- - ℹ️️ Click here to view the October 2026 Update preview version (Fervo_Project_Cape-7). -
+⚠️️ This is a deprecated version of the case study. Click here to view an updated version (Fervo_Project_Cape-7).
--- @@ -555,6 +552,8 @@ See [Redrilling Assumptions](#technical-operational-considerations) below for fu The case study also includes a 100 MWe model, `Fervo_Project_Cape-6`, with equivalent capacity to Phase I. Note that like the 500 MWe model, `Fervo_Project_Cape-6` represents a SOAK project and not the real-world Phase I implementation as built by Fervo. +`Fervo_Project_Cape-6` is deprecated in favor of the October 2026 Update's +[100 MWe model](Fervo_Project_Cape-7.html#Fervo_Project_Cape-8-section) (`Fervo_Project_Cape-8`). [Click here](https://gtp.scientificwebservices.com/geophires/?geophires-example-id=Fervo_Project_Cape-6) to view the 100 MWe model in the GEOPHIRES web interface. diff --git a/docs/Fervo_Project_Cape-7.md.jinja b/docs/Fervo_Project_Cape-7.md.jinja index 5cfb87670..c5e0e45d1 100644 --- a/docs/Fervo_Project_Cape-7.md.jinja +++ b/docs/Fervo_Project_Cape-7.md.jinja @@ -16,15 +16,7 @@ } -# \[Preview\] GEOPHIRES Case Study: 500 MW EGS Modeled on Fervo Cape Station (October 2026 Update) - -.. raw:: html - -ℹ️️ This is a preview version of the case study. - Click here to view the February 2026 Update (Fervo_Project_Cape-5). -
- ---- +# GEOPHIRES Case Study: 500 MW EGS Modeled on Fervo Cape Station (October 2026 Update) ## Introduction @@ -504,9 +496,21 @@ rate. ## Variants + + ### 100 MWe Model (Phase I) -The 100 MWe model, with equivalent capacity to Phase I, has not yet been updated for the October 2026 Update. +The case study also includes a 100 MWe model, `Fervo_Project_Cape-8`, with equivalent capacity to Phase I. +Like the 500 MWe model, `Fervo_Project_Cape-8` represents a SOAK project and not the real-world Phase I implementation +as built by Fervo. It is derived from `Fervo_Project_Cape-7` by reducing the number of production wells, shortening +the construction period, scaling interconnection and transmission costs to 100 MWe, and resizing the debt fraction +to meet the same minimum DSCR target. +[Click here](https://gtp.scientificwebservices.com/geophires/?geophires-example-id=Fervo_Project_Cape-8) to view the +100 MWe model in the GEOPHIRES web interface. + +Source code: [Fervo_Project_Cape-8.txt](https://github.com/softwareengineerprogrammer/GEOPHIRES/blob/main/tests/examples/Fervo_Project_Cape-8.txt) +and [Fervo_Project_Cape-8.out](https://github.com/softwareengineerprogrammer/GEOPHIRES/blob/main/tests/examples/Fervo_Project_Cape-8.out). + The February 2026 Update's 100 MWe model, `Fervo_Project_Cape-6`, is documented in the [February 2026 Update of the case study](Fervo_Project_Cape-5.html#Fervo_Project_Cape-6-section). diff --git a/docs/index.rst b/docs/index.rst index 248681270..cebd1e183 100644 --- a/docs/index.rst +++ b/docs/index.rst @@ -24,9 +24,8 @@ Contents :caption: Examples GEOPHIRES-Examples - Fervo_Project_Red - Fervo_Project_Cape-5 Fervo_Project_Cape-7 + Fervo_Project_Red .. reference/index diff --git a/tests/examples/Fervo_Project_Cape-5.txt b/tests/examples/Fervo_Project_Cape-5.txt index c76b92612..a5d81c463 100644 --- a/tests/examples/Fervo_Project_Cape-5.txt +++ b/tests/examples/Fervo_Project_Cape-5.txt @@ -1,4 +1,4 @@ -# Case Study: 500 MWe EGS Project Modeled on Fervo Cape Station Phase II +# [Deprecated] Case Study: 500 MWe EGS Project Modeled on Fervo Cape Station Phase II # See documentation: https://softwareengineerprogrammer.github.io/GEOPHIRES/Fervo_Project_Cape-5.html # *** ECONOMIC/FINANCIAL PARAMETERS *** diff --git a/tests/examples/Fervo_Project_Cape-6.txt b/tests/examples/Fervo_Project_Cape-6.txt index b800271d1..09bb59460 100644 --- a/tests/examples/Fervo_Project_Cape-6.txt +++ b/tests/examples/Fervo_Project_Cape-6.txt @@ -1,4 +1,4 @@ -# Case Study: 100 MWe EGS Project Modeled on Fervo Cape Station Phase I +# [Deprecated] Case Study: 100 MWe EGS Project Modeled on Fervo Cape Station Phase I # See documentation: https://softwareengineerprogrammer.github.io/GEOPHIRES/Fervo_Project_Cape-5.html#Fervo_Project_Cape-6-section # *** ECONOMIC/FINANCIAL PARAMETERS *** diff --git a/tests/examples/Fervo_Project_Cape-8.out b/tests/examples/Fervo_Project_Cape-8.out new file mode 100644 index 000000000..e2da5de78 --- /dev/null +++ b/tests/examples/Fervo_Project_Cape-8.out @@ -0,0 +1,482 @@ + ***************** + ***CASE REPORT*** + ***************** + +Simulation Metadata +---------------------- + GEOPHIRES Version: 3.19.2 + Simulation Date: 2026-10-14 + Simulation Time: 10:37 + Calculation Time: 3.881 sec + + ***SUMMARY OF RESULTS*** + + End-Use Option: Electricity + Average Net Electricity Production: 105.52 MW + Electricity breakeven price: 11.18 cents/kWh + Total CAPEX: 769.02 MUSD + Total CAPEX ($/kW): 7257 USD/kW + Number of production wells: 10 + Number of injection wells: 7 + Flowrate per production well: 107.0 kg/sec + Well depth: 3.1 kilometer + Segment 1 Geothermal gradient: 74 degC/km + Segment 1 Thickness: 2.5 kilometer + Segment 2 Geothermal gradient: 41 degC/km + Segment 2 Thickness: 0.5 kilometer + Segment 3 Geothermal gradient: 39.1 degC/km + + + ***ECONOMIC PARAMETERS*** + + Economic Model = SAM Single Owner PPA + Real Discount Rate: 12.00 % + Nominal Discount Rate: 15.36 % + WACC: 9.33 % + Investment Tax Credit: 230.71 MUSD + Project lifetime: 30 yr + Capacity factor: 91.3 % + Project NPV: 54.29 MUSD + After-tax IRR: 20.48 % + Project VIR=PI=PIR: 1.21 + Project MOIC: 4.52 + Project Payback Period: 4.59 yr + Estimated Jobs Created: 269 + + ***ENGINEERING PARAMETERS*** + + Number of Production Wells: 10 + Number of Injection Wells: 7 + Well depth: 3.1 kilometer + Water loss rate: 1.0 % + Pump efficiency: 80.0 % + Injection temperature: 56.6 degC + Production Wellbore heat transmission calculated with Ramey's model + Average production well temperature drop: 1.0 degC + Flowrate per production well: 107.0 kg/sec + Injection well casing ID: 7.825 in + Production well casing ID: 7.825 in + Number of times redrilling: 2 + Power plant type: Supercritical ORC + + + ***RESOURCE CHARACTERISTICS*** + + Maximum reservoir temperature: 500.0 degC + Number of segments: 3 + Segment 1 Geothermal gradient: 74 degC/km + Segment 1 Thickness: 2.5 kilometer + Segment 2 Geothermal gradient: 41 degC/km + Segment 2 Thickness: 0.5 kilometer + Segment 3 Geothermal gradient: 39.1 degC/km + Project location: 38.506196, -112.918155 + + + ***RESERVOIR PARAMETERS*** + + Reservoir Model = Multiple Parallel Fractures Model (Gringarten) + Bottom-hole temperature: 220.85 degC + Fracture model = Rectangular + Well separation: fracture height: 100.00 meter + Fracture width: 305.00 meter + Fracture area: 30500.00 m**2 + Reservoir volume calculated with fracture separation and number of fractures as input + Number of fractures: 3825 + Fracture separation: 9.83 meter + Reservoir volume: 1145967716 m**3 + Reservoir hydrostatic pressure: 28782.99 kPa + Plant outlet pressure: 13789.51 kPa + Production wellhead pressure: 2702.05 kPa + Productivity Index: 0.98 kg/sec/bar + Injectivity Index: 1.20 kg/sec/bar + Reservoir density: 2800.00 kg/m**3 + Reservoir thermal conductivity: 3.05 W/m/K + Reservoir heat capacity: 790.00 J/kg/K + + + ***RESERVOIR SIMULATION RESULTS*** + + Maximum Production Temperature: 218.4 degC + Average Production Temperature: 218.1 degC + Minimum Production Temperature: 216.3 degC + Initial Production Temperature: 216.7 degC + Average Reservoir Heat Extraction: 723.32 MW + Production Wellbore Heat Transmission Model = Ramey Model + Average Production Well Temperature Drop: 1.0 degC + Average Injection Well Pump Pressure Drop: 1159.3 kPa + Average Production Well Pump Pressure Drop: 12497.6 kPa + + + ***CAPITAL COSTS (M$)*** + + Exploration costs: 56.00 MUSD + Drilling and completion costs: 144.09 MUSD + Drilling and completion costs per vertical production well: 4.40 MUSD + Drilling and completion costs per vertical injection well: 4.40 MUSD + Drilling and completion costs per non-vertical section: 4.08 MUSD + Stimulation costs: 123.27 MUSD + Stimulation costs per well: 7.25 MUSD + Surface power plant costs: 310.61 MUSD + Field gathering system costs: 9.99 MUSD + Total surface equipment costs: 320.60 MUSD + One-time Flat License Fees Etc: 50.00 MUSD + Overnight Capital Cost: 693.96 MUSD + Inflation costs during construction: 49.49 MUSD + Interest during construction: 25.57 MUSD + Total CAPEX: 769.02 MUSD + + + ***OPERATING AND MAINTENANCE COSTS (M$/yr)*** + + Wellfield maintenance costs: 2.24 MUSD/yr + Power plant maintenance costs: 6.76 MUSD/yr + Water costs: 0.57 MUSD/yr + Redrilling costs: 15.56 MUSD/yr + Annual License Fees Etc: 5.40 MUSD + Average Annual Royalty Cost: 3.36 MUSD/yr + Total operating and maintenance costs: 33.89 MUSD/yr + + + ***SURFACE EQUIPMENT SIMULATION RESULTS*** + + Initial geofluid availability: 0.22 MW/(kg/s) + Maximum Total Electricity Generation: 126.92 MW + Average Total Electricity Generation: 126.48 MW + Minimum Total