How to Evaluate Commercial Solar ROI in South Carolina

Commercial solar ROI in South Carolina cannot be verified from system size, average electricity price, a tax-credit percentage, or one payback number. It must be reconstructed from the facility’s load at each billing interval, the actual tariff, the proposed array’s time-matched production, the complete project and lifecycle cost, the owner and financing structure, and tax benefits the business’s advisers confirm it can use.

A useful model shows every year, formula, source, and uncertainty. It also answers a more important question than “Does solar save money?”: does this project clear the company’s capital-allocation threshold after downside risks, and does it do so within the period the business controls the roof, site, account, and asset?

Commercial solar ROI at a glance

Start with four linked files rather than a summary slide.

File	What it must establish	Common shortcut to reject
Load and bill	Interval consumption, actual tariff, operating schedule, anomalies, future loads, baseline bill	Annual kWh multiplied by an average rate
Production	Hourly or subhourly solar output, layout, weather, losses, availability, degradation, curtailment	Nameplate kW multiplied by a generic yield
Cash flow	CAPEX, utility value, O&M, replacements, insurance, roof/site obligations, taxes, financing, terminal costs	Contract price minus all projected credits in year zero
Decision	Perspective, horizon, nominal/real convention, discount rate, NPV, IRR, payback, sensitivity	One “ROI” percentage with no definition

The files should reconcile. Interval solar production flows into the utility-bill model. The bill-model difference flows into the annual cash flow. Taxes and financing alter the cash flow only for the entity that owns those rights and obligations. Financial metrics are calculated from that same disclosed series—not from a second spreadsheet with different assumptions.

Define whose return you are measuring

A commercial property can involve several different parties:

• the business occupying the facility;
• the electric account holder;
• the building or land owner;
• the solar-system owner;
• a tenant purchasing energy;
• a lender or third-party owner; and
• a parent company or tax-equity participant.

These parties do not necessarily receive the same value. The operating business may avoid utility purchases. A landlord may own the roof and solar asset. A third party may claim federal tax attributes and sell electricity to the host. A lender receives interest and principal. A tenant may move before the array’s technical life ends.

Name the perspective at the top of every output. At minimum, distinguish:

• Unlevered project return: performance of the solar asset before financing cash flows.
• Levered equity return: cash flow to the owner after debt proceeds, fees, interest, principal, reserves, and other financing obligations.
• Host/customer case: utility-bill change minus lease, power-purchase agreement, or other contract payments and host obligations.
• Property-owner case: roof/site, lease, transfer, insurance, restoration, rent, and property-value consequences to the owner.

A project can have a positive unlevered NPV but an unattractive equity return under expensive debt. A host can benefit from a power-purchase agreement while owning no asset and claiming no owned-system ROI. A landlord can accept a project that works for a tenant but creates roof or sale constraints. Do not combine tax benefits received by one party with utility value received by another unless the agreements transfer that value and the model shows the transfer.

Build the no-solar baseline before modeling savings

Solar value is the difference between two bills and two business cash-flow paths: a defensible future without the project and the same future with it. If the no-solar baseline is wrong, every return metric inherits the error.

Collect at least 12 complete months of bills plus the best interval data available from the meter or utility portal. More history is useful when the facility has seasonal production, shutdowns, tenant changes, abnormal weather, construction, or a recent operational change.

Document:

• every account and meter affected by the project;
• serving utility, account class, tariff, riders, effective dates, and contract demand;
• billed energy, demand, power-factor/reactive, fixed, minimum, standby, fuel, tax, and other components where applicable;
• interval resolution and missing or estimated periods;
• operating days, shifts, holidays, shutdowns, and production schedules;
• major loads and whether their operation is discretionary;
• billing anomalies, meter changes, outages, vacancies, or temporary loads; and
• committed efficiency, electrification, fleet, production, occupancy, or tenant changes.

Do not infer the provider or rate from a city. A South Carolina address can sit in a utility, cooperative, or municipal territory that differs from a nearby property. Start with the bill and use the South Carolina utility directory to locate the provider’s current documents.

Test the baseline against actual bills

Before inserting solar, run the current load through the proposed tariff engine. The calculated monthly bills should reconcile reasonably with actual bills after known taxes, riders, adjustments, and billing-period dates are accounted for. Large unexplained differences mean the model is not ready for a return calculation.

Ask for a month-by-month bridge:

Check	What should reconcile
Energy	Interval or monthly kWh to billed kWh
Demand	Interval maximum under the tariff rule to billed demand
Rate periods	Interval timestamps to on/off/other time buckets
Fixed and riders	Published terms to bill line items
Baseline total	Modeled no-solar bill to actual bill

Do not “calibrate” the model by applying an unexplained savings factor until totals match. Find the actual cause: timestamps, daylight saving time, interval gaps, demand ratchets, taxes, riders, billing dates, rate changes, power factor, multiple meters, or another rule.

