BD Project Pipeline
Track projects as they move from proposal through to operation
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Baseline Equipment
2 x 40 HP
Installed Power
80 HP
Installed Capacity
320 ICFM
Schedule
11 hrs/day, 5 days/wk
Existing System
Plant Baseline
From the CAGI data sheet or nameplate. A rough screening default is about 4 ICFM per HP.
Package bhp as a percent of nameplate HP at full load. Full-load kW = total HP x bhp factor x 0.746 / motor efficiency.
Operating Schedule
Baseline Operation
Percent of installed capacity. Replace with logged data when available.
Older fixed-speed units are commonly modulating or load/unload with limited receiver volume.
Proposed System
Upgrade Measures
kW per 100 cfm delivered, at typical operating load. Pull from the CAGI data sheet of the proposed unit.
Share of current air demand eliminated through leak repair. Verify with ultrasonic survey.
Roughly 0.5% energy per psi reduced.
Economics
Sets grid CO2 (eGRID2023) and the regional electricity price.
Applied to average kW reduction as a conservative proxy for billing demand.
Enter turnkey cost to compute simple payback.
Estimated Annual Savings
$0
0 kWh per year | 0% reduction in compressed air energy
0
Annual operating hours
0
Baseline average kW
0
Proposed average kW
n/a
Simple payback (years)
0
CO2 avoided (tons/yr)
Baseline vs. Proposed
| Parameter | Baseline | Proposed |
|---|---|---|
| Air delivered (avg cfm) | 0 | 0 |
| Average input power (kW) | 0 | 0 |
| Effective specific power (kW/100 cfm) | 0 | 0 |
| Annual energy (kWh) | 0 | 0 |
| Annual energy cost ($) | 0 | 0 |
| Annual CO2 emissions (tons) | 0 | 0 |
| Annual savings | 0 kWh | $0 |
Sanity check: total savings exceed 55% of baseline energy. That is above the typical 30 to 50% range for a full system replacement. Re-check the baseline control type and average demand assumptions before this goes into a pro forma.
Screening-level estimate for internal feasibility use. Baseline full-load input is derived as total nameplate HP x bhp factor x 0.746 / motor efficiency (defaults 110% and 91%). Part-load power curves: load/unload with adequate storage P = 25% + 75% x load; load/unload minimal storage P = 40% + 60% x load; inlet modulation P = 70% + 30% x load. Savings are sequenced (leak reduction shrinks demand first, then pressure reduction, then VSD specific power applied to net demand) to avoid double counting. Replace assumed demand profile with 2 to 4 weeks of amp logging before investment-grade analysis. Dryer, drain, and heat recovery savings not included.
System Size
500 kW-DC
Annual Production
700,000 kWh
% of Load Met
47%
Adequacy
Insufficient
Site & Electricity
Project Site
Sets grid CO2 (eGRID2023), the solar resource (yield), and the regional electricity price.
Enter roof/ground area to see the rough max system it supports.
Current Electricity Use
Proposed PV System
Sizing
Auto-fills from the state's solar resource (PVWatts, fixed-tilt). Override with a PVWatts run for the exact site.
Cost & Incentives
Auto from size + mounting. Enter a value to override.
IRA Section 48 base is 30%; can be higher with adders.
Financial Assumptions
Estimated Annual Savings (Year 1)
$0
0 kWh/yr | 0% of load met ·
0
System size (kW-DC)
$0
Net cost after ITC
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
Cost & Savings Detail
| Annual production | 0 kWh |
| Installed cost used ($/W-DC) | 0 |
| Total system cost (turnkey) | $0 |
| Federal ITC | $0 |
| Net system cost | $0 |
| Annual O&M | $0 |
| Annual energy savings (Year 1) | $0 |
| Net present value (term) | $0 |
| CO2 avoided / year | 0 tons |
Screening-level estimate. Installed cost from the REP $/W-DC matrix by system size and mounting type (override with a quote). O&M $10/kW/yr, federal ITC 30% (IRA Sec. 48 base), 25-year life, 8.5% discount, 3% energy escalation per REP System Parameters. Annual production = system size x specific yield; replace with a PVWatts run for the actual site. Grid CO2 factor from EPA eGRID2023 by state. NPV and IRR are computed on net savings (after O&M) with escalation over the analysis term. Net metering rules, interconnection cost, module degradation, and demand-charge effects are not modeled at screening level.