Electricity Generation: 124.09 MW + Initial Total Electricity Generation: 124.61 MW + Maximum Net Electricity Generation: 105.98 MW + Average Net Electricity Generation: 105.52 MW + Minimum Net Electricity Generation: 103.07 MW + Initial Net Electricity Generation: 103.63 MW + Average Annual Total Electricity Generation: 1011.59 GWh + Average Annual Net Electricity Generation: 843.93 GWh + Initial pumping power/net installed power: 20.24 % + Average Pumping Power: 20.96 MW + Heat to Power Conversion Efficiency: 14.59 % + + ************************************************************ + * HEATING, COOLING AND/OR ELECTRICITY PRODUCTION PROFILE * + ************************************************************ + YEAR THERMAL GEOFLUID PUMP NET FIRST LAW + DRAWDOWN TEMPERATURE POWER POWER EFFICIENCY + (degC) (MW) (MW) (%) + 1 1.0000 216.67 20.9801 103.6333 14.4536 + 2 1.0053 217.82 20.9731 105.1647 14.5625 + 3 1.0063 218.04 20.9718 105.4522 14.5827 + 4 1.0068 218.15 20.9711 105.6021 14.5933 + 5 1.0072 218.23 20.9707 105.7014 14.6003 + 6 1.0074 218.28 20.9704 105.7747 14.6054 + 7 1.0076 218.33 20.9701 105.8324 14.6095 + 8 1.0078 218.36 20.9699 105.8793 14.6128 + 9 1.0079 218.39 20.9697 105.9202 14.6156 + 10 1.0080 218.41 20.9696 105.9487 14.6176 + 11 1.0080 218.41 20.9701 105.9480 14.6176 + 12 1.0074 218.28 20.9737 105.7699 14.6049 + 13 1.0041 217.56 20.9916 104.8011 14.5356 + 14 1.0028 217.27 20.9686 104.4411 14.5117 + 15 1.0057 217.90 20.9677 105.2669 14.5700 + 16 1.0065 218.07 20.9661 105.5025 14.5867 + 17 1.0069 218.17 20.9637 105.6377 14.5963 + 18 1.0072 218.24 20.9605 105.7317 14.6031 + 19 1.0075 218.29 20.9571 105.8035 14.6083 + 20 1.0077 218.34 20.9539 105.8611 14.6126 + 21 1.0078 218.37 20.9514 105.9084 14.6161 + 22 1.0080 218.40 20.9495 105.9493 14.6190 + 23 1.0080 218.42 20.9485 105.9736 14.6208 + 24 1.0080 218.40 20.9487 105.9553 14.6195 + 25 1.0070 218.19 20.9543 105.6622 14.5986 + 26 1.0024 217.19 20.9793 104.3155 14.5021 + 27 1.0042 217.57 20.9472 104.8569 14.5426 + 28 1.0059 217.95 20.9472 105.3632 14.5782 + 29 1.0066 218.10 20.9472 105.5605 14.5920 + 30 1.0070 218.19 20.9472 105.6797 14.6004 + + + ******************************************************************* + * ANNUAL HEATING, COOLING AND/OR ELECTRICITY PRODUCTION PROFILE * + ******************************************************************* + YEAR ELECTRICITY HEAT RESERVOIR PERCENTAGE OF + PROVIDED EXTRACTED HEAT CONTENT TOTAL HEAT MINED + (GWh/year) (GWh/year) (10^15 J) (%) + 1 837.1 5762.2 395.60 4.98 + 2 842.4 5780.2 374.79 9.98 + 3 844.0 5785.7 353.96 14.98 + 4 845.0 5789.0 333.12 19.99 + 5 845.7 5791.2 312.27 25.00 + 6 846.2 5793.0 291.42 30.01 + 7 846.6 5794.4 270.56 35.02 + 8 847.0 5795.6 249.70 40.03 + 9 847.3 5796.5 228.83 45.04 + 10 847.4 5797.0 207.96 50.05 + 11 846.9 5795.3 187.10 55.06 + 12 842.9 5782.2 166.28 60.06 + 13 831.5 5743.8 145.60 65.03 + 14 839.6 5770.7 124.83 70.02 + 15 843.0 5781.9 104.01 75.02 + 16 844.4 5786.6 83.18 80.02 + 17 845.3 5789.6 62.34 85.03 + 18 845.9 5791.7 41.49 90.04 + 19 846.4 5793.4 20.63 95.04 + 20 846.9 5794.7 -0.23 100.05 + 21 847.2 5795.8 -21.09 105.07 + 22 847.5 5796.7 -41.96 110.08 + 23 847.5 5796.9 -62.83 115.09 + 24 846.6 5793.8 -83.69 120.10 + 25 840.8 5774.5 -104.48 125.09 + 26 831.8 5744.3 -125.16 130.06 + 27 841.1 5775.1 -145.95 135.05 + 28 843.6 5783.4 -166.77 140.06 + 29 844.8 5787.5 -187.60 145.06 + 30 845.5 5790.1 -208.45 150.07 + + *************************** + * SAM CASH FLOW PROFILE * + *************************** +--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- + Year -2 Year -1 Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Year 11 Year 12 Year 13 Year 14 Year 15 Year 16 Year 17 Year 18 Year 19 Year 20 Year 21 Year 22 Year 23 Year 24 Year 25 Year 26 Year 27 Year 28 Year 29 Year 30 +CONSTRUCTION +Capital expenditure schedule [construction] (%) 7.50 52.50 40.0 +Overnight capital expenditure [construction] ($) -52,047,093 -364,329,648 -277,584,494 +plus: +Inflation cost [construction] ($) -1,561,413 -22,187,676 -25,739,577 +plus: +Royalty supplemental payments [construction] ($) 0 0 0 +equals: +Nominal capital expenditure [construction] ($) -53,608,505 -386,517,324 -303,324,071 + +Issuance of equity [construction] ($) 53,608,505 143,011,410 112,229,906 +Issuance of debt [construction] ($) 0 243,505,914 191,094,165 +Debt balance [construction] ($) 0 243,505,914 460,168,200 +Debt interest payment [construction] ($) 0 0 25,568,121 + +Installed cost [construction] ($) -53,608,505 -386,517,324 -328,892,192 +After-tax net cash flow [construction] ($) -53,608,505 -143,011,410 -112,229,906 + +ENERGY +Electricity to grid (kWh) 0.0 837,073,402 842,417,040 844,055,642 845,026,469 845,706,938 846,226,078 846,642,371 846,990,878 847,278,347 847,409,160 846,906,038 842,944,097 831,472,231 839,660,699 842,977,128 844,388,923 845,286,302 845,941,966 846,455,941 846,872,912 847,226,068 847,495,746 847,562,879 846,615,321 840,816,982 831,853,596 841,112,691 843,565,108 844,782,469 845,553,544 +Electricity from grid (kWh) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 +Electricity to grid net (kWh) 0.0 837,073,402 842,417,040 844,055,642 845,026,469 845,706,938 846,226,078 846,642,371 846,990,878 847,278,347 847,409,160 846,906,038 842,944,097 831,472,231 839,660,699 842,977,128 844,388,923 845,286,302 845,941,966 846,455,941 846,872,912 847,226,068 847,495,746 847,562,879 846,615,321 840,816,982 831,853,596 841,112,691 843,565,108 844,782,469 845,553,544 + +REVENUE +PPA price (cents/kWh) 0.0 11.50 11.68 11.87 12.05 12.23 12.42 12.60 12.78 12.96 13.15 13.33 13.51 13.70 13.88 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 14.06 +PPA revenue ($) 0 96,263,441 98,419,583 100,155,642 101,817,239 103,446,873 105,058,968 106,660,006 108,253,904 109,841,165 111,408,882 112,892,575 113,907,036 113,878,437 116,536,508 118,522,584 118,721,083 118,847,254 118,939,440 119,011,705 119,070,331 119,119,985 119,157,902 119,167,341 119,034,114 118,218,868 116,958,616 118,260,444 118,605,254 118,776,415 118,884,828 +Curtailment payment revenue ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Capacity payment revenue ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Salvage value ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 384,509,011 +Total revenue ($) 0 96,263,441 98,419,583 100,155,642 101,817,239 103,446,873 105,058,968 106,660,006 108,253,904 109,841,165 111,408,882 112,892,575 113,907,036 113,878,437 116,536,508 118,522,584 118,721,083 118,847,254 118,939,440 119,011,705 119,070,331 119,119,985 119,157,902 119,167,341 119,034,114 118,218,868 116,958,616 118,260,444 118,605,254 118,776,415 503,393,839 + +Property tax net assessed value ($) 0 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 769,018,021 + +OPERATING EXPENSES +O&M fixed expense ($) 0 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 30,536,019 +Royalty rate (%) 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 1.75 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 3.50 +O&M production-based expense ($) 0 1,684,610 1,722,343 1,752,724 1,781,802 1,810,320 1,838,532 1,866,550 1,894,443 1,922,220 1,949,655 3,951,240 3,986,746 3,985,745 4,078,778 4,148,290 4,155,238 4,159,654 4,162,880 4,165,410 4,167,462 4,169,199 4,170,527 4,170,857 4,166,194 4,137,660 4,093,552 4,139,116 4,151,184 4,157,175 4,160,969 +O&M capacity-based expense ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Fuel expense ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Electricity purchase ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Property tax expense ($) 0 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 1,691,840 +Insurance expense ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Total operating expenses ($) 0 33,912,469 33,950,202 33,980,583 34,009,661 34,038,179 34,066,391 34,094,409 34,122,302 34,150,079 34,177,514 36,179,099 36,214,605 36,213,604 36,306,637 36,376,149 36,383,097 36,387,513 36,390,739 36,393,269 36,395,320 36,397,058 36,398,385 36,398,716 36,394,053 36,365,519 36,321,410 36,366,974 36,379,043 36,385,033 36,388,828 + +EBITDA ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 + +OPERATING ACTIVITIES +EBITDA ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +Interest earned on reserves ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +plus PBI if not available for debt service: +Federal PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Utility PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Other PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Debt interest payment ($) 0 32,211,774 31,264,342 30,250,590 29,165,875 28,005,230 26,763,339 25,434,517 24,012,677 22,491,308 20,863,443 19,121,628 17,257,886 15,263,681 13,129,883 10,846,718 8,403,732 5,789,737 2,992,763 0 0 0 0 0 0 0 0 0 0 0 0 +Cash flow from operating activities ($) 0 30,139,198 33,205,039 35,924,470 38,641,704 41,403,464 44,229,237 47,131,080 50,118,925 53,199,778 56,367,925 57,591,848 60,434,545 62,401,151 67,099,989 71,299,716 73,934,253 76,670,004 79,555,938 