Keep current and future load cases separate

Create a current-operations case and a committed-change case. A future production line, heat pump, EV fleet, refrigeration upgrade, efficiency project, vacancy, or extended shift can change both annual energy and the timing that determines self-consumption and demand.

Use equipment studies, measured pilot data, engineering estimates, schedules, and management-approved plans. Avoid a blanket annual growth percentage that hides several unrelated changes. If a future load is speculative, keep it as a sensitivity rather than the base case.

Calculate self-consumption, exports, and imports interval by interval

For each interval i:

Self-used solarᵢ = minimum(facility loadᵢ, solar productionᵢ)

Exportᵢ = maximum(solar productionᵢ − facility loadᵢ, 0)

Grid importᵢ = maximum(facility loadᵢ − solar productionᵢ, 0)

This is why annual totals are insufficient. A building can consume more electricity over a year than the array produces and still export at midday on low-load days. Another facility can have a modest annual load but use nearly all generation onsite because its operating hours and production align.

Value each category under the current tariff and approved solar program:

1. Avoided imported energy: apply the energy charge for the interval’s time, season, block, rider, or other rule.
2. Exported energy: apply the actual export credit/payment and true-up treatment, not the retail import rate unless the controlling terms say so.
3. Demand impact: recalculate monthly billing demand under the tariff’s definition.
4. Fixed and remaining charges: preserve charges solar does not change and add any program, meter, standby, or administrative charge.

The year-one utility value is the modeled no-solar bill minus the modeled solar bill. It is not “solar production × blended cents per kWh.”

The U.S. Energy Information Administration publishes state and sector sales, revenue, and average-price history. EIA also explains that its average retail revenue per kilowatt-hour is a proxy, not a collected customer tariff. Use EIA data for context or a documented sensitivity—not as the facility’s avoided-energy rate.

Model demand charges from the actual tariff rule

Demand charges are measured in power, not annual energy. Depending on the tariff, billed demand may involve an interval maximum, a time-specific peak, a seasonal rule, a minimum, contract demand, power factor, or a ratchet linked to another month. Solar only changes a demand charge when its production changes the load during the intervals the tariff uses.

NREL’s commercial PV demand-charge guide explains why the result depends on facility load, solar production, and demand-charge design. A strong annual production model can leave a monthly peak largely unchanged if the peak occurs after solar output falls, during a cloud event, on a shutdown-restart day, or when an uncontrolled process starts.

For every month, retain:

• baseline interval and billed demand;
• solar-case interval and billed demand;
• date/time and rate window of each determining event;
• solar production and facility load at those intervals;
• ratchet, minimum, contract, or power-factor adjustment; and
• resulting demand-charge difference.

Do not apply one demand-reduction percentage to all months. Do not carry the best month through the project life. If the business is considering storage or load control, create a separate incremental case with its own dispatch rules, power/energy constraints, degradation, CAPEX, O&M, replacement, incentives, warranty, and operational value. Sunburst’s battery-storage service can evaluate a defined use case, but storage should not be inserted merely to improve a solar return chart.

Use the current utility program, then stress it

South Carolina commercial solar programs and retail tariffs are not interchangeable. A single provider can offer multiple structures with different metering, export, sizing, charges, time periods, and eligibility.

Dominion Energy South Carolina’s current business solar information distinguishes Solar Choice, Offset Only, and Buy All/Sell All paths, while its rates and tariffs hub contains the underlying nonresidential rates and riders. Those pathways value imports and exports differently. A Dominion example cannot be applied to a Duke, Santee Cooper, cooperative, or municipal account.

Santee Cooper’s Solar for Business page and 2026 manual tell customers to obtain the utility’s integration and rate facts and set program-period, eligibility, system, application, and funding conditions. Program money should enter cash flow only after the business has written confirmation of eligibility and reservation where required.

Treat renewable energy certificates and other environmental attributes as a separate ledger. The model should identify who owns them, whether a utility incentive or contract transfers them, who may sell or retire them, the evidence for any price, transaction and reporting costs, and whether the business may still make the environmental claim. For example, Santee Cooper’s 2026 Solar Business Program manual says Santee Cooper retains the RECs associated with participating customer installations in exchange for program rebates. Do not count both REC revenue and retained environmental value unless the governing documents support both.