Heat Delivered
0 MMBtu/yr
Replacement
Condensing
Annual Savings
$0
CO2 Avoided
0 tons/yr
Existing System
Site
Sets grid CO2 (eGRID2023), regional electric/gas prices, and the ASHP climate COP.
Existing Boiler
Gas standard ~80%, condensing ~90%, oil ~85%.
1 HP = 33,475 BTU/hr (33.475 MBH).
Replacement System
Technology
Condensing 0.93, Electric 1.00. ASHP COP is set by the state's climate (2.0 cold - 3.5 hot); override as needed.
Cost & Incentives
Financial Assumptions
Estimated Total Annual Savings
$0
0% lower operating cost vs. the existing boiler
$0
Net project cost
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
Existing vs. Replacement
| Parameter | Existing | Replacement |
|---|---|---|
| Heat delivered (MMBtu/yr) | 0 | same |
| Annual energy input | 0 | 0 |
| Annual energy cost ($) | $0 | $0 |
| Annual CO2 emissions (tons) | 0 | 0 |
| Total project cost (turnkey) | $0 | |
| Annual O&M | $0 | |
| Net present value (term) | $0 | |
| Total annual savings (after O&M) | $0 | |
Screening-level estimate. Heat delivered = fuel consumed x existing efficiency. Replacement input: condensing boiler = delivered / efficiency (same fuel); electric boiler and ASHP convert to kWh at 293.07 kWh/MMBtu (ASHP divided by COP). Equipment $/HP and O&M $/MBH/yr from the REP Installed Costs table; turnkey cost adds 100% install, 20% controls, 20% soft cost, plus a $15/MBH electrical upgrade for electrification options. Efficiencies/COP from REP Technology Performance; fuel CO2 factors from System Parameters, grid CO2 from EPA eGRID2023. 20-year life, 8.5% discount, 3% escalation. NPV/IRR on net savings after O&M. Carbon-penalty (BPS) savings, dryer/steam-trap losses, and standby losses not modeled at screening level.
Cooling Load
0 ton-hrs/yr
Replacement
High-Eff Centrifugal
Annual Savings
$0
CO2 Avoided
0 tons/yr
Existing System
Site
Sets grid CO2 (eGRID2023) and the regional electricity price.
Existing Chiller Plant
Absorption is entered as kW/ton-equivalent; steam handled via COP.
Replacement System
Technology
Centrifugal 0.54, Water-cooled screw 0.64, Air-cooled 1.10, Mag-bearing 0.47.
Cost & Incentives
Financial Assumptions
Estimated Total Annual Savings
$0
0% lower cooling energy cost vs. the existing plant
$0
Net project cost
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
Existing vs. Replacement
| Parameter | Existing | Replacement |
|---|---|---|
| Cooling energy use | 0 | 0 |
| Annual cooling cost ($) | $0 | $0 |
| Annual CO2 emissions (tons) | 0 | 0 |
| Total project cost (turnkey) | $0 | |
| Annual O&M | $0 | |
| Net present value (term) | $0 | |
| Total annual savings (after O&M) | $0 | |
Screening-level estimate. Existing electric cooling energy = cooling load x kW/ton; absorption plants use cooling MMBtu / COP at the steam rate. Replacement (always electric) = cooling load x new kW/ton. Efficiencies from REP Technology Performance; equipment $/ton and O&M $/ton/yr from Installed Costs. Turnkey cost adds cooling tower ($150/ton for water-cooled), pumps/piping ($200/ton), rigging & demo ($75/ton), 35% install, 10% controls, 10% soft cost, plus a $100/ton electrical upgrade when converting from steam absorption. Grid CO2 from EPA eGRID2023; steam CO2 at 107 lb/MMBtu. 20-year life, 8.5% discount, 3% escalation. NPV/IRR on net savings after O&M. Carbon-penalty (BPS) savings and part-load/IPLV effects not modeled at screening level.