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 + +INVESTING ACTIVITIES +Total installed cost ($) -769,018,021 +Debt closing costs ($) 0 +Debt up-front fee ($) 0 +minus: +Total IBI income ($) 0 +Total CBI income ($) 0 +equals: +Purchase of property ($) -769,018,021 +plus: +Reserve (increase)/decrease debt service ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve (increase)/decrease working capital ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve (increase)/decrease receivables ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve (increase)/decrease major equipment 1 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve (increase)/decrease major equipment 2 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve (increase)/decrease major equipment 3 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve capital spending major equipment 1 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve capital spending major equipment 2 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserve capital spending major equipment 3 ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +equals: +Cash flow from investing activities ($) -769,018,021 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +FINANCING ACTIVITIES +Issuance of equity ($) 308,849,822 +Size of debt ($) 460,168,200 +minus: +Debt principal payment ($) 0 13,534,744 14,482,176 15,495,928 16,580,643 17,741,288 18,983,179 20,312,001 21,733,841 23,255,210 24,883,075 26,624,890 28,488,632 30,482,837 32,616,635 34,899,800 37,342,785 39,956,780 42,753,755 0 0 0 0 0 0 0 0 0 0 0 0 +equals: +Cash flow from financing activities ($) 769,018,021 -13,534,744 -14,482,176 -15,495,928 -16,580,643 -17,741,288 -18,983,179 -20,312,001 -21,733,841 -23,255,210 -24,883,075 -26,624,890 -28,488,632 -30,482,837 -32,616,635 -34,899,800 -37,342,785 -39,956,780 -42,753,755 0 0 0 0 0 0 0 0 0 0 0 0 + +PROJECT RETURNS +Pre-tax Cash Flow: +Cash flow from operating activities ($) 0 30,139,198 33,205,039 35,924,470 38,641,704 41,403,464 44,229,237 47,131,080 50,118,925 53,199,778 56,367,925 57,591,848 60,434,545 62,401,151 67,099,989 71,299,716 73,934,253 76,670,004 79,555,938 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +Cash flow from investing activities ($) -769,018,021 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Cash flow from financing activities ($) 769,018,021 -13,534,744 -14,482,176 -15,495,928 -16,580,643 -17,741,288 -18,983,179 -20,312,001 -21,733,841 -23,255,210 -24,883,075 -26,624,890 -28,488,632 -30,482,837 -32,616,635 -34,899,800 -37,342,785 -39,956,780 -42,753,755 0 0 0 0 0 0 0 0 0 0 0 0 +Total pre-tax cash flow ($) 0 16,604,454 18,722,863 20,428,542 22,061,061 23,662,176 25,246,059 26,819,079 28,385,084 29,944,568 31,484,850 30,966,958 31,945,913 31,918,315 34,483,354 36,399,917 36,591,468 36,713,223 36,802,183 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 + +Pre-tax Returns: +Issuance of equity ($) 308,849,822 +Total pre-tax cash flow ($) 0 16,604,454 18,722,863 20,428,542 22,061,061 23,662,176 25,246,059 26,819,079 28,385,084 29,944,568 31,484,850 30,966,958 31,945,913 31,918,315 34,483,354 36,399,917 36,591,468 36,713,223 36,802,183 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +Total pre-tax returns ($) -308,849,822 16,604,454 18,722,863 20,428,542 22,061,061 23,662,176 25,246,059 26,819,079 28,385,084 29,944,568 31,484,850 30,966,958 31,945,913 31,918,315 34,483,354 36,399,917 36,591,468 36,713,223 36,802,183 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 + +After-tax Returns: +Total pre-tax returns ($) -308,849,822 16,604,454 18,722,863 20,428,542 22,061,061 23,662,176 25,246,059 26,819,079 28,385,084 29,944,568 31,484,850 30,966,958 31,945,913 31,918,315 34,483,354 36,399,917 36,591,468 36,713,223 36,802,183 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +Federal ITC total income ($) 0 230,705,406 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Federal PTC income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Federal tax benefit (liability) ($) 0 20,163,537 35,271,878 17,955,717 7,348,422 6,794,841 -1,318,550 -9,447,189 -10,046,088 -10,663,629 -11,298,669 -11,543,998 -12,113,802 -12,507,999 -13,449,857 -14,291,672 -14,819,751 -15,368,119 -15,946,590 -16,560,453 -16,571,793 -16,581,397 -16,588,731 -16,590,557 -16,564,787 -16,407,094 -16,163,325 -16,415,137 -16,481,833 -16,514,941 -93,608,819 +State ITC total income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State PTC income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State tax benefit (liability) ($) 0 4,577,021 8,006,538 4,075,857 1,668,055 1,542,395 -299,304 -2,144,464 -2,280,411 -2,420,590 -2,564,741 -2,620,429 -2,749,772 -2,839,252 -3,053,049 -3,244,137 -3,364,009 -3,488,485 -3,619,795 -3,759,139 -3,761,713 -3,763,893 -3,765,558 -3,765,972 -3,760,123 -3,724,327 -3,668,993 -3,726,153 -3,741,293 -3,748,808 -21,248,728 +Total after-tax returns ($) -308,849,822 272,050,419 62,001,279 42,460,116 31,077,537 31,999,411 23,628,204 15,227,425 16,058,585 16,860,348 17,621,441 16,802,531 17,082,339 16,571,063 17,980,447 18,864,108 18,407,708 17,856,619 17,235,798 62,298,845 62,341,505 62,377,637 62,405,227 62,412,096 62,315,151 61,721,927 60,804,888 61,752,180 62,003,086 62,127,633 352,147,464 + +After-tax net cash flow ($) -53,608,505 -143,011,410 -112,229,906 272,050,419 62,001,279 42,460,116 31,077,537 31,999,411 23,628,204 15,227,425 16,058,585 16,860,348 17,621,441 16,802,531 17,082,339 16,571,063 17,980,447 18,864,108 18,407,708 17,856,619 17,235,798 62,298,845 62,341,505 62,377,637 62,405,227 62,412,096 62,315,151 61,721,927 60,804,888 61,752,180 62,003,086 62,127,633 352,147,464 +After-tax cumulative IRR (%) NaN NaN NaN -6.83 3.99 9.41 12.37 14.66 15.96 16.61 17.17 17.64 18.03 18.33 18.58 18.78 18.95 19.09 19.21 19.30 19.38 19.59 19.76 19.89 20.00 20.09 20.16 20.22 20.26 20.30 20.33 20.36 20.48 +After-tax cumulative NPV ($) -53,608,505 -177,578,174 -261,911,282 -84,703,146 -49,694,149 -28,911,307 -15,725,245 -3,955,820 3,577,540 7,786,058 11,633,347 15,134,885 18,307,216 20,929,359 23,240,221 25,183,439 27,011,188 28,673,441 30,079,506 31,261,865 32,251,161 35,350,862 38,039,683 40,371,843 42,394,373 44,147,799 45,665,399 46,968,409 48,081,144 49,060,747 49,913,367 50,653,948 54,292,735 + +AFTER-TAX LCOE AND PPA PRICE +Annual costs ($) -53,608,505 -143,011,410 -112,229,906 175,786,978 -36,418,304 -57,695,527 -70,739,702 -71,447,461 -81,430,763 -91,432,580 -92,195,319 -92,980,817 -93,787,442 -96,090,044 -96,824,697 -97,307,373 -98,556,061 -99,658,476 -100,313,375 -100,990,635 -101,703,642 -56,712,860 -56,728,826 -56,742,349 -56,752,675 -56,755,245 -56,718,963 -56,496,941 -56,153,728 -56,508,264 -56,602,168 -56,648,782 233,262,635 +PPA revenue ($) 0 0 0 96,263,441 98,419,583 100,155,642 101,817,239 103,446,873 105,058,968 106,660,006 108,253,904 109,841,165 111,408,882 112,892,575 113,907,036 113,878,437 116,536,508 118,522,584 118,721,083 118,847,254 118,939,440 119,011,705 119,070,331 119,119,985 119,157,902 119,167,341 119,034,114 118,218,868 116,958,616 118,260,444 118,605,254 118,776,415 118,884,828 +Electricity to grid (kWh) 0 0 0 837,073,402 842,417,040 844,055,642 845,026,469 845,706,938 846,226,078 846,642,371 846,990,878 847,278,347 847,409,160 846,906,038 842,944,097 831,472,231 839,660,699 842,977,128 844,388,923 845,286,302 845,941,966 846,455,941 846,872,912 847,226,068 847,495,746 847,562,879 846,615,321 840,816,982 831,853,596 841,112,691 843,565,108 844,782,469 845,553,544 + +Present value of annual costs ($) 454,875,378 + +Present value of annual energy costs ($) 454,875,378 +Present value of annual energy nominal (kWh) 4,070,182,856 +LCOE Levelized cost of energy nominal (cents/kWh) 11.18 + +Present value of PPA revenue ($) 509,168,114 +Present value of annual energy nominal (kWh) 4,070,182,856 +LPPA Levelized PPA price nominal (cents/kWh) 12.51 + +PROJECT STATE INCOME TAXES +EBITDA ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +State taxable PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Interest earned on reserves ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State taxable IBI income ($) 0 +State taxable CBI income ($) 0 +minus: +Debt interest payment ($) 0 32,211,774 31,264,342 30,250,590 29,165,875 28,005,230 26,763,339 25,434,517 24,012,677 22,491,308 20,863,443 19,121,628 17,257,886 15,263,681 13,129,883 10,846,718 8,403,732 5,789,737 2,992,763 0 0 0 0 0 0 0 0 0 0 0 0 +Total state tax depreciation ($) 0 130,733,064 209,172,902 125,503,741 75,302,245 75,302,245 37,651,122 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +equals: +State taxable income ($) 0 -100,593,865 -175,967,863 -89,579,271 -36,660,541 -33,898,781 6,578,115 47,131,080 50,118,925 53,199,778 56,367,925 57,591,848 60,434,545 62,401,151 67,099,989 71,299,716 73,934,253 76,670,004 79,555,938 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 + +State income tax rate (frac) 0.0 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 +State tax benefit (liability) ($) 0 4,577,021 8,006,538 4,075,857 1,668,055 1,542,395 -299,304 -2,144,464 -2,280,411 -2,420,590 -2,564,741 -2,620,429 -2,749,772 -2,839,252 -3,053,049 -3,244,137 -3,364,009 -3,488,485 -3,619,795 -3,759,139 -3,761,713 -3,763,893 -3,765,558 -3,765,972 -3,760,123 -3,724,327 -3,668,993 -3,726,153 -3,741,293 -3,748,808 -21,248,728 + +PROJECT FEDERAL INCOME TAXES +EBITDA ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +Interest earned on reserves ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State tax benefit (liability) ($) 0 4,577,021 8,006,538 4,075,857 1,668,055 1,542,395 -299,304 -2,144,464 -2,280,411 -2,420,590 -2,564,741 -2,620,429 -2,749,772 -2,839,252 -3,053,049 -3,244,137 -3,364,009 -3,488,485 -3,619,795 -3,759,139 -3,761,713 -3,763,893 -3,765,558 -3,765,972 -3,760,123 -3,724,327 -3,668,993 -3,726,153 -3,741,293 -3,748,808 -21,248,728 +State ITC total income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State PTC income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Federal taxable IBI income ($) 0 +Federal taxable CBI income ($) 0 +Federal taxable PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +minus: +Debt interest payment ($) 0 32,211,774 31,264,342 30,250,590 29,165,875 28,005,230 26,763,339 25,434,517 24,012,677 22,491,308 20,863,443 19,121,628 17,257,886 15,263,681 13,129,883 10,846,718 8,403,732 5,789,737 2,992,763 0 0 0 0 0 0 0 0 0 0 0 0 +Total federal tax depreciation ($) 0 130,733,064 209,172,902 125,503,741 75,302,245 75,302,245 37,651,122 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +equals: +Federal taxable income ($) 0 -96,016,845 -167,961,325 -85,503,414 -34,992,486 -32,356,386 6,278,811 44,986,616 47,838,514 50,779,188 53,803,184 54,971,419 57,684,773 59,561,899 64,046,939 68,055,579 70,570,245 73,181,519 75,936,143 78,859,298 78,913,298 78,959,034 78,993,958 79,002,653 78,879,938 78,129,021 76,968,212 78,167,317 78,484,919 78,642,574 445,756,283 + +Federal income tax rate (frac) 0.0 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21 +Federal tax benefit (liability) ($) 0 20,163,537 35,271,878 17,955,717 7,348,422 6,794,841 -1,318,550 -9,447,189 -10,046,088 -10,663,629 -11,298,669 -11,543,998 -12,113,802 -12,507,999 -13,449,857 -14,291,672 -14,819,751 -15,368,119 -15,946,590 -16,560,453 -16,571,793 -16,581,397 -16,588,731 -16,590,557 -16,564,787 -16,407,094 -16,163,325 -16,415,137 -16,481,833 -16,514,941 -93,608,819 + +CASH INCENTIVES +Federal IBI income ($) 0 +State IBI income ($) 0 +Utility IBI income ($) 0 +Other IBI income ($) 0 +Total IBI income ($) 0 + +Federal CBI income ($) 0 +State CBI income ($) 0 +Utility CBI income ($) 0 +Other CBI income ($) 0 +Total CBI income ($) 0 + +Federal PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Utility PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Other PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Total PBI income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +TAX CREDITS +Federal PTC income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State PTC income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Federal ITC amount income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Federal ITC percent income ($) 0 230,705,406 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Federal ITC total income ($) 0 230,705,406 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +State ITC amount income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State ITC percent income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +State ITC total income ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +DEBT REPAYMENT +Debt balance ($) 460,168,200 446,633,456 432,151,280 416,655,352 400,074,708 382,333,420 363,350,241 343,038,240 321,304,399 298,049,189 273,166,114 246,541,224 218,052,592 187,569,756 154,953,121 120,053,321 82,710,536 42,753,755 0 0 0 0 0 0 0 0 0 0 0 0 0 +Debt interest payment ($) 0 32,211,774 31,264,342 30,250,590 29,165,875 28,005,230 26,763,339 25,434,517 24,012,677 22,491,308 20,863,443 19,121,628 17,257,886 15,263,681 13,129,883 10,846,718 8,403,732 5,789,737 2,992,763 0 0 0 0 0 0 0 0 0 0 0 0 +Debt principal payment ($) 0 13,534,744 14,482,176 15,495,928 16,580,643 17,741,288 18,983,179 20,312,001 21,733,841 23,255,210 24,883,075 26,624,890 28,488,632 30,482,837 32,616,635 34,899,800 37,342,785 39,956,780 42,753,755 0 0 0 0 0 0 0 0 0 0 0 0 +Debt total payment ($) 0 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 0 0 0 0 0 0 0 0 0 0 0 0 + +DSCR (DEBT FRACTION) +EBITDA ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 82,618,437 82,675,011 82,722,927 82,759,516 82,768,625 82,640,061 81,853,348 80,637,205 81,893,470 82,226,211 82,391,382 467,005,011 +minus: +Reserves major equipment 1 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 2 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 3 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves receivables funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +equals: +Cash available for debt service (CAFDS) ($) 0 62,350,972 64,469,381 66,175,060 67,807,579 69,408,693 70,992,577 72,565,597 74,131,602 75,691,086 77,231,368 76,713,476 77,692,431 77,664,833 80,229,872 82,146,435 82,337,986 82,459,741 82,548,701 0 0 0 0 0 0 0 0 0 0 0 0 +Debt total payment ($) 0 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 45,746,518 0 0 0 0 0 0 0 0 0 0 0 0 +DSCR (pre-tax) 0.0 1.36 1.41 1.45 1.48 1.52 1.55 1.59 1.62 1.65 1.69 1.68 1.70 1.70 1.75 1.80 1.80 1.80 1.80 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 + +RESERVES +Reserves working capital funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves working capital disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves working capital balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves debt service funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves debt service disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves debt service balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves receivables funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves receivables disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves receivables balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves major equipment 1 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 1 disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 1 balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves major equipment 2 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 2 disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 2 balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves major equipment 3 funding ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 3 disbursement ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Reserves major equipment 3 balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 + +Reserves total reserves balance ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +Interest on reserves (%/year) 1.75 +Interest earned on reserves ($) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 +--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- + + + ***EXTENDED ECONOMICS*** + + Royalty Holder NPV: 41.21 MUSD + Royalty Holder Average Annual Revenue: 3.05 MUSD/yr + Royalty Holder Total Revenue: 100.70 MUSD diff --git a/tests/examples/Fervo_Project_Cape-8.txt b/tests/examples/Fervo_Project_Cape-8.txt new file mode 100644 index 000000000..21350565d --- /dev/null +++ b/tests/examples/Fervo_Project_Cape-8.txt @@ -0,0 +1,158 @@ +# Case Study: 100 MWe EGS Project Modeled on Fervo Cape Station (October 2026 Update) +# See documentation: https://softwareengineerprogrammer.github.io/GEOPHIRES/Fervo_Project_Cape-7.html#Fervo_Project_Cape-8-section +# 100 MWe variant of Fervo_Project_Cape-7 with capacity equivalent to Cape Station Phase I, derived by +# tests/regenerate-example-result.sh. Comments inherited from Fervo_Project_Cape-7 describe the 500 MWe case. +# October 2026 Update: subsurface design aligned with the Fervo 3.0 well design disclosed for Cape Station Phase II +# (Fervo Energy Q2 2026 earnings call, 2026-08-12). The case study remains a second-of-a-kind (SOAK) analog; +# the wellfield is re-sized for the 3.0 design rather than matched to Fervo's as-built well count, and +# lateral drilling cost is now modeled explicitly rather than folded into the vertical well cost. + +# *** ECONOMIC/FINANCIAL PARAMETERS *** +# ************************************* +Economic Model, 5, -- The SAM Single Owner PPA economic model is used to calculate financial results including LCOE, NPV, IRR, and pro-forma cash flow analysis. See [GEOPHIRES documentation of SAM Economic Models](https://softwareengineerprogrammer.github.io/GEOPHIRES/SAM-Economic-Models.html) for details on how System Advisor Model financial models are integrated into GEOPHIRES. +Inflation Rate, .03, -- US CPI-U was 3.4% year over year in August 2026 (core 2.4%) (BLS, 2026b), down from 4.2% in May 2026, when the energy index was up 23.5% year over year (BLS, 2026a). 