Quick answer: Evaluate commercial solar by comparing the business’s electricity bills and cash flows with and without the project. Include the full installed cost, ongoing expenses, replacements, financing and verified incentives. Report payback alongside net present value, then test whether the decision survives lower generation, lower electricity value and higher costs. A headline payback figure is not enough. This cash-flow approach is consistent with the national laboratory’s System Advisor Model financial framework. (sam.nlr.gov)
This guide uses California’s PG&E service territory for its utility-rule example and U.S. federal tax guidance checked on October 10, 2026. The worked financial example is hypothetical: its prices, production and costs are disclosed assumptions, not a project quotation or forecast.
1. Define the investment and the decision criteria
Start by identifying whose cash flow you are evaluating: the equipment owner, building owner, tenant or electricity customer. These may be different parties.
For a purchased system, prepare two views:
- Project cash flow before financing: installation expenditure, electricity savings, operating costs, replacements and applicable tax effects.
- Owner cash flow after financing: equity contributed, loan proceeds, principal and interest payments, and cash remaining for the owner.
For a lease or power purchase agreement, evaluate the customer’s avoided electricity charges against contract payments and retained obligations. The national laboratory’s third-party ownership model distinguishes these host payments from the system owner’s economics. (sam.nlr.gov)
Agree on approval criteria before reviewing proposals. Suggested questions include:
- What minimum return does the organization require?
- How much initial cash can it commit?
- Must savings exceed debt payments every year?
- How long will it control the premises?
- What happens if the building is sold or the tenant leaves?
Use several metrics rather than one. Simple payback is a screening calculation: initial investment divided by first-year net savings. Cumulative cash-flow payback accounts for changing annual cash flows. Net present value (NPV) discounts future cash flows and subtracts the initial investment. SAM provides commercial cash-flow models and supporting spreadsheets for evaluating financial metrics. (sam.nlr.gov)
For approval, request the underlying annual cash-flow table—not just the summary slide.
2. Establish the full cost, not just a dollars-per-watt price
Build a cost schedule separating installation, recurring expenses and irregular expenditure.
For procurement, request explicit treatment of:
- Modules, inverters, mounting and electrical equipment.
- Engineering, permits, installation and commissioning.
- Interconnection studies, utility upgrades and metering.
- Structural work, roof work and access arrangements.
- Taxes, contingency and project-management costs.
- Monitoring, inspections, maintenance and insurance.
- Replacement equipment, removal and end-of-project obligations.
Assign each item to a named party and flag exclusions. An excluded cost does not disappear from the business case.
Keep capacity units consistent. Commercial PV benchmarks commonly use watts DC, based on module-rated capacity, while inverter capacity is expressed in watts AC. NREL’s 2024 Annual Technology Baseline reported bottom-up commercial PV system prices of $1.99/W DC for 2022 and $1.78/W DC for 2023. These historical figures represent overnight costs, excluding construction financing; the benchmark also omits regional impacts and tends toward the lower end of observed costs. They are not 2026 quotations. (atb.nlr.gov)
Use such benchmarks to investigate differences, not to impose a universal price. Ask: “Which scope items, site conditions and pricing dates explain this proposal?”
Request a separate replacement schedule. For an inverter allowance, identify the assumed timing, equipment price, labor and warranty coverage. Do not present a modeling allowance as a prediction that a particular inverter will fail.
3. Calculate electricity value from the applicable tariff
Do not multiply total solar generation by the business’s average bill divided by consumption. Instead, calculate the electricity bill twice: once without solar and once with the proposed system and tariff.
For PG&E business customers, Solar Billing Plan implementation began in March 2026, covering specified customers who applied for interconnection after April 14, 2023, and customers whose 20-year NEM legacy period expired. Transition timing can depend on the account’s True-Up date. The plan requires an applicable time-of-use rate, and export credits vary with the timing of exports. (pge.com)
Collect the account’s:
- Current tariff and any proposed replacement tariff.
- Interval consumption data.
- Billing demand and demand-charge rules.
- Hourly solar production forecast.
- Export-credit schedule and credit-use restrictions.
- Electricity-supply arrangements, including any separate supplier.
Separate four components:
- Self-consumed generation: energy that reduces grid purchases.
- Exported generation: energy credited under the export rules.
- Demand-charge changes: differences in billed demand.
- Remaining charges: charges the project does not eliminate.
PG&E states that Solar Billing Plan export credits do not offset demand charges or non-bypassable charges. That is different from solar physically reducing billed demand; any such reduction should be demonstrated through the tariff calculation. (pge.com)
As a practical check, compare a sunny weekday, a cloudy weekday and a low-load weekend. If the model assigns all solar production the same retail value, require an explanation.
4. Separate financing, taxes and incentive eligibility
Keep financing assumptions visible: loan amount, interest rate, term, fees, repayment schedule and any balloon payment. Then calculate annual cash remaining after debt service.
