Wind Projects and Wholesale Market Risks | Feb 10, 2015
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EnergyGPS Principal Tim Belden gave a seminar on wind projects and wholesale market risk at Infocast in San Diego on February 10, 2015.
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Wind Projects and Wholesale Market Risks | Feb 10, 2015
- 1. Infocast Wind Power and Investment Summit 2/10/2015 Tim Belden tbelden@energygps.com 1
- 2. Course Outline Wind Development Roadmap Characteristics of Wholesale Markets with Wind Curtailment Trends Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 2
- 3. Course Outline Wind Development Roadmap Characteristics of Wholesale Markets with Wind Curtailment Trends Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 3
- 4. 4
- 5. 5
- 6. Growth of Wind in US 6Source: AWEA
- 7. Installed Wind Capacity By State 7 Source: AWEA
- 8. Projects Under Online and Under Construction 2014 8 Source: AWEA
- 9. RPS: wide range of targets 9
- 10. RPS: major market progress 10 • ERCOT: meeting MW goal • California: major IOUs ahead of schedule • Pacific Northwest: largely in compliance • MISO: State by state but most are at or close to their goals.
- 11. Renewable Policies Transmission • Southern California Edison • ERCOT CREZ 11
- 12. CAISO Transmission Build Out 12
- 14. CREZ Project Status - 2012 14
- 15. CREZ Project Status - 2014 15
- 17. RTO Policies • Three Words: – Dispatchable – Setpoint – LMP • All RTO’s transitioning to dispatching renewables. 17
- 18. RTO Policies • ERCOT – setpoint sent to you but only binding when binding constraints exist. • MISO – Short term forecast and binding setpoint in all intervals. • CAISO – Short term forecast and binding setpoint in all intervals. 18
- 19. PPA Pricing 19
- 20. Falling PPA Prices 20 Source: LBNL
- 21. PPA vs Market Prices
- 22. Where are we going? • Slower rate of growth in new capacity with additions concentrated in Texas/Oklahoma – Future RPS needs: 3 to 4 GW new capacity per year, not all wind – More merchant projects as wind energy prices have declined to levels competitive with wholesale in certain markets • Lower gas/power prices? – Healthy reserve margins in most major markets – Forward (2020) gas prices steadily fallen since 2012 22
- 23. If RPS will not drive growth, what will? 23
- 26. Summary • Rapid growth in installed wind capacity between 2008-2012. • Growth has tapered in 2013 and 2014. • Measured growth moving forward. • Downward pressure on PPA prices as RPS obligations are met. • Some large transmission build outs in CA and ERCOT. Less so elsewhere. • Wind generators increasingly treated like other resources in RTO dispatch. • Curtailment issues, especially in ERCOT 26
- 27. Course Outline X Wind Development Roadmap Characteristics of Wholesale Markets with Wind Curtailment Trends Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 27
- 28. Gen Stack by Region: ERCOT 28
- 30. Gen Stack by Region: SPP 30
- 32. Gen Stack by Region: MISO 32
- 33. Gen Stack by Region: California 33
- 34. Reserve Margins: NERC 2014 summer assessment 34
- 35. Reserve Margins: NERC 2014 summer assessment 35
- 36. Future Gas Prices Steadily Falling 36
- 37. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind Curtailment Trends Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 37
- 41. West Texas Negative Pricing at Generation Node 41
- 43. Distribution of MISO Curtailments 43
- 44. Distribution of Constrained MISO Paths 44
- 45. Catastrophic MISO Basis Risk 45
- 47. CAISO Prices Increasingly Driven by Solar “Duck Graph” 47
- 48. CAISO Prices Increasingly Driven by Solar “Duck Graph” Happening Now 48
- 49. CAISO Prices Increasingly Driven by Solar “Duck Graph” Happening Now 49
- 50. Estimated 2030 Projected Overgen Curtailment 50
- 52. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 52
- 53. Characterizing Wind Risks 53 • Curve Shift – Natural Gas Price • Curve Shift – Median Heat Rate • Nodal Basis Price • System Wind Production and Price Correlation • Price Spike Risk
- 54. Curve Shift – Natural Gas 54 • Curve shift indicates a movement in electricity prices – up or down – that is caused by changes in natural gas prices. • The supplier producing the marginal MW sets price. • Natural gas power plants are the marginal generator most of the time. • Overall level of natural gas prices is one of the most important drivers of electricity prices. • All electricity generators are exposed to changes in the price of natural gas.