3.0% is between core and headline and above the Federal Reserve's 2% target, a conservative assumption for a 30-year horizon. The February 2026 Update used 2.7%, US inflation as of December 2025. Note: [2024b ATB models lower inflation](https://atb.nrel.gov/electricity/2024b/definitions#inflation). GEOPHIRES holds fixed O&M flat in nominal terms; inflation affects capital cost escalation during construction and the nominal discount rate. + +Starting Electricity Sale Price, 0.115, -- Midpoint of the $100-130/MWh range Fervo reports for contracts currently under negotiation, of which approximately half are with hyperscale data center buyers (Fervo Energy, 2026f; 2026g). Above the prices implied by Fervo's existing contracts: Corsac Station's 15-year PPA at $107/MWh (CTVC, 2025), and Fervo's company-wide revenue backlog of approximately $7.2B across 658 MW of binding PPAs (Fervo Energy, 2026g), which implies roughly $91/MWh assuming 15-year terms at 91.3% capacity factor. Pricing for the subsequent 396 MW Google PPA was not disclosed (Fervo Energy, 2026b). The SOAK project is assumed to contract in 2026 or later for a 2030 commercial operation date. The February 2026 Update used $95/MWh, aligned with Geysers - Sacramento pricing in [2024b ATB](https://atb.nrel.gov/electricity/2024/geothermal) (NREL, 2025). See Sensitivity Analysis for effect of different prices on results. +Electricity Escalation Rate Per Year, 0.00183, -- $1.83/MWh per year. GEOPHIRES supports only linear (additive) escalation; this value reproduces the 15-year present value, at the case study WACC of approximately 9.2%, of a 1.5% per year compounding escalator on the $115/MWh starting price. 1.5% is the escalator in Ormat's 2025 Heber 1 geothermal PPA (CTVC, 2025); Fervo's PPA escalation terms are not disclosed. Reaches $140.6/MWh in operating year 15 versus $141.7/MWh under compounding. The February 2026 Update used $0.57/MWh per year, calibrated to reach $100/MWh at project year 11 from a $95/MWh start. +Ending Electricity Sale Price, 0.1406, -- Caps escalation at $140.6/MWh, the price reached in operating year 15, so that the price is held flat after the 15-year PPA term rather than continuing to escalate through the 30-year project lifetime. This represents an assumed post-contract re-contracting or merchant price equal to the final contract price. Note that this value does not directly determine price at the end of the project life, but rather acts as a cap on the price to which the starting price can escalate; the February 2026 Update set it to $1/kWh (no effective cap). +Electricity Escalation Start Year, 0, -- The first escalation step is applied in the second operating year, matching a PPA whose price escalates annually from the first anniversary of commercial operation. The February 2026 Update used 1, which GEOPHIRES applies as the first step in the third operating year. + +Fraction of Investment in Bonds, .63 +Discount Rate, 0.12, -- Typical discount rates for higher-risk projects may be 12–15%. This is a real (inflation-adjusted) rate; the SAM Economic Model discounts nominal cash flows at the equivalent nominal rate, (1 + discount rate) × (1 + inflation rate) − 1. +Inflated Bond Interest Rate, .07, -- 2024b ATB (NREL, 2025) +Debt Tenor, 18, -- The 2024b ATB debt amortization assumption, "a common debt amortization period for U.S. renewable energy projects, even if the term of debt is shorter" (NREL, 2025), and the SAM default. It extends 3 years beyond the approximately 15-year remaining terms of Fervo's binding PPAs (Fervo Energy, 2026d) and the case study's 15-year PPA, so debt service in operating years 16-18 relies on the post-PPA price (see Ending Electricity Sale Price); DSCR in those years is 1.80. Fervo's Phase I construction-to-term loan is a bank mini-perm maturing March 31, 2031, with quarterly amortization and a balloon at maturity (Fervo Energy, 2026h); the level-payment tenor modeled here stands in for its undisclosed amortization profile. A 15-year tenor matching the PPA term is the conservative case. Counted from COD. The February 2026 Update repaid debt over the 30-year plant lifetime, the only option before GEOPHIRES 3.18. + +Inflated Bond Interest Rate During Construction, 0.105, -- Higher than interest rate during normal operation to account for increased risk of default prior to COD. Value aligns with ATB discount rate (NREL, 2025). +Bond Financing Start Year, -1 + +Construction Years, 3 + + + + +Construction CAPEX Schedule, 0.075,0.525,0.4 + +Investment Tax Credit Rate, 0.3, -- Statutory rate; Geothermal Drilling and Completions Apprenticeship Program ensures compliance with ITC labor requirements (Southern Utah University, 2024). GEOPHIRES's SAM Single Owner PPA model applies this rate to total installed cost, which includes the interconnection cost entered under One-time Flat License Fees Etc. Under IRC §48(a)(8) qualified interconnection property is in the ITC basis only for energy property of 5 MW or less, so the model overstates the credit by approximately $86M (30% of the $287M interconnection cost including its inflation and interest during construction); an equivalent rate of 0.2768 on total installed cost would remove it and reduces IRR by about 1.1 points. The statutory rate is retained for clarity because the overstatement is offset in direction, and likely in magnitude, by an unmodeled benefit on the same line item: in non-ISO balancing authorities such as PacifiCorp, network upgrade costs, the majority of interconnection cost, are often refunded to the interconnection customer over up to 20 years with interest once the plant reaches commercial operation (Seel et al., 2026). Taxpayer-owned point-of-interconnection facilities may also qualify as integral power conditioning and transfer equipment regardless of project size, which would reduce the overstatement further. +Combined Income Tax Rate, .2555, -- Federal Corporate Income Tax Rate of 21% plus Utah Corporate Franchise and Income Tax Rate of 4.55%. (Note: This input uses a simple summation of statutory rates; the effective combined rate calculated in the model may differ due to standard federal-state tax interactions.) +Property Tax Rate, 0.0022, -- Utah Inland Port Authority (UIPA) tax differential incentive +Depreciation Schedule, 2, -- 5-year MACRS, the statutory depreciation class for facilities that claim the technology-neutral clean electricity credits (IRC sections 48E and 45Y); geothermal facilities that begin construction by the end of 2033 receive the full credit (Norton Rose Fulbright, 2025). The SAM Single Owner model counts the resulting early-year tax losses as tax benefits in the years they occur, which assumes the owner can use them, for example through a tax equity partner; the 2024b ATB likewise assumes tax benefits are used efficiently through tax equity (NREL, 2025). Allocating the entire depreciable basis to 5-year MACRS slightly overstates the benefit, since the interconnection cost would be depreciated over a longer life (about 0.4 percentage points of IRR). The February 2026 Update used 20-year straight line. + +Capital Cost for Power Plant for Electricity Generation, 1900, -- [US DOE, 2021](https://betterbuildingssolutioncenter.energy.gov/sites/default/files/attachments/Waste_Heat_to_Power_Fact_Sheet.pdf). Pricing information not publicly available for Turboden or Baker Hughes Gen 2 ORC units (Turboden, 2025; Jacobs, 2025). Note: Fervo states that drilling, completion and well pad facilities are about half of pre-COD CAPEX and surface power generation equipment about half (Fervo Energy, 2026f); this case study yields roughly 47% subsurface (drilling, completion, stimulation and gathering) / 53% surface plant, excluding interconnection and exploration, so the plant cost may be modestly overstated and/or the well costs understated relative to Fervo's actuals. +Exploration Capital Cost, 56, -- Equivalent to 2024b ATB NF-EGS conservative scenario exploration assumption of 5 full-size wells (NREL, 2025) at this case study's all-in well cost of $8.48M, plus $1M for geophysical and field work, plus 15% contingency, plus 12% indirect costs: (5 × $8.48M + $1M) × 1.15 × 1.12 = $55.9M. The February 2026 Update used $30M, derived the same way from a $4.65M well. Recompute this value whenever the per-well drilling and completion cost changes. + +Well Drilling Cost Correlation, 3, -- 2025 NREL Geothermal Drilling Cost Curve Update (Akindipe and Witter, 2025). +Well Drilling and Completion Capital Cost Adjustment Factor, 0.72, -- Applied to both the vertical correlation and the lateral cost. Yields $8.5M/well all-in (vertical $4.40M + lateral $4.08M, each including 5% indirect costs) versus $11.8M at factor 1.0 for the 3.06 km TVD, 7,500 ft lateral geometry. Calibration: Fervo's first Cape Station well ($9.4M) and best Phase I well ($4.8M), both 5,000 ft lateral 2.0-design wells, correspond to factors of 1.14 and 0.58 respectively against the same correlation with the lateral costed explicitly. The SOAK value of 0.72 is the geometric mean of the ATB-aligned baseline (0.9) and Fervo's best demonstrated well (0.58), decomposing as 