System Size
0 kW
Annual Production
0 kWh
Spark Spread
$0.000/kWh
CO2 Impact
0 tons/yr
Site Energy Profile
Site
Sets grid CO2 (eGRID2023) and regional electric + gas prices.
Electricity
CHP production should not exceed the site load.
Gas & Heating
Fuel into the existing boiler; recovered CHP heat displaces part of it.
Sets the thermal offset factor for the chosen technology.
Absorption Chiller (optional)
Leave 0 if no absorption cooling. Counted in CO2 displaced per the model.
CHP System
Technology
Cost & Incentives
Auto from the REP installed-cost table.
Auto from the technology's O&M model.
Financial Assumptions
Total Annual Energy Savings
$0
Electric + thermal savings net of CHP fuel · $0 after O&M
$0
Net project cost
n/a
Simple payback (years)
n/a
IRR over term
0
Net CO2 reduction (tons/yr)
Generation & Savings Detail
| System size / annual production | 0 kW / 0 kWh |
| Heat rate (HHV) / spark spread | 0 / $0 |
| Annual CHP fuel required | 0 MMBtu |
| Heat available / used for heating | 0 / 0 MMBtu |
| Boiler fuel displaced | 0 MMBtu |
| Annual electric savings | $0 |
| Annual thermal savings | $0 |
| Annual CHP fuel cost | -$0 |
| Annual O&M | $0 |
| Total project cost / ITC | $0 / $0 |
| Net present value (term) | $0 |
| Net annual savings (after O&M) | $0 |
Sizing check: annual CHP production exceeds the site's annual electric consumption. Reduce the number of units, unit size, or load factor so the system does not exceed the site load.
Absorption chiller check: the heat the chiller needs exceeds the CHP's available wasted heat. The model caps chiller heat at what is available; consider a smaller cooling offset.
Screening-level estimate ported from the REP Technology Screening Tool CHP sheets. Heat rate = 3.412 / electrical efficiency (HHV); production = unit kW x units x load factor x 8,760 x availability. Recoverable heat = heat output per unit x units x operating hours; boiler fuel displaced = min(heat available, heating demand during operation) / boiler efficiency x the technology's thermal offset factor. Savings = electric (production x rate) + thermal (displaced fuel x gas price) minus CHP fuel (production x heat rate x gas price). O&M models per vendor proformas (fuel cells include overhaul reserves; recip at $0.055/kWh; Mainspring at $63.95/kW-yr). Installed $/kW from the REP cost table plus 10% soft cost; ITC 30% base. Net CO2 = grid displaced (production + chiller kWh) minus CHP combustion at 117 lb/MMBtu plus boiler fuel displaced; on cleaner grids gas CHP can show a net increase. NPV/IRR on net savings after O&M over the analysis term. Standby charges, gas interconnection, and utility tariffs not modeled at screening level.
System Size
0 tons
Bores Required
0
Total Capex
$0
CO2 Avoided
0 tons/yr
Site & Heating Load
Site
Sets grid CO2 (eGRID2023) and regional electric + gas prices.
Heating Load
Peak Load Basis
Modern/insulated ~500, leaky/older ~400, passive ~1,000.
If > 0, sets the engineering peak (HP x 33,475 x 0.75); else the sqft method is used.
Bore Field & Cost
Bore Field Design
Typical 300-600; up to 800+ on tight sites.
Rule of thumb 60; good rock 70-80.
Ground-source typical 3.5-5. Also used as the geo cooling COP.
Cost & Incentives
Auto-interpolated by depth. Enter a value to override.
No = direct exchange (radiant / free cooling / low-temp process).
IRA Section 48 base is 30% for geothermal heat pumps.
Cooling & Financial
Air-cooled ~3.0, water-cooled ~5.0, DX ~3.5.
Estimated Net Annual Savings
$0
0 tons served · 0 bores · 0 ft drilled
$0
Net capex after ITC
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
Sizing & Cost Detail
| Peak heating load | 0 MMBtu/hr |
| System size | 0 tons |
| Capacity per bore | 0 MMBtu/hr |
| Bore count (peak / annual balance) | 0 / 0 |
| Bores required / grid layout | 0 |
| Total footage / area | 0 ft |
| Effective drilling cost | $0/ft |
| Ground loop cost | $0 |
| Heat pump capex | $0 |
| Total project capex / ITC | $0 / $0 |
| Annual gas savings | $0 |
| Pump electricity cost | $0 |
| Net cooling savings | $0 |
| Annual O&M (ground loop) | $0 |
| Net present value (term) | $0 |
| Net annual savings | $0 |
Panels
0
Load Met
0%
Total Cost
$0
CO2 Avoided
0 tons/yr
Site & Heating Load
Site
Sets the solar resource (DNI) and the regional gas price.
