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GT Viability in the NEPOOL Market REVISED TO REFLECT ACTIONS FROM MEETING - SEE LAST THREE SLIDES

GT Viability in the NEPOOL Market REVISED TO REFLECT ACTIONS FROM MEETING - SEE LAST THREE SLIDES. Presented by Andrew P. Hartshorn Prepared for NEPOOL Markets Committee Meeting January 24, 2001. GT VIABILITY Overview.

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GT Viability in the NEPOOL Market REVISED TO REFLECT ACTIONS FROM MEETING - SEE LAST THREE SLIDES

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  1. GT Viability in the NEPOOL MarketREVISED TO REFLECT ACTIONS FROM MEETING - SEE LAST THREE SLIDES Presented by Andrew P. Hartshorn Prepared for NEPOOL Markets Committee Meeting January 24, 2001

  2. GT VIABILITY Overview • The viability of new GT capacity in the NEPOOL market is dependent on three components: • pro forma analysis of the revenue requirement necessary to fund a new GT project • ancillary service revenues • energy revenues • This presentation lays out the methodology and assumptions we have used to determine each of these three components. • We will present a base case analysis with two sensitivities. The sensitivities cases evaluate the impact of project assumptions and the potential impact of using year 2000 energy prices to evaluate the viability of the GT project. LECG

  3. PRO FORMA ANALYSIS Overview • The pro forma analysis used to determine the project’s levelized revenue requirement assumes: • Project life of 20 years • 60% debt financing • 20 year debt amortization • Return on equity of 13.0% • Return on debt of 9% LECG

  4. PRO FORMA ANALYSIS Base Case • For the base case analysis we assumed the following GT project parameters: • 100 MW unit size; • $350/kW installation cost; • 11,000 BTU/kWh heat rate; • Modeled with assumptions shown in the following tables, the levelized revenue requirement is $54.47/kWyr. LECG

  5. PRO FORMA ANALYSIS Project Sensitivity • As a sensitivity case, we assumed the following GT project parameters: • 45 MW unit size; • $320/kW installation cost; • 8,280 BTU/kWh heat rate; • Modeled with assumptions shown in the following tables, the levelized revenue requirement is $50.66/kWyr. LECG

  6. ANCILLARY SERVICE REVENUES Overview • We have assumed that the new GT is a 10-minute capable unit and would thus bid to supply 10-minute non-spinning reserves. • To determine the price of 10-minute reserves going forward, it is necessary to evaluate the both the clearing price of the 10-minute reserve market and the clearing price for replacement reserves as defined by the replacement reserve demand curve. • The price paid to 10-minute reserves will always be the higher of the the 10-minute clearing price and the replacement reserve clearing price. LECG

  7. ANCILLARY SERVICE REVENUES Methodology • We used year 2000 10-minute reserve prices to estimate the likely 10-minute reserve prices going forward. • To determine replacement reserve prices, a snapshot of the real time dispatch was taken in each hour of year 2000 that identified the level of total reserve available and total reserve required by reserve type. The total reserve available was then mapped onto the demand curve for replacement reserves for that hour to determine the replacement reserve price. The definition of the demand curve is described on a later slide. • In each hour, the higher of the year 2000 10-minute reserve price and the replacement reserve price was used to define the final 10-minute reserve price. LECG

  8. 10-Minute Requirement = 1200 MW 30-Minute Requirement = 1700 MW 30-Minute Requirement + 500 = 2200 MW LECG

  9. ANCILLARY SERVICE REVENUES Assumptions • The demand curve used to determine the price of replacement reserves was defined according to the following specifications. • Adjusted for any commitment shift to compensate for historical commitment preferences: • a maximum price of $100 would be reached at the 10-minute reserve requirement; • a price of $50 would be reached at the 30-minute reserve requirement; • a price of $1.35 would be reached at the 30-minute requirement plus 500 MW; • a price of $0.10 would be reached at the 30-minute requirement plus 1200 MW. • Note that the graph on the prior page assumes a 1200 MW 10-minute requirement and a 1700 MW 30-minute requirement and no commitment shift. Individual demand curves were calculated for each real-time dispatch based on the reserve requirements in that real-time dispatch. LECG

