Model Reference Documentation
Comprehensive baseline assumptions and parameters for the RNG Economic Model
Table of Contents
1. Executive Summary
The RNG Economic Model uses industry-standard assumptions and parameters derived from academic research, commercial project data, and regulatory frameworks. All baseline assumptions are calibrated for commercial-scale renewable natural gas projects in North America as of 2025.
Key Model Characteristics:
- • Base Case Project: 280 MMBtu/day (~107,702 GJ/year) RNG production
- • Capital Cost: $12.5M baseline investment
- • Project Lifespan: 25 years operational period
- • Discount Rate: 8% (representative of commercial RNG projects)
- • Currency: All values in 2025 USD
- • Geography: Optimized for Western US markets (California LCFS focus)
Model Coverage:
- • 6 Feedstock Types: Dairy manure, landfill gas, wastewater sludge, agricultural residues, food waste, power-to-gas
- • 3 LCFS Regions: California, Oregon, Washington
- • 2 Add-on Technologies: CNG liquefaction, Power-to-Gas synthesis
- • Government Incentives: Federal tax credits (45Z), LCFS credits, RINs
2. Financial Parameters
Core Financial Assumptions
| Project Lifespan | 25 years |
| Discount Rate (WACC) | 8.0% |
| Base Capital Cost | $12.5M |
| Base Production Capacity | 280 MMBtu/day |
| Energy Conversion Factor | 1.055 GJ/MMBtu |
| Base Selling Price | $15.5/GJ |
Financing Structure
| Debt Ratio | 70% |
| Cost of Debt | 5.5% |
| Tax Rate | 25% |
| Investment Tax Credit (ITC) | 30% |
| Inflation Rate | 2.5% |
| Natural Gas Reference Price | $3.5/MMBtu |
Source: Financial parameters based on commercial RNG project benchmarks, industry reports from EPA AgSTAR, and renewable energy financing standards.
3. Feedstock-Specific Cost Assumptions
Dairy Manure (Default: $3.2/GJ)
Feedstock Cost
$0/wet ton
Often free or negative (tipping fee revenue)
Transport Cost
$8.5/wet ton
Collection and hauling from farms
Processing Cost
$3.2/GJ RNG
Anaerobic digestion, upgrading, O&M
Landfill Gas (Default: $2.8/GJ)
Gas Rights Fee
$0.5/MMBtu
Landfill gas extraction rights
Collection System
$45/SCFM
Gas collection infrastructure
Processing Cost
$2.8/GJ RNG
NMOC/siloxane removal, upgrading
Wastewater Sludge (Default: $5.2/GJ)
Sludge Handling
$15/dry ton
Sludge processing and preparation
Pre-treatment
$2.5/m³
Thickening, dewatering operations
Processing Cost
$5.2/GJ RNG
Digestion, H₂S removal, upgrading
Agricultural Residues (Default: $6.5/GJ)
Feedstock Cost
$35/dry ton
Corn stover, wheat straw procurement
Collection/Transport
$25/dry ton
Harvest, baling, transport operations
Processing Cost
$6.5/GJ RNG
Pretreatment, gasification, upgrading
Food Waste (Default: $4.8/GJ)
Tipping Fee
-$25/wet ton
Revenue from waste disposal service
Preprocessing
$12/wet ton
Sorting, grinding, contaminant removal
Processing Cost
$4.8/GJ RNG
Anaerobic digestion, upgrading
Power-to-Gas (Default: $12.5/GJ)
Electricity Input
$45/MWh
Renewable electricity for electrolysis
CO₂ Input
$25/tonne
Captured CO₂ for methanation
Processing Cost
$12.5/GJ RNG
Electrolysis, methanation, O&M
4. Technical Parameters
Biogas Production
| Biogas Yield | 0.25 m³/kg VS |
| Methane Content | 60% |
| Upgrading Efficiency | 95% |
| Parasitic Load | 15% |
| Capacity Factor | 90% |
| System Degradation | 0.5%/year |
Gas Quality Standards
| Pipeline Methane Content | 96-98% |
| H₂S Content (max) | 4 ppm |
| CO₂ Content (max) | 2% |
| Water Content (max) | 112 mg/m³ |
| Injection Pressure | 1,000 psi |
| Heating Value | 950-1,150 Btu/scf |
5. Economic Assumptions
LCFS Credit Pricing ($/tCO₂e)
| California LCFS | $66.25 |
| Oregon CFP | $43.05 |
| Washington CFS | $22.60 |
Prices as of Q2 2025. California market has 29.19M credit surplus affecting pricing.
Federal Incentives
| RINs (D3 Cellulosic) | $21/MMBtu |
| 45Z Production Tax Credit | $1.00/gallon equiv |
| Investment Tax Credit | 30% |
| Combined Subsidies | $4.2/GJ |
Combined value includes federal 45Z credit, LCFS credits, and RINs value.
6. Emissions Factors
Default Project Emissions
| Baseline Emissions | 20,100 tCO₂e/year |
| Project Emissions | 4,350 tCO₂e/year |
| Net Carbon Credits | 15,750 tCO₂e/year |
| Methane GWP | 25 |
| Leakage Factor | 0% |
Feedstock-Specific Emissions
| Dairy Manure | 6.7 tCO₂e/cow/year |
| Landfill Gas | 50 kg CH₄/ton MSW |
| Food Waste | 37.5 kg CH₄/ton |
| Power-to-Gas CI | -950 gCO₂e/MJ |
Source: IPCC emissions factors, EPA AgSTAR guidelines, and CARB CA-GREET model calculations. Methane GWP of 25 used per IPCC AR4 standards (commonly used in LCFS calculations).