- 55. Curve Shift – Median Heat Rate 55 • Movement in electricity prices – up or down – caused by the efficiency (as expressed by heat rate) of the price-setting, marginal, natural gas generator. • Increases in demand or changes in the supply stack (e.g., outages, low wind) can impact the median market-clearing heat rate. • If median, market-clearing heat rates move higher then electricity prices will also increase.
- 56. Curve Shift – Median Heat Rate 56
- 57. Nodal Basis Risk 57 • Refers to differences in price at the project node compared to the delivery location for the load (or a hedge). • In certain wind generation pockets, the nodal prices can delink from hub prices due to transmission constraints. • This results in nodal prices reflecting the variable cost of wind production rather than the variable cost of natural gas generation.
- 58. System Wind Price Correlation 58 • Captures the interplay between a project’s production, total system wind production, and RTO prices. • Overall prices may be unchanged (natural gas prices and heat rates relatively constant), but the price of power during certain intervals may change relative to the price of power during other intervals. • For example, prices during intervals of heavy total system wind production may decline relative to prices during intervals with low total system wind production. • As wind makes up a larger portion of the supply stack, this risk may increase.
- 59. Total System Wind Capacity Factor versus ERCOT North Price 59
- 60. System Wind Price Correlation 60
- 61. Price Spike Risk 61 • Some markets experience a small number of extreme price spikes. These can benefit or harm a wind generator depending upon how it is hedged and whether it is producing power at the time of the spike.
- 62. Risk Overview Risk 1. Curve Shift Natural Gas 2. Curve Shift Heat Rate 3. Nodal Basis Risk 4. System Wind Price Corr 5. Price spike risk Cause 1. Weak energy market. 2. More gen in market 3. Bad project location 4. Bad production patterns 5. Bad luck (sort of) 62
- 63. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends X Wind Risks Defined Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 63
- 64. Transaction Structures 64 • As Produced at Node • Fixed Quantity at Hub
- 65. PPA at Project Node 65 Utility Buyer MWh PPA Price MWh Nodal LMP ERCOT Project • Physical sale at node. • LMP based on actual volume for each interval • Buyer bears risk between PPA price and Nodal LMP. • MWh delivered at busbar • Take or pay obligation if curtailment language is tight.
- 66. Fixed Quantity at Hub Transaction 66 Project MWh Node Intermit Mwh hub_ fixed Q Fixed Price Nodal LMP ERCOT Counterparty Hub LMP Mwh hub_ fixed Q
- 67. Fixed Quantity at Hub Transaction 67 Project MWh Node Intermit Mwh hub_ fixed Q Fixed Price Nodal LMP ERCOT Counterparty Hub LMP Mwh hub_ fixed Q
- 68. Fixed Quantity at Hub Transaction 68 Project MWh Node Intermit Mwh hub_ fixed Q Fixed Price Nodal LMP ERCOT Counterparty Hub LMP Mwh hub_ fixed Q
- 69. Fixed Quantity at Hub Transaction 69 Project MWh Node Intermit Mwh hub_ fixed Q Fixed Price Nodal LMP ERCOT Counterparty Hub LMP Mwh hub_ fixed Q
- 70. Break 70
- 71. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends X Wind Risks Defined X Transaction Structures Group Discussion Risk Volume Buckets Risk Metrics Case Study 71
- 72. Group Discussion 72 • What risks is your organization willing to bear? • How do you think about these risks? • How do you manage these risks? • What types of transaction structures work for your organization? • What are the most important factors that your organization considers when evaluating risks and transaction structures?