0.70 for a fast follower's learning position times 1.029 for the temperature adjustment at 221℃ (NREL 2025 drilling cost curves). It is about 4% above the INTERMEDIATE1 drilling technology scenario (US DOE, 2019) at factor 1.0 ($8.1M/well for the same geometry, with the lateral at that scenario's per-meter cost). Fervo cites batch drilling among its drilling efficiency gains, reports a record 21-day spud-to-total-depth time on the Sawtooth 7 well, and has trialed rotary steerable systems on deeper wells (Fervo Energy, 2026a; 2026f). Reference points: 0.58 ($6.8M/well) for Fervo-demonstrated performance; 0.9 ($10.6M/well) for the unadjusted ATB baseline; Latimer's stated target of under $4M/well (Latimer, 2025) corresponds to roughly 0.35 and is treated as a NOAK aspiration rather than a SOAK comparable. Note: the February 2026 Update used 0.9 on the vertical correlation only with the lateral folded in, which yielded $4.65M/well at 2.68 km; against the lateral-inclusive correlation that was an effective factor of about 0.58, i.e. Fervo's best demonstrated well rather than a conservative SOAK assumption. See [Sensitivity Analysis](#sensitivity-analysis-section) for effect of different drilling costs on results. +All-in Nonvertical Drilling Costs, 2360, -- USD per meter of lateral before the adjustment factor and indirect costs. Value from the 2025 NREL geothermal drilling cost curve (Akindipe and Witter, 2025) for the vertical large diameter baseline correlation at 3.06 km, as computed by the SWS Geothermal Platform drilling cost calculator; the calculator assumes the same per-meter cost for lateral and vertical sections. Scaled by the Well Drilling and Completion Capital Cost Adjustment Factor and by Multilaterals Cased. +Multilaterals Cased, True, -- Fervo's laterals are cased and cemented for plug-and-perf multistage stimulation (Norbeck et al., 2024). GEOPHIRES halves the lateral cost when this is False (the default), on the assumption that casing and cementing are 50% of drilling cost. + +Reservoir Stimulation Capital Cost per Fracture Surface Area, 0.875, -- USD per square meter of nominal (single-face, planar) fracture area, before adjustment factor, indirect costs and contingency; GEOPHIRES multiplies by Fracture Width × Fracture Height × Number of Fractures per Stimulated Well × number of stimulated wells. Equivalent to $4M per 12-stage 5,000 ft lateral (150 fractures) and $6M per 18-stage 7,500 ft lateral (225 fractures) at the case study fracture geometry, i.e. the same per-stage calibration used in the February 2026 Update: high-intensity U.S. shale wells (Baytex Energy, 2024; Quantum Proppant Technologies, 2020), the closest technological analogue for multi-stage EGS (Gradl, 2018). Costs are also driven by the requirement for high-strength ceramic proppant rather than standard sand, which would crush or chemically degrade (diagenesis) over a 30-year lifecycle at 200℃ (Ko et al., 2023; Shiozawa and McClure, 2014) and the premium for ultra-high-temperature (HT) downhole tools. Fervo also reports sourcing equipment to pump at the higher pressures required by the deeper Phase II wells (Fervo Energy, 2026f). Parameterizing by area rather than per well makes stimulation cost track fracture count and geometry automatically in sensitivity and variant scenarios. Note that all-in costs per well are higher than the direct cost because they include indirect costs and contingency. See [Sensitivity Analysis](#sensitivity-analysis-section) for effect of different stimulation costs on results. +Reservoir Stimulation Capital Cost per Production Well, -1, -- Indicates that production wells are stimulated (in addition to injection wells, which GEOPHIRES stimulates by default); the per-area cost is then apportioned across all wells. + +Field Gathering System Capital Cost Adjustment Factor, 0.54, -- Gathering costs represent 2% of facilities CAPEX per [Matson, 2024](https://www.linkedin.com/pulse/fervo-energy-technology-day-2024-entering-geothermal-decade-matson-n4stc/). + +One-time Flat License Fees Etc, 50 +Annual License Fees Etc, 5.4 + +Royalty Rate, 0.0175, -- The BLM royalty structure is 1.75% of gross proceeds from electricity sales for the first 10 years of production (Code of Federal Regulations, 2024). +Royalty Rate Escalation Start Year, 11, -- After the first 10 years of production, the royalty rate escalates to 3.5%. +Royalty Rate Escalation, 0.0175, -- Escalation at Year 11 from 1.75% to 3.5%. +Royalty Rate Maximum, 0.035, -- No further escalation beyond 3.5%. + + +# *** SURFACE & SUBSURFACE TECHNICAL PARAMETERS *** +# ************************************************* +End-Use Option, 1, -- Electricity +Power Plant Type, 2, -- Gen 2 ORC units (Turboden, 2025). +Plant Lifetime, 30, -- Sets the project economic horizon, aligned with Fervo's anticipated 30-year well life (Fervo Energy, 2025a). Modeling Distinction: While Fervo projects physical wellbore integrity for 30 years, GEOPHIRES simulates "redrilling events" to model thermal management of the reservoir volume. This treats the 30-year lifespan as an aggregate of shorter-lived thermal cycles delineated by discrete redrilling events occurring at intervals dictated by the Maximum Drawdown parameter. The modeled cost of each redrilling event is equivalent to the drilling and stimulation cost of the entire wellfield, serving as a conservative cost proxy for the major interventions (e.g., sidetracking and stimulating laterals into fresh rock, or drilling new wells if necessary) required to sustain the PPA target against thermal depletion. Fervo describes its approach as a makeup-well drilling program in which later wells benefit from cumulative learnings (Fervo Energy, 2026f). + +Surface Temperature, 13, -- Surface temperature near Milford, UT (38.4987670, -112.9163432) ([Project InnerSpace, 2025](https://geomap.projectinnerspace.org/test/)). + +Number of Segments, 3 +Gradient 1, 74, -- Sedimentary overburden. 200℃ at 8500 ft depth (Fercho et al. 2024); 228.89℃ at 9824 ft (Norbeck et al. 2024). +Thickness 1, 2.5 +Gradient 2, 41, -- Crystalline reservoir +Thickness 2, 0.5 +Gradient 3, 39.1, -- Sugarloaf appraisal + +Reservoir Depth, 3.06, -- Depth at which the segmented gradient yields a bottom-hole temperature of approximately 221℃ (430℉), the average reservoir temperature design point of the Fervo 3.0 well design used for Cape Station Phase II (Fervo Energy, 2026f; 2026g). The previous value of 2.68 km was extrapolated from surface temperature, gradient, and average production temperature of shallower and deeper producers in Singh et al., 2025, corresponding to the roughly 400℉ Phase I design. Fervo reports 460℉ at the Sawtooth 7 well (Fervo Energy, 2026a), so 430℉ is not an upper bound for the resource. + +Reservoir Density, 2800, -- phyllite + quartzite + diorite + granodiorite ([Norbeck et al., 2023](https://doi.org/10.31223/X52X0B)) +Reservoir Heat Capacity, 790 +Reservoir Thermal Conductivity, 3.05 +Reservoir Porosity, 0.0118 + +Reservoir Model, 1, -- See the [reservoir engineering calibration section](#res-eng-params-calibration-section) for additional details. +Reservoir Volume Option, 1, -- FRAC_NUM_SEP: Reservoir volume calculated with fracture separation and number of fractures as input + +Number of Fractures per Stimulated Well, 225, -- The model assumes an Extreme Limited Entry stimulation design (Fervo Energy, 2023a) utilizing 15 clusters per stage (derived from Singh et al., 2025) and 81–85% stimulation success rate per 2024b ATB Moderate Scenario (NREL, 2025). The previous 12-stage count for a 5,000 ft lateral is scaled proportionally to 18 stages for the 7,500 ft lateral of the Fervo 3.0 design, preserving the stage length of approximately 417 ft. Fervo attributes more stimulated reservoir volume per well and a more gradual decline profile to the longer laterals (Fervo Energy, 2026f). +Fracture Separation, 9.8255, -- Based on 30 foot cluster spacing (Singh et al., 2025) marginally uprated to align with long-term thermal decline behavior trend towards wider fracture spacing (Fercho et al., 2025). + +Fracture Shape, 4, -- Bench design and fracture geometry in Singh et al., 2025 are given in rectangular dimensions. +Fracture Width, 305, -- Matches intra-bench well spacing of 500 ft (corresponding to fracture length of 1000 ft) (Singh. et al., 2025) +Fracture Height, 100, -- Actual fracture geometry is irregular and heterogeneous; this height complies with the minimum height required by the implemented bench design (200 ft; 60.96 meters) and yields an effective fracture surface area consistent with simulation results in Singh. et al., 2025. + +Water Loss Fraction, 0.01, -- Fervo states that "long-term modeling, calibrated to early field data, predicts high circulation recapture rates" and that previous studies have shown recapture rates of 80% to 99% ([Geothermal Mythbusting: Water Use and Impacts](https://fervoenergy.com/geothermal-mythbusting-water-use-and-impacts/); Fervo Energy, 2025a). The 1% loss fraction corresponds to the