DAM participation could be required in order to acquire 100% Allocation Day-Ahead Market 23 Risk Transference: LSEs would manage their portfolios in the forward and DA markets, and use the spot market for balancing purposes only Load Serving Entities OPG Regulation and Allocation

24 Objective DAM LSE LSE LSE LSE A A A A Demand-Side Resources in Competition Gx Gx Gx Gx Supply-Side Resources in Competition DEMAND Delivering MWh SUPPLY 24

25 Questions?