  10. ANCILLARY SERVICE REVENUES Assumptions • Two scenarios for shifting the demand curve were analyzed: • The first scenario was a 400 MW shift before September 15th with a 250 MW shift from September 16th. These shifts reflect changing preferences in historical unit commitments relative to current commitment preferences defined by the original demand curve; • In the second scenario the demand curve was not shifted. LECG

  11. ANCILLARY SERVICES REVENUES Results • Ancillary service revenues for 10-minute and 30-minute GTs under each of the demand curve shift scenarios and two outage rates are shown below. • The ancillary service revenues are unaffected by the choice of either the base case or sensitivity case GT project. LECG

  12. ANCILLARY SERVICES REVENUES Results • The table below summarizes the reserve revenue calculations by level of replacement reserves for the shifted demand curve scenario. Most of the value from providing 10-minute reserves comes when less than 1000 MW of replacement reserves was available in real time. LECG

  13. ANCILLARY SERVICES REVENUES Results • The table below summarizes the reserve revenue calculations by month for the shifted demand curve scenario. • We have not adjusted the reserve revenues to reflect any weather or temperature related bias even though the summer of 2000 was mild. LECG

  14. INCREMENTAL ENERGY REVENUES Assumptions • The incremental cost of energy for the GT was derived using the following information: • Natural gas spot prices for Boston City Gate provided by Energy Intel based on their contact with gas marketer and traders; • Heat rate of 11,000 BTU/kWh • Variable O&M of $2.50/MWh • Real-time energy prices were modeled using actual year 2000 real-time energy prices: • Real-time energy prices greater than $1,000 on May 8th were reduced to $1,000 for this analysis. LECG

  15. INCREMENTAL ENERGY REVENUE Methodology • The GT would earn a margin on energy sales if the sum of fuel cost and variable O&M was less than the real-time energy price. However, we have already assumed a revenue stream for the GT in the reserves analysis. The GT would only want to generate energy if the margin on the energy sales was greater than the 10-minute reserve price. • Therefore, the incremental energy revenue (over and above reserve revenue) was determined by subtracting fuel cost, variable O&M and ancillary service revenue from the real-time energy price in every hour. • In every hour where the incremental net revenue is positive, the GT would generate energy instead of providing reserves. LECG

  16. INCREMENTAL ENERGY REVENUE Results • The tables below shows the incremental energy revenues associated with the base case project (11,000 BTU/kWh heat rate). • The left table shows the incremental energy revenue for either a 10-minute or 30-minute GT with a 5% outage rate under each of the demand curve shift scenarios. • The right table shows the incremental energy revenue for either a 10-minute or 30-minute GT with a 10% outage rate under each of the demand curve shift scenarios. LECG

  17. INCREMENTAL ENERGY REVENUE Results • The table below shows the monthly breakdown of incremental energy revenue under the shifted demand curve scenario. • Much of the incremental energy revenue is created in January, May and December. Perhaps more surprising is how little incremental energy revenue is created in June, July and August. LECG

  18. GT VIABILITY Base Case Results • Combining the reserve and energy revenues together, the tables below show the total net revenues in $/kWyr for 10-minute and 30-minute GTs with 5% and 10% outage rates and each of the demand curve shift scenarios. • Based on a levelized revenue requirement of $54.47/kWyr the GT project does not look viable against any of the scenarios. LECG

  19. GT VIABILITY Project Sensitivity • If the installation cost of the GT is reduced from $350/kW to $320/kW and the size of the project is reduced from 100 MW to 45 MW, the levelized revenue requirement is reduced to $50.66/kWyr. • The sensitivity case also assumes the heat rate is reduced from 11,000 BTU/kWh to 8,280 BTU/kWh. • Reducing the heat rate reduces the cost of generating energy which: • increases the margin on hours where generating energy was the most profitable option in the base case; • increases the number of hours where generating energy was preferable to providing reserves. LECG

  20. GT VIABILITY Project Sensitivity • The total net revenues for the project sensitivity case are shown in the tables below. • The 10-minute GT now meets its $50.66/kWyr revenue requirement at a 5% outage rate under either demand curve shift scenario. • It easily meets the revenue requirement at a 10% outage rate under the shifted demand curve scenario and nearly meets its requirement with a 10% outage rate and no demand curve shift. LECG