top of that range. Modeling in Singh et al., 2025 predicts fluid loss of 0.36% to 0.49%. +Water Cost Adjustment Factor, 2, -- Local scarcity may increase procurement costs. Development near/on land with active/shut-in oil and gas wells could potentially utilize waste water to recover losses and offset costs. + +Ambient Temperature, 11.17, -- Average annual temperature of Milford, Utah ([NCEI](https://www.ncei.noaa.gov/access/us-climate-normals/#dataset=normals-annualseasonal&timeframe=30&station=USC00425654)). Note that this value affects heat to power conversion efficiency. The effects of hourly and seasonal ambient temperature fluctuations on efficiency and power generation are not modeled in this version of the case study. + +Utilization Factor, .913, -- (DeGolyer and MacNaughton, 2024) +Plant Outlet Pressure, 2000 psi, -- McClure, 2024; Singh et al., 2025. +Circulation Pump Efficiency, 0.80 + +# *** Well Bores Parameters *** + +Number of Production Wells, 10 +Number of Injection Wells per Production Well, 0.666, -- Modeled on the reference case 5-well bench pattern (3 producers : 2 injectors) described in Singh et al., 2025. + +Nonvertical Length per Multilateral Section, 7500 feet, -- Lateral length of the Fervo 3.0 well design used for Cape Station Phase II (Fervo Energy, 2026f; 2026g); Phase I used 5,000 ft laterals, the target length given in the environmental assessment (BLM, 2024). Note that lateral length is assumed to be an upper bound constraining the number of fractures per well for a given cluster spacing. +Well Geometry Configuration, 4, -- L configuration: vertical section to reservoir depth plus one lateral per well. Required for GEOPHIRES to cost the lateral explicitly. +Number of Multilateral Sections per Vertical Section, 1, -- One lateral per well (producers and injectors); GEOPHIRES multiplies by the total well count, so this does not need updating when the number of wells changes. The February 2026 Update set Number of Multilateral Sections to 0 and folded lateral cost into the vertical well cost via the adjustment factor; the lateral is now costed explicitly (see All-in Nonvertical Drilling Costs and Multilaterals Cased). Requires GEOPHIRES 3.16.1 or later. + +Production Flow Rate per Well, 107, -- Cape Station pilot testing reported a sustained flow rate of 95–100 kg/s and maximum flow rate of 107 kg/s (Fervo Energy, 2024). Modeling by Singh et al. suggests initial flow rates of 120–130 kg/sec that gradually decrease over time (Singh et al., 2025). The case study flow rate is chosen both as a conservative target for long-term sustainability and to achieve a more economically favorable drawdown and redrilling schedule. Pumping load is set by the Productivity and Injectivity Index parameters rather than by flow rate; see Injectivity Index. +# The ATB Advanced Scenario models sustained flow rates of 110 kg/s (NREL, 2024). + +Production Well Diameter, 7.825, -- Inner diameter of 8⅝ inch, 36 lb/ft casing. Fervo disclosed 8⅝ inch casing for the 3.0 well design (up from 7 inch in Phase I) (Fervo Energy, 2026f; 2026g); the February 2026 Update inferred 9⅝ inch (8.535 in ID) from a less specific announcement (Fervo Energy, 2025b). Casing weight is not disclosed; API IDs for 8⅝ in range from about 7.5 in (49 lb/ft) to 8.1 in (24 lb/ft). +Injection Well Diameter, 7.825, -- See Production Well Diameter + +Production Wellhead Pressure, 303 psi, -- Modeled at a constant 300 psi in Singh et al., 2025. We use a marginally uprated value to conform to GEOPHIRES's calculated minimum wellhead pressure and nominally align with the gradual increase in WHP for constant flow rates modeled by Singh et al. + +Injectivity Index, 1.20, -- Based on ATB Conservative Scenario (NREL, 2025) derated per analyses that suggest lower productivity/injectivitity (Xing et al., 2025; Yearsley and Kombrink, 2024), and further derated in this version (from 1.38) to yield a parasitic load of at least 20% of net generation. Norbeck (2026) reported observed parasitic loads of approximately 25–35% in Phase I operations with a goal of eventually reaching 15–20%; a SOAK case is not credibly modeled below the low end of that goal. The February 2026 Update's ~16% aligned with the 16.7% ceiling implied by Fervo's Phase II procurement of 480 MW gross for 400 MW net, which is a design target rather than observed performance. Result: 21.1% initial and 20.8% average pumping power relative to net generation (17.2% relative to gross generation). The production-side pressure drop is dominated by flow ÷ Productivity Index; the injection side becomes pump-limited once flow ÷ Injectivity Index exceeds the plant outlet pressure, which occurs below an Injectivity Index of roughly 1.38 at 107 kg/s per producer. +Productivity Index, 0.98, -- See Injectivity Index. Derated from 1.13 in proportion with the Injectivity Index (ratio 1.22 preserved). + +Ramey Production Wellbore Model, True, -- Ramey's model estimates the geofluid temperature drop in production wells +Injection Temperature, 53.6, -- Calibrated with GEOPHIRES model-calculated reinjection temperature (Beckers and McCabe, 2019). Close to upper bound of Project Red injection temperatures (75–125℉; 23.89–51.67℃) (Norbeck and Latimer, 2023). Note: GEOPHIRES enforces a thermodynamic optimum that overrides higher values, such as the 85°C ORC outlet temperature specified in Cape Station's plant design (DeGolyer and MacNaughton, 2024) (intended for silica scaling mitigation), resulting in a "maximum theoretical power" scenario. Support for higher reinjection temperatures may be added in future GEOPHIRES versions. +Injection Wellbore Temperature Gain, 3, -- Empirical estimate for high-flow rate wells where rapid fluid velocity minimizes heat uptake during descent (Ramey, 1962). + +Maximum Drawdown, 0.0025, -- This value represents the fractional drop in production temperature compared to the initial temperature that is allowed before the wellfield is redrilled. It is calibrated to maintain the PPA minimum net electricity generation requirement. It is a very small percentage because it is relative to the initial production temperature; the temperature quickly rises higher due to thermal conditioning and plateaus until breakthrough, so any drawdown relative to the initial value signals that the temperature has already declined from its stabilized peak. +Redrilling Learning Rate, 0.1, -- Each doubling of the number of wellfields drilled at the site cuts the cost of the next by 10%, so the first redrill costs 90% of the original wellfield and the eighth 72%. At Cape Station, the first six horizontal wells improved by 15% (drilling days) to 20% (cost) per doubling, but there and in other fields the gains level off after the first wells, and geothermal well costs flatten at 70 to 75% of the first well’s (El-Sadi et al., 2024, as tabulated by Akindipe and Witter, 2025, Lowry et al., 2017, Kellogg, 2009). + +# *** SIMULATION PARAMETERS *** +# ***************************** +Maximum Temperature, 500 +Time steps per year, 12 + +Project Latitude, 38.506196 +Project Longitude, -112.918155 + +# *** ADDITIONAL REFERENCES (October 2026 Update) *** +# Fervo Energy. (2026a, August 12). Fervo Energy Reports Second Quarter 2026 Results. https://fervoenergy.com/fervo-energy-reports-second-quarter-2026-results/ +# Fervo Energy. (2026b, September 1). Fervo Energy and Google Sign 396 MW PPA. https://fervoenergy.com/fervo-energy-and-google-sign-396-mw-ppa/ +# Fervo Energy. (2026c, June 22). First Quarter 2026 Results. https://ir.fervoenergy.com/news-releases/news-release-details/fervo-energy-reports-first-quarter-2026-results +# Fervo Energy. (2026d, May 11). Form S-1/A (Amendment No. 3). Cape Station Phase I overnight capital cost of approximately $7,000/kW. https://www.sec.gov/Archives/edgar/data/1853868/000162828026033127/fervoenergy-sx1a3.htm +# Fervo Energy. (2026e, September 24). Fervo Energy Achieves First Power at Cape Station, a Landmark Moment for the Future of Enhanced Geothermal Systems. https://fervoenergy.com/fervo-energy-achieves-first-power-at-cape-station-a-landmark-moment-for-the-future-of-enhanced-geothermal-systems/ +# Fervo Energy. (2026f, August 12). Fervo Energy (FRVO) Q2 2026 Earnings Call Transcript. The Motley Fool, published August 19, 2026. https://www.fool.com/earnings/call-transcripts/2026/08/19/fervo-energy-frvo-q2-2026-earnings-call-transcript/ (webcast replay: https://edge.media-server.com/mmc/p/va49yxkc/) +# Fervo Energy. (2026g, August 12). Q2 2026 Quarterly Results [Earnings presentation]. https://ir.fervoenergy.com/static-files/28260ce5-2ac0-458e-bfb7-2d80f3709cae +# Fervo Energy. (2026h, August 13). Form 10-Q for the quarter ended June 30, 2026 (Project Granite Facility). https://www.sec.gov/Archives/edgar/data/1853868/000162828026056457/frvo-20260630.htm +# Fervo Energy. (2026i, March 19). Fervo Energy Secures $421 Million in Non-Recourse Project Financing for Cape Station. https://fervoenergy.com/fervo-energy-secures-421-million-in-non-recourse-project-financing-for-cape-station/ +# Fervo Energy. (2026j, October 1). Fervo Energy Declares Commercial Operation at Cape Station Ahead of Schedule, Leading the Race for Next-Generation Geothermal Energy. https://www.globenewswire.com/news-release/2026/10/01/3372717/0/en/fervo-energy-declares-commercial-operation-at-cape-station-ahead-of-schedule-leading-the-race-for-next-generation-geothermal-energy.html +# Norton Rose Fulbright. (2025, July 7). Effects of "One Big Beautiful Bill" on Projects. https://www.projectfinance.law/publications/effects-of-one-big-beautiful-bill-on-projects +# BLS. (2026a, June 10). Consumer Price Index - May 2026. https://www.bls.gov/news.release/archives/cpi_06102026.htm +# BLS. (2026b, September 11). Consumer Price Index - August 2026. https://www.bls.gov/news.release/archives/cpi_09112026.htm +# CTVC. (2025, September 2). The $783m PPA that keeps on drilling #260. https://www.ctvc.co/the-783m-ppa-that-keeps-on-drilling-260/ +# PacifiCorp. (2017, June 1). FAQ: Transmission and Ancillary Service Rate Changes. https://www.oasis.oati.com/PPW/PPWdocs/Rate_Update_FAQ_20170601.pdf +# BPA. (2025, October). 