- 73. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends X Wind Risks Defined X Transaction Structures X Group Discussion Risk Volume Buckets Risk Metrics Case Study 73
- 74. Fixed Quantity at Hub Transaction 74 Project MWh Node Intermit Mwh hub_ fixed Q Fixed Price Nodal LMP ERCOT Counterparty Hub LMP Mwh hub_ fixed Q
- 76. Risk Bucket Definitions 76 Hedge = Actual MWh (H=A). These volumes are represented by the green bars in the figure above. These volumes represent MWh where actual production overlaps with the load. It is the union set of hedge MWh and actual MWh. In each interval, the H=A MWh is the minimum of the hedge quantity or actual. Actual > Hedge MWh (Long). These volumes are represented by the yellow bars in the figure above. These volumes represent MWh of actual production in excess of the hedge. In each interval, the Actual > Load MWh equal the positive difference, if any, between actual production and hedge. During these intervals the portfolio has a “long” position at the node and benefits from higher prices. Actual < Hedge MWh (Short). These volumes are represented by the red bars in the figure above. These volumes occur when actual production is less than the hedge. In each interval, the Actual < Hedge MWh equal the negative difference, if any, between actual production and the hedge. During these intervals the portfolio has a “short” position at the hub and is harmed by higher prices.
- 77. Risk Bucket Diagram 77 Actual Volume Hedge Volume Hedge = Actual MWh Short MWh Long MWh
- 78. Volume Buckets versus Risk 78
- 79. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends X Wind Risks Defined X Transaction Structures X Group Discussion X Risk Volume Buckets Risk Metrics Case Study 79
- 80. Metrics How Much Volume in Each Bucket? 80 Volume Calculations 2011 1 Total Hedge Volume 781,409 2 Total Potential Production 827,248 3 Actual Production 827,248 4 Curtailed 0 5 Total Production 827,248 6 Hedge = Act 630,059 7 Hedge < Act 197,189 8 Hedge > Act 151,350 9 Total Hedge / Total Production 94% 10 Hedge = Act/Total Production 76% 11 Hedge < Act / Total Production 24% 12 Hedge > Act / Total Production 18%
- 81. Metrics Realized Price 81 2011 2012 2013 Avg 1 Hedge Price 31.65 22.14 28.62 27.47 2 Net Revenue per MWh 28.19 21.30 28.62 26.04 3 Hedge - Net Revenue -3.46 -0.84 0.00 -1.43
- 82. Metrics Price Components 82 2011 1 Hedge Price 31.65 2 Net Revenue per MWh 28.19 3 Hedge - Net Revenue -3.46 Contributions to Pricing (act wght) 2011 4 Total -3.46 5 Hedge=Act Basis 1.65 6 Remaining Difference -5.11 7 Hedge < Act -1.94 8 Hedge > Act Gain/Loss -3.17 Price (category wght) 9 Hedge=Act Basis 2.16 10 Load=Prod Price 33.81 11 Hedge < Act Price 23.51 12 Hedge Price 31.65 13 Hedge > Act Price -48.97 14 Hedge > Act Gain/Loss -17.32
- 83. Metrics Basis Deep Dive 83 Basis Breakdown 2011 1 Flat Basis 3.83 2 Prod Basis 1.95 3 Hedge=Act Basis Price 2.16 4 Hedge < Act Basis Price 1.28 5 Hedge > Act Basis Price 4.91