For a PPA, request the starting price, escalation, payment basis, term, buyout provisions and responsibility for maintenance. SAM’s host model calculates electricity-bill reductions separately from payments to the third-party system owner. (sam.nlr.gov)
Do not automatically deduct 30% from the installation price. Section 48E has a 6% base investment credit and an increased amount subject to qualifying conditions. IRS instructions identify facilities with maximum net output below 1 MW AC as one route to the increased credit amount; other eligibility requirements still apply. (irs.gov)
Timing also matters. IRS instructions reflect termination of the credit for solar facilities placed in service after December 31, 2027, where construction begins after July 4, 2026. Have a qualified tax adviser confirm the applicable construction and placed-in-service rules for the project. (stayexempt.irs.gov)
Additional prohibited-foreign-entity and material-assistance restrictions can affect eligibility. IRS Notice 2026-15 provides interim guidance, including sourcing-related requirements relevant to projects beginning construction after December 31, 2025. Obtain documented tax review before recognizing a credit in the approval case. (irs.gov)
Show incentives in the year their financial benefit is expected to become available. Keep uncertain bonuses outside the base case. Build a separate after-tax model covering depreciation, eligible basis and the tax effect of reduced deductible electricity expenses; SAM’s commercial documentation explicitly accounts for that last effect. (samrepo.nlr.gov)
5. Work through a transparent cash-flow example
Consider a hypothetical host-owned rooftop project in PG&E territory. This is a simplified, pre-tax, unfinanced illustration—not a tariff simulation.
| Input | Illustrative assumption |
|---|---|
| Currency | U.S. dollars |
| Capacity | 100 kW DC / 80 kW AC |
| Initial installed cost | $300,000 |
| First-year generation | 150,000 kWh |
| Self-consumed / exported share | 80% / 20% |
| Avoided import energy value | $0.26/kWh |
| Export value | $0.06/kWh |
| Annual generation degradation | 0.5%, beginning in year 2 |
| Annual operating allowance | $3,000 |
| Inverter replacement allowance | $20,000 in year 15 |
| Analysis period | 25 years |
| Nominal discount rate | 8% |
| Price and operating-cost escalation | 0% |
| Debt, incentives and income-tax effects | Excluded |
| Demand-charge savings | $0 |
| Terminal salvage and removal | Both assumed $0 |
Every value is an example assumption. The electricity values are not quoted PG&E rates. Production is not a measured result. Operating costs and replacement timing require project-specific evidence.
First-year electricity benefit:
- Self-consumption: 150,000 × 80% × $0.26 = $31,200.
- Exports: 150,000 × 20% × $0.06 = $1,800.
- Total benefit: $33,000.
- Net operating cash flow: $33,000 − $3,000 = $30,000.
The headline simple payback is therefore:
$300,000 ÷ $30,000 = 10 years.
For each operating year, the illustration uses:
Cash flow = $33,000 × 0.995^(year − 1) − $3,000 − replacement expenditure
| Year | Illustrative cash flow |
|---|---|
| 0 | −$300,000 |
| 1 | $30,000 |
| 15, including replacement | $7,764 |
| 25 | $26,260 |
With degradation included, cumulative undiscounted cash flow first becomes positive in year 11. However, discounting all year-end operating cash flows at 8% gives a 25-year NPV of approximately −$106.
The lesson: a ten-year simple payback can coexist with a project that only just reaches a chosen discounted-return threshold.
These results assume a constant self-consumption share and constant unit values. A real approval model should recalculate interval imports, exports and bills as output and business consumption change.
6. Test which assumptions can reverse the decision
Change one input at a time before combining risks. The table below uses the example’s cash flows; results are rounded.
| Scenario | First-year net cash flow | Simple payback | 25-year NPV |
|---|---|---|---|
| Base case | $30,000 | 10.0 years | −$106 |
| Capital cost 20% lower | $30,000 | 8.0 years | +$59,894 |
| Capital cost 20% higher | $30,000 | 12.0 years | −$60,106 |
| Import and export values 20% lower | $23,400 | 12.8 years | −$67,751 |
| Import and export values 20% higher | $36,600 | 8.2 years | +$67,538 |
| Generation 10% lower | $26,700 | 11.2 years | −$33,929 |
| Generation 10% higher | $33,300 | 9.0 years | +$33,716 |
Here, electricity-value changes affect both assumed unit values equally. Generation changes retain the 80/20 split. Operating and replacement costs remain unchanged. Those simplifications isolate the sensitivities; they do not reproduce an actual utility bill.
Next, combine plausible downside conditions: higher installation cost, lower output, delayed operation and reduced credit eligibility. Also test roof-related expenditure, replacement timing and changes in business occupancy.
Have finance set the discount rate rather than accept an unexplained software default. Match nominal cash flows with a nominal discount rate and real cash flows with a real rate. SAM documents the relationship between inflation, real discount rates and nominal discount rates. (samrepo.nlr.gov)
7. Check the model before approving expenditure
Use this final review checklist:
- Scope: Are roof work, utility upgrades and exclusions included or explicitly unresolved?
- Units: Are proposal prices compared on the same DC or AC basis?
- Electricity value: Are self-consumption, exports and demand charges calculated separately?
- Generation: Are forecast inputs, losses, shading and degradation documented?
- Costs: Are maintenance and replacement allowances supported by quotations or clearly labeled assumptions?
- Financing: Are principal, interest, fees and cash shortfalls visible?
- Taxes: Has an adviser confirmed eligibility and benefit timing?
- Terminal year: Are removal obligations and salvage assumptions explicit?
- Arithmetic: Can another reviewer reproduce the headline results?
Watch for double-counted incentives, retail-rate valuation of every exported kWh, positive salvage without evidence and omitted replacement costs.
For unresolved inputs, assign a verification owner: facilities for roof and operating constraints, the project designer for generation, procurement for scope, finance for funding, and a tax adviser for incentives.
Approve against a documented base case and downside case—not an attractive payback claim. Any performance guarantee should be evaluated through its contract terms, exclusions and remedies, separately from the financial forecast.