  21. GT VIABILITY Mild Year Sensitivity • This entire base case analysis is derived from year 2000 reserve and energy prices. The 2000 summer was a very mild. • To analyze the potential impacts of a “normal” summer, we reviewed the average clearing price of forward market contracts for Summer 2000 peak energy transacted before May 1st and compared them to the average peak energy price observed during the Summer months of June, July and August. • The average forward market transaction for on-peak Summer energy traded before May 1st was $94.17/MWh; • The average real-time energy price for on-peak Summer hours was $45.71/MWh; • A second sensitivity case was created off the base case by multiplying each on-peak Summer real-time energy price by 94.17/45.71 or 2.06. LECG

  22. GT VIABILITY Mild Year Sensitivity • When reviewing the results from the mild year sensitivity case it is important to note: • The sensitivity was based of the 11,000 BTU/kWh base case scenario; • A price cap of $1000/MWh was kept in place so actual results in this sensitivity reflect an energy price ratio between the original and final real-time prices of something less than 2.06; • Reserve prices were not changed; • No allowance was made for potential changes in gas prices as a result of increased demand; • The variance effects of the incremental energy calculation may have been skewed by the multiplicative treatment of the real-time prices. The energy margin is very sensitive to the shape of the price duration curve. LECG

  23. GT VIABILITY Mild Year Sensitivity • The total net revenues for the mild year sensitivity are shown in the tables below. • The $54.47/kWyr revenue requirement for the base case project is now met under every 10-minute and 30-minute scenario regardless of outage rate or demand curve shift. LECG

  24. GT VIABILITY Conclusions • During the low load summer of 2000, the demand curve as proposed, in conjunction with incremental energy revenues, would have provided less revenue than the levelized revenue requirement for the base case project; • If forward market prices had materialized, it is likely that the demand curve, in conjunction with incremental energy revenues, would have provided more than sufficient revenues to meet the levelized revenue requirement for the base case project; • A better turbine with lower heat rates and lower capital cost would probably have met its levelized revenue requirement; • The sensitivity studies show that the demand curve provides a reasonable expectation of adequate revenues and incentives to construct new quick start units. LECG

  25. GT VIABILITY Meeting Follow-Up • These additional slide present data for several requests were made during the meeting: • To what extent did the demand curve set the price of 10-minute and 30-minute reserves? • What was the GT’s capacity factor under each scenario? • Can the spreadsheet that performed the analysis be circulated to all the members of the Markets Committee? - This spreadsheet will be available later in the week of Monday 29th. • Further explanation of the demand curve shifts. LECG

  26. GT VIABILITY Demand Curve Sets Reserve Price • The only element of the analysis that affected how often the demand curve set the 10-minute and 30-minute price was whether the demand curve was shifted or not. It did not depend at all on the type of GT modeled or the mild year sensitivity. • The table below shows that the 30-minute reserve price was set by the demand curve much of the time whether the demand curve was shifted or not. The 10-minute reserve price was set by the shifted demand curve 42% of the time and 26% of the time if the demand curve was not shifted. LECG

  27. GT VIABILITY GT Capacity Factors • The GT capacity factors were affected by the demand curve shift, the heat rate of the GT and the mild year sensitivity. • The capacity factor represented below have not been adjusted for outage rates. They are simply the percentage of hours in the year that the unit would have been selected for energy had it been available the whole of the year. • Note that the increase in capacity factor for the mild year sensitivity is very pronounced given that the only hours that changed in this case were the on-peak hours of June through August. LECG

  28. GT VIABILITY Demand Curve Shifts • This slide was added after the presentation in response to questions about the demand curve shift at the meeting. • Slide #8 says: “a price of $1.35 would be reached at the 30-minute requirement plus 500 MW” This demand curve is the one used in the “no shift” scenarios described below. • The “shift” case in the base case refers to using two demand curves rather one. Prior to 9/15/01 the price of $1.35 would be reached at the 30-minute requirement plus 900 MW. After 9/15/01 the price of $1.35 would be reached at the 30-minute requirement plus 750 MW. • Unit commitment practices changed to the day-ahead target of 1350 from 1500 on or around September 15, 2000. The 900 MW assumes a target of 1500 day ahead plus 600 MW outages overnight. The 750 MW assumes a day-ahead target of 1350 plus 600 MW of outages. LECG

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