- 84. Metrics Price Spikes and Short Position 84 Risk Metrics 2011 1 # of hrs w/RT Hub > $200 124 2 # of hrs w/RT Hub > $200 & Short 96 3 % of hrs w/RT Hub > $200 & Short 77% 4 # of hrs w/RT Hub > $500 56 5 # of hrs w/RT Hub > $500 & Short 45 6 % of hrs w/RT Hub > $500 & Short 80% 7 % of Hours Long 54% 8 % of Hours Short 46% 9 # of days with loss 23 10 # of days with loss > 1 std dev 18 11 # of days with loss > 2 std dev 18 12 Max Daily Loss -1,480,240
- 85. Metrics Curtailment 85 Curtailment Metrics 2011 2012 2013 Avg 1 Total MWh curtailed 55,777 8,590 0 21,456 2 % of Hours with Curtailment 4% 1% 0% 2% 3 Losses Avoided by Curtailment -322,240 -16,645 0 -112,962 4 Node $/MWh when Curtailed -5.78 -1.94 -5.26 5 Basis $/MWh when Curtailed 2.99 3.78 3.10
- 86. Course Outline X Wind Development Roadmap X Characteristics of Wholesale Markets with Wind X Curtailment Trends X Wind Risks Defined X Transaction Structures X Group Discussion X Risk Volume Buckets X Risk Metrics Case Study 86
- 87. Case Study 87 The Number in the Spreadsheet
- 88. Case Study 88 The Number in the Spreadsheet
- 89. Questions 89 • What volumes should be hedged? What should the 12x24 look like? • What can we expect to earn in $/MWh • What is our basis risk? • What are our other risks? • What are the downsides of hedging? • What drives these risks? • What are the advantages of hedging?
- 90. Framework 90 • What will a hedge do for me? • Even with a hedge, what is the risk that I won’t hit my numbers? • What speed bumps should I expect along the way?
- 91. Sample Project 91 • 200 MW • ERCOT West • 45% Capacity Factor • Located in the panhandle • Used for evaluating the risks and benefits of a stipulated quantity hedge
- 92. Data Required 92 • Back-cast wind production for as far back as nodal prices exist (12/2010 ERCOT). • Lat/Long for project to find appropriate proxy node. • Historic nodal prices. • Historic hub prices. • Historic ERCOT Total System Wind • Hedge quantities and prices
- 93. The Model 93 • Excel-based • Hourly • Parses volumes and risks • 30 MB to 50 MB
- 94. Comparison 12x2 v. 12x24 94 Volume Calculations 12x2 12x24 1 Total Hedge Volume 782,184 782,183 2 Actual Production 785,841 785,841 3 Hedge = Act/Total Potential 78% 78% 4 Hedge < Act / Total Potential 22% 22% 5 Curtailed / Total Potential 0% 0% 6 Hedge > Act / Total Potential 22% 21% 7 Total Hedge / Total Production 100% 100% Production = #5 + #6 + #7
- 95. Comparison Volume Quantities 95 12x2 12x2 12x2 12x2 100% P50 90% P50 80% P50 70% P50 2011-13 2011-13 2011-13 2011-13 Volume Calculations Avg Avg Avg Avg 1 Total Hedge Volume 782,184 703,964 625,744 547,528 2 Total Production 785,841 785,841 785,838 785,842 3 Hedge = Act 609,058 567,128 520,542 469,670 4 Hedge < Act (LONG) 176,782 218,712 265,296 316,172 5 Hedge > Act (SHORT) 173,126 136,836 105,203 77,858 6 Total Hedge / Total Production 100% 90% 80% 70% 7 Hedge = Act/Total Production 78% 72% 66% 60% 8 Hedge < Act / Total Production 22% 28% 34% 40% 9 Hedge > Act / Total Production 22% 17% 13% 10% Notes: #1 = #3 + #4 #2 = #4 + #5