10. CNG Liquefaction Parameters
Small Scale (0.5-5 MMBtu/day)
| Capital Cost | $60,000/MMBtu/day |
| Energy Consumption | 350 kWh/MMBtu |
| Process Efficiency | 92% |
| Operating Cost | 4.5% of capex |
Medium Scale (5-50 MMBtu/day)
| Capital Cost | $45,000/MMBtu/day |
| Energy Consumption | 280 kWh/MMBtu |
| Process Efficiency | 95% |
| Operating Cost | 3.8% of capex |
Large Scale (50-500 MMBtu/day)
| Capital Cost | $32,000/MMBtu/day |
| Energy Consumption | 250 kWh/MMBtu |
| Process Efficiency | 98% |
| Operating Cost | 3.0% of capex |
Model Default (280 MMBtu/day facility)
Additional Cost
$2.3/GJ
Electricity Cost
$65/MWh
Process Efficiency
92%
Boil-off Rate
0.15%/day
11. Government Subsidies & Incentives
Federal Programs
45Z Production Tax Credit
$1.00/gallon gasoline equivalent
Clean fuel production credit (2025-2027)
Renewable Fuel Standard (RFS)
D3 RINs: ~$21/MMBtu
Cellulosic biofuel category for RNG
Investment Tax Credit (ITC)
30% of eligible project costs
One-time upfront credit
MACRS Depreciation
5-year accelerated schedule
Modified Accelerated Cost Recovery System
State Programs (West Coast)
California LCFS
$66.25/tCO₂e (current avg)
30% CI reduction target by 2030
Oregon Clean Fuels Program
$43.05/tCO₂e (current avg)
Recently resumed after litigation pause
Washington Clean Fuel Standard
$22.60/tCO₂e (current avg)
20% CI reduction by 2034 (HB 1409)
Combined Model Value
$4.2/GJ total subsidies
When subsidies toggle is enabled
9. Power-to-Gas Parameters
Process Efficiencies
| Electrolyzer Efficiency | 73% (70-75% range) |
| Methanation Efficiency | 85% (80-90% range) |
| Overall P2G Efficiency | 55% (50-60% range) |
| Capacity Factor | 90% |
Input Requirements
| Electricity | 450 kWh/GJ RNG |
| CO₂ Input | 49.5 kg/GJ RNG |
| Water Consumption | 9 m³/tonne H₂ |
| Maintenance Rate | 4% of capex/year |
Cost Structure (10 MW Electrolyzer Example)
Electrolyzer CapEx
$1,200/kW
Methanation System
$800/kW thermal
Total Project Cost
$22M (10 MW)
RNG Production
2,000 GJ/MW/year
12. Calculation Methodologies
Net Present Value (NPV)
Where CFt = Cash flow in year t, r = Discount rate (8%), t = Year
Positive NPV
Project creates value
Zero NPV
Break-even project
Negative NPV
Project destroys value
Internal Rate of Return (IRR)
Solved iteratively using Newton-Raphson method with 0.01% tolerance
IRR > 15%
Excellent returns
IRR 8-15%
Acceptable returns
IRR < 8%
Below hurdle rate
Payback Period Calculation
Simple payback period calculated as: Initial Investment / Annual Cash Flow
For uniform cash flows, includes linear interpolation for precise timing.
< 5 years
Fast payback
5-10 years
Moderate payback
> 10 years
Slow payback
Carbon Credit Calculation
Uses IPCC methodology with methane GWP of 25 (100-year timeframe, AR4 basis)
Example: 20,100 - 4,350 - 0 = 15,750 tCO₂e/year carbon credits
13. Data Sources & References
Primary Data Sources
EPA AgSTAR Program
Anaerobic digester database, biogas project economics
California Air Resources Board (CARB)
LCFS credit prices, CA-GREET model parameters
US EPA Renewable Fuel Standard
RIN pricing data, D3 cellulosic biofuel credits
Department of Energy (DOE)
Hydrogen production costs, P2G technology assessments
IPCC Guidelines
Emissions factors, methane GWP values
Industry & Academic Sources
American Biogas Association
Industry benchmarks, project development costs
National Renewable Energy Laboratory (NREL)
Technology cost databases, renewable energy analysis
International Energy Agency (IEA)
Global hydrogen outlook, P2G technology roadmaps
GTI Energy
Gas technology benchmarks, RNG market analysis
Academic Literature
Peer-reviewed studies on biogas yields, processing costs
Data Validation Approach
All baseline assumptions have been cross-referenced across multiple sources and validated against commercial project data where available. Default values represent industry medians or typical ranges for commercial-scale projects. Regional variations and technology-specific adjustments are incorporated through the Advanced Parameters interface.
Model Limitations & Disclaimers
Important Disclaimers
- • This model provides preliminary economic analysis for planning purposes only
- • Actual project economics may vary significantly based on site-specific conditions
- • Policy incentives are subject to change and may expire or be modified
- • Capital costs can vary ±50% based on project complexity and location
- • Feedstock availability and pricing are site and region-specific
Model Simplifications
- • Assumes uniform annual cash flows (no seasonality or market volatility)
- • Does not account for construction period financing or delays
- • Simplified O&M cost structure (actual costs may have different components)
- • No consideration of interconnection or pipeline transportation costs
- • Carbon intensity calculations use simplified lifecycle assessment
Recommended Next Steps
- • Conduct detailed site-specific feasibility studies
- • Obtain actual quotes for equipment and EPC costs
- • Validate feedstock availability and pricing with local sources
- • Confirm current policy incentive values and eligibility
- • Perform sensitivity analysis on key variables
RNG Economic Model Reference Documentation
Generated on September 1, 2025 | Version 1.0
For technical support or questions about these assumptions, please consult the model documentation or contact your technical advisor.