Steam uses a solar pre-heat offset (60°F→180°F of 60→250).
Existing Heating
Gas standard ~80%, condensing ~90%, oil ~85%.
System & Cost
Sizing
0 auto-sizes to the space available, capped at 100% of the load.
Phoenix panel, ~59 sq ft each. Includes install & engineering.
Incentives
IRA Section 48 base is 30%.
Financial Assumptions
Estimated Annual Energy Savings
$0
0 panels · 0% of load met ·
$0
Net cost after ITC
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
System & Savings Detail
| Solar resource (DNI) | 0 BTU/ft²/day |
| Panels (fit / for 100% load) | 0 / 0 |
| Panels installed / total area | 0 / 0 sq ft |
| Annual energy generated | 0 MMBtu |
| Fuel displaced | 0 |
| Annual heating need (useful) | 0 |
| Total turnkey cost / ITC | $0 / $0 |
| Annual O&M (1%) | $0 |
| Net annual savings (after O&M) | $0 |
| Net present value (term) | $0 |
| Annual CO2 avoided | 0 tons |
Heating Delivered
0 MMBtu/yr
Cooling Load
0 ton-hrs/yr
Annual Savings
$0
CO2 Avoided
0 tons/yr
Existing Systems
Site
Sets grid CO2, the electricity price, and the ASHP climate COP.
Existing Heating
1 HP = 33,475 BTU/hr. Sizes the ASHP heating equipment.
Existing Cooling
Choose "None" to price an ASHP that only replaces the boiler.
Steam rate, used only when the existing plant is absorption.
ASHP Replacement
Performance
Set by the state's climate; override with manufacturer data.
Air-cooled screw equivalent (1.10 kW/ton).
Cost & Incentives
Carbon Penalty (BPS)
BERDO / LL97-style performance standards.
Financial Assumptions
Estimated Total Annual Savings
$0
Heating $0 · Cooling $0 · after O&M $0
$0
Net project cost
n/a
Simple payback (years)
n/a
IRR over term
0
CO2 avoided (tons/yr)
Existing vs. ASHP
| Parameter | Existing | ASHP |
|---|---|---|
| Heating delivered (MMBtu/yr) | 0 | same |
| Heating energy input | 0 | 0 |
| Heating cost | $0 | $0 |
| Cooling energy input | 0 | 0 |
| Cooling cost | $0 | $0 |
| Annual CO2 (tons) | 0 | 0 |
| Carbon penalty | $0 | $0 |
| Equipment (heating / cooling) | $0 / $0 | |
| Total project cost (turnkey) | $0 | |
| Net project cost after rebates | $0 | |
| Annual O&M | $0 | |
| Net present value (term) | $0 | |
| Net annual savings (after O&M) | $0 | |
Monthly engineering hours — delivery split by project
FTE required per month
Development cost by category
Cumulative development cost
Monthly Forecast
Resource Stack by Stage
★ current stage
grey = already complete
Global Levers
Everything on this page feeds the forecast directly. Change a value and every other page recalculates — no code change needed.
Technology Defaults
Each project inherits these from its technology. FEL3 and Owner's engineering are a percentage of the project cost; the rest are flat fees. FEL2 is a low-to-high band the estimate case picks from. FEL3 sets the default FEED cost — a project with its own FEED cost entered on Projects & Inputs uses that instead.
Stage Library
Stage durations drive both the monthly spread and the projected close date. Construction has no fixed duration — it comes from each project's construction months.
Resource Lines
The work itself. Hours lines consume engineering time at the role's rate; Dollars lines post to a GL account. Low and high are the band the estimate case picks from — for Hours lines they are hours, for Dollars lines the amount comes from the technology defaults instead.
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