- 96. Curve Shift 96 p50 p50 p50 2011-13 2011-13 2011-13 Avg Avg Avg 1 Hedge Price 27.47 27.47 27.47 2 Flat Hub Price 21.61 31.61 41.61 3 Net Rev per MWh 25.99 26.04 26.09 4 Hedge - Net Revenue 1.48 1.43 1.39
- 97. Curve Shift 97 p50 p50 p50 2011-13 2011-13 2011-13 Avg Avg Avg 1 Hedge Price 27.47 27.47 27.47 2 Flat Hub Price 21.61 31.61 41.61 3 Net Rev per MWh 25.99 26.04 26.09 4 Hedge - Net Revenue 1.48 1.43 1.39 5 H=A Price 29.65 29.65 29.65 6 H=A Basis 2.12 2.12 2.12 7 Long Price 13.21 23.21 33.21 8 Gain/loss Short 0.41 -9.59 -19.59
- 98. Curve Shift: Effect of Different Hedge Quantities 98 12x2 12x2 12x2 12x2 100% P50 90% P50 80% P50 70% P50 +$10 26.09 27.08 28.08 29.07 No shift 26.04 26.04 26.04 26.04 -$10 25.99 25.00 24.00 23.01
- 99. Why Don’t You Hit Number? Tilt Risk 99
- 100. Why Don’t You Hit #? Tilt Risk 100
- 101. More Tilt Risk 101
- 102. Why You Don’t Hit Your #? Basis Unhedged 102 Basis Breakdown 2011 2012 2013 Avg 1 Flat Basis 3.83 2.57 1.54 2.52 2 Prod Basis 1.95 2.83 2.44 2.74 3 Hedge=Act Basis Price 2.16 2.41 1.80 2.12 4 Hedge < Act Basis Price 1.28 4.24 4.91 3.33 5 Hedge > Act Basis Price 4.91 0.57 -0.17 1.57 Note: historically was favorable at selected node. Other nodes in West Hub have much more negative basis.
- 103. Speed Bumps Max Daily Loss Comparing 100% and 70% P50 103 100% P50 70% P50 Risk Metrics Avg Avg 1 # of hrs w/RT Hub > $200 65 65 2 # of hrs w/RT Hub > $200 & Short 51 40 3 % of hrs w/RT Hub > $200 & Short 80% 61% 4 # of hrs w/RT Hub > $500 25 25 5 # of hrs w/RT Hub > $500 & Short 21 17 6 % of hrs w/RT Hub > $500 & Short 93% 74% 7 % of Hours Long 60% 81% 8 % of Hours Short 62% 41% 9 # of days with loss 19 11 10 # of days with loss > 1 std dev 12 12 11 # of days with loss > 2 std dev 12 12 12 Max Daily Loss -639,188 -414,234
- 104. Speed Bumps: can take very large single-day losses 104 12x2 12x2 12x2 12x2 100% P50 90% P50 80% P50 70% P50 Max -1.48 MM -1.31 MM -1.14 MM -0.97 MM 5th percentile -114,439 -99,608 -84,778 -68,072 Max -3.16 MM -2.82 MM -2.48 MM -2.15 MM 5th percentile -258,286 -224,176 -188,647 -154,686 Max -4.83 MM -4.33 MM -3.83 MM -3.32 MM 5th percentile -402,133 -357,597 -291,351 -250,557 $3,000 Cap $6,000 Cap $9,000 Cap
- 105. ERCOT Wind Pricing Summary 105 2011 2012 2013 Avg 1 FlatHub 36.91 23.29 29.69 31.61 2 FlatNode 40.74 25.86 31.23 34.12 3 FlatBasis 3.83 2.57 1.54 2.52 4 Production Hub 26.23 18.47 26.18 25.54 5 Production Node 28.19 21.30 28.62 28.28 6 Production Basis 1.95 2.83 2.44 2.74 7 FlatNode / FlatHub 110% 111% 105% 108% 8 ActHub / FlatHub 71% 79% 88% 81% 9 ActNode / FlatNode 69% 82% 92% 83% 10 ActNode / ActHub 107% 115% 109% 111% 11 ActNode / FlatHub 76% 91% 96% 89%