2026 Transmission, Ancillary, and Control Area Service Rate Schedules and General Rate Schedule Provisions (FY 2026-2028). https://www.bpa.gov/-/media/Aep/rates-tariff/bp-26/Final-Transmission-Rate-Schedules-and-GRSPs.pdf +# Rocky Mountain Power. (2026, January 26). Notice of Intent to Use ECR Input and Proposed Tariff Changes to Electric Service Schedule No. 137, Net Billing Service. Public Service Commission of Utah. https://pscdocs.utah.gov/electric/26docs/26035T03/343554Trf1-26-2026.pdf +# US DOE. (2019). GeoVision: Harnessing the Heat Beneath Our Feet (p. 163, drilling cost scenarios). https://www.energy.gov/sites/prod/files/2019/06/f63/GeoVision-full-report-opt.pdf +# Seel, J., Manderlink, N., Mulvaney Kemp, J., Rand, J., Gorman, W., Wiser, R., Cotton, W., Porter, K. (2026, February). Generator Interconnection Costs to the Transmission System in non-ISO Balancing Authorities. Lawrence Berkeley National Laboratory. https://eta-publications.lbl.gov/sites/default/files/2026-02/lbnl_2026.02.23_ba_interconnection_costs.pdf +# Utility Dive. (2026, June 5). Fervo Energy faces transmission constraints in the West, analysts say. https://www.utilitydive.com/news/fervo-energy-geothermal-transmission-constraints/822141/ diff --git a/tests/geophires_x_tests/test_fervo_project_cape_7.py b/tests/geophires_x_tests/test_fervo_project_cape_7.py index bb833ed7d..e452bcdd7 100644 --- a/tests/geophires_x_tests/test_fervo_project_cape_7.py +++ b/tests/geophires_x_tests/test_fervo_project_cape_7.py @@ -316,6 +316,77 @@ def test_flow_rate_parametric_data_matches_example_result(self) -> None: with self.subTest(field_name=field_name): self.assertAlmostEqual(getattr(expected_base_row, field_name), getattr(base_row, field_name), places=2) + def test_fervo_project_cape_8(self) -> None: + """ + Fervo_Project_Cape-8 (100 MWe) is derived from Fervo_Project_Cape-7 - see tests/regenerate-example-result.sh + """ + fpc8_result = GeophiresXResult(self._get_test_file_path('../examples/Fervo_Project_Cape-8.out')) + fpc8_input_params_dict = self._get_input_parameters( + ImmutableGeophiresInputParameters( + from_file_path=self._get_test_file_path('../examples/Fervo_Project_Cape-8.txt') + ) + ) + + ppa_minimum_net_generation_mwe = 100 + min_net_gen_dict = fpc8_result.result['SURFACE EQUIPMENT SIMULATION RESULTS'][ + 'Minimum Net Electricity Generation' + ] + min_net_gen_mwe = quantity(min_net_gen_dict['value'], min_net_gen_dict['unit']).to('MW').magnitude + self.assertGreater(min_net_gen_mwe, ppa_minimum_net_generation_mwe) + + # Fewest production wells that meet the PPA minimum, approximating net generation as proportional to the number + # of production wells + num_production_wells = int(fpc8_input_params_dict['Number of Production Wells']) + self.assertLess( + min_net_gen_mwe * (num_production_wells - 1) / num_production_wells, ppa_minimum_net_generation_mwe + ) + + _, min_dscr = generate_fervo_project_cape_7_md._get_min_dscr(fpc8_result) + self.assertGreaterEqual(min_dscr, 1.35) + + def test_fervo_project_cape_8_matches_fervo_project_cape_7(self) -> None: + """ + Fails when Fervo_Project_Cape-7 changes without Fervo_Project_Cape-8 being regenerated, or when Fervo_Project_Cape-7 + changes a value that the Fervo_Project_Cape-8 derivation in tests/regenerate-example-result.sh hard-codes. + """ + + def _input_params_dict(example_name: str) -> dict[str, Any]: + return self._get_input_parameters( + ImmutableGeophiresInputParameters( + from_file_path=self._get_test_file_path(f'../examples/{example_name}.txt') + ) + ) + + fpc7_input_params_dict = _input_params_dict('Fervo_Project_Cape-7') + fpc8_input_params_dict = _input_params_dict('Fervo_Project_Cape-8') + + params_derived_for_100_mwe = { + 'Fraction of Investment in Bonds', + 'Bond Financing Start Year', + 'Construction Years', + 'Construction CAPEX Schedule', + 'One-time Flat License Fees Etc', + 'Annual License Fees Etc', + 'Number of Production Wells', + } + + def _without_params_derived_for_100_mwe(input_params_dict: dict[str, Any]) -> dict[str, Any]: + return {k: v for k, v in input_params_dict.items() if k not in params_derived_for_100_mwe} + + self.assertDictEqual( + _without_params_derived_for_100_mwe(fpc7_input_params_dict), + _without_params_derived_for_100_mwe(fpc8_input_params_dict), + ) + + capacity_ratio = 100 / 500 + for scaled_param_name in ['One-time Flat License Fees Etc', 'Annual License Fees Etc']: + with self.subTest(param_name=scaled_param_name): + self.assertAlmostEqual( + float(fpc7_input_params_dict[scaled_param_name]) * capacity_ratio, + float(fpc8_input_params_dict[scaled_param_name]), + places=6, + ) + def test_get_fpc7_flow_rate_parametric_summary(self) -> None: def _row(flow: float, min_net_mw: float, redrills: int, irr_pct: float) -> FlowRateParametricRow: return FlowRateParametricRow( diff --git a/tests/regenerate-example-result.sh b/tests/regenerate-example-result.sh old mode 100755 new mode 100644 index 89387cc8b..8a04434cd --- a/tests/regenerate-example-result.sh +++ b/tests/regenerate-example-result.sh @@ -36,6 +36,32 @@ then examples/Fervo_Project_Cape-5.txt > examples/Fervo_Project_Cape-6.txt fi +if [[ $1 == "Fervo_Project_Cape-8" ]] +then + echo "Syncing Fervo_Project_Cape-8.txt from Fervo_Project_Cape-7.txt..." + + # 100 MWe: fewest producers for minimum net generation above 100 MWe; interconnection and transmission costs + # scaled from 500 MWe; debt fraction resized for a minimum DSCR of at least 1.35. Recheck the producer count and + # debt fraction whenever Fervo_Project_Cape-7 changes. + sed -e '1s/500 MWe EGS Project Modeled on Fervo Cape Station Phase II/100 MWe EGS Project Modeled on Fervo Cape Station/' \ + -e 's/\/Fervo_Project_Cape-7.html$/\/Fervo_Project_Cape-7.html#Fervo_Project_Cape-8-section/' \ + -e '3i\ +# 100 MWe variant of Fervo_Project_Cape-7 with capacity equivalent to Cape Station Phase I, derived by\ +# tests/regenerate-example-result.sh. Comments inherited from Fervo_Project_Cape-7 describe the 500 MWe case.' \ + -e 's/^Fraction of Investment in Bonds,.*/Fraction of Investment in Bonds, .63/' \ + -e 's/^Bond Financing Start Year,.*/Bond Financing Start Year, -1/' \ + -e 's/^Construction Years,.*/Construction Years, 3/' \ + -e '/^# ATB advanced scenario/d' \ + -e '/^# DOE scenario/d' \ + -e '/^# DOE-ATB hybrid scenario/d' \ + -e '/^# Construction CAPEX Schedule/d' \ + -e 's/^Construction CAPEX Schedule,.*/Construction CAPEX Schedule, 0.075,0.525,0.4/' \ + -e 's/^One-time Flat License Fees Etc,.*/One-time Flat License Fees Etc, 50/' \ + -e 's/^Annual License Fees Etc,.*/Annual License Fees Etc, 5.4/' \ + -e 's/^Number of Production Wells,.*/Number of Production Wells, 10/' \ + examples/Fervo_Project_Cape-7.txt > examples/Fervo_Project_Cape-8.txt +fi + if [[ $1 == "example5b" ]] then python regenerate_example_input_reservoir_output_profile.py example5b src/geophires_x/Examples/ReservoirOutput.txt @@ -63,6 +89,8 @@ fi if [[ $1 == "Fervo_Project_Cape-7" ]] then + ./regenerate-example-result.sh Fervo_Project_Cape-8 + # The documentation reads the flow rate parametric data, so regenerate it first. echo "Regenerating Fervo_Project_Cape-7 flow rate parametric data..." python ../src/geophires_docs/fervo_project_cape_7_scenarios.py From 8eedecd241cf9b63ff587c065344626b7c09fe06 Mon Sep 17 00:00:00 2001 From: softwareengineerprogrammer <4056124+softwareengineerprogrammer@users.noreply.github.com> Date: Thu, 15 Oct 2026 09:10:08 -0700 Subject: [PATCH 2/7] update readme - include fpc8, mark fpc5/6 as deprecated --- README.rst | 22 +++++++++++++--------- 1 file changed, 13 insertions(+), 9 deletions(-) diff --git a/README.rst b/README.rst index c4414eaa5..936d06a47 100644 --- a/README.rst +++ b/README.rst @@ -168,18 +168,14 @@ Example-specific web interface deeplinks are listed in the Link column. - Input file - Case report file - Link - * - Case Study: 500 MW EGS Modeled on Fervo Cape Station (February 2026 Update) (`documentation