Attach the exact current tariff and solar-program documents used by the model. Record their effective dates, the model’s “as of” date, and pending rate cases or announced changes known to the team.

Do not disguise rate escalation as certainty

Create at least three tariff views:

• Flat-real or current-dollar case: holds real tariff value constant to show economics without speculative growth.
• Finance-approved planning case: uses the company’s approved energy-price and general inflation assumptions, with their source and date.
• Tariff downside: tests weaker avoided-energy, export, or demand value and possible additional charges.

Keep energy escalation, demand escalation, export changes, fixed charges, and general O&M inflation separate. A utility’s historical increases do not prove the future schedule. Do not use an aggressive escalator simply because it shortens payback.

Use nominal cash flows with a nominal discount rate, or real cash flows with a real discount rate. Mixing inflated future benefits with a real discount rate overstates present value. NREL’s commercial financial-model guidance emphasizes that NPV is sensitive to the discount-rate input and relates nominal rate, real rate, and inflation explicitly.

Build production from a site-specific time series

The production file should be independently reviewable. Record:

• address/weather source and model version;
• roof, ground, or carport planes, tilt, orientation, shade, setbacks, and usable area;
• module, inverter, racking and electrical design;
• kW DC, kW AC, DC-to-AC relationship, clipping, curtailment, and utility limits;
• temperature, wiring, mismatch, soiling, shading and other loss assumptions;
• modeled hourly or subhourly output and monthly/year-one totals;
• availability/downtime assumption;
• interannual weather range;
• degradation method by year; and
• design changes between proposal and as-built model.

NREL’s PVWatts V8 calculator is useful for a transparent reasonableness check and describes an interannual range derived from historical weather analysis for its defined configuration. It is not a production guarantee and does not know every roof obstruction, outage, curtailment, equipment mismatch, or maintenance event.

Separate weather, degradation, and availability

These are different risks:

• Weather variability changes solar resource from one year to another.
• Degradation changes equipment output over time under the chosen model.
• Availability reflects time the system cannot produce because of faults, grid events, maintenance, communications/control issues, or other downtime.

Do not bury all three in one loss factor. Use proposal/manufacturer/model evidence for the degradation schedule and a downside case rather than a universal annual percentage. A module performance warranty does not cover every production loss, and it does not automatically reimburse tariff-based bill value.

Translate a production guarantee carefully

If a bidder offers a performance guarantee, capture:

• guaranteed quantity and measurement point;
• weather normalization;
• degradation schedule;
• excluded grid, curtailment, shade, soiling, force-majeure, access, or owner-caused events;
• monitoring/data requirements;
• claim threshold, timing, formula, and cap;
• payment or repair remedy; and
• counterparty responsible after equipment substitution or ownership change.

Then model the remedy as the contract actually provides. Do not replace the downside-production case with the guarantee label.

Include every lifecycle cost, not only installation price

Begin with a complete, same-scope capital amount. The commercial solar cost guide covers engineering, roof/structure, electrical, civil, access, equipment, permitting, interconnection, construction constraints, allowances, and exclusions in more detail. The ROI workbook should reconcile its initial cash flow to the approved scope and change-order process.

Separate costs into four groups.

Initial and development costs

Include the actual responsibility for feasibility studies, design/engineering, permitting, utility studies, equipment, labor, electrical/service/switchgear, roof work, civil work, access/rigging, bonding, commissioning, owner oversight, legal/tax review, lender costs, reserves, and other approved project items. Identify refundable, nonrefundable, capitalized, expensed, financed, owner-provided, provisional, and excluded amounts.

Do not subtract tax benefits or program money from contract price and call the result “net CAPEX” unless the cash flow also preserves when and to whom those benefits are received. Keep gross project investment, cash incentives, tax cash effects, and financing proceeds on separate rows.

Recurring operating costs

Depending on the actual project, rows may include:

• monitoring, communications, hosting or data services;
• inspection, testing and preventive maintenance;
• cleaning or vegetation work justified by the site;
• roof/site access and safety requirements;
• property/roof lease or easement payments;
• administration, accounting, reporting, REC/program, legal, security or compliance work;
• insurance premium changes confirmed by the carrier or broker; and
• property or other taxes confirmed by the business’s adviser.

No universal O&M rate belongs in the article. DOE’s current PV operation and maintenance lifecycle guidance shows that monitoring, reporting, inspection and maintenance scope depends on the system. Obtain an actual service plan and identify what the owner retains.

Corrective and replacement costs

Model warranty coverage and owner exposure separately. A manufacturer product warranty, performance warranty, installer workmanship obligation, roof-penetration obligation, monitoring service, and labor coverage are different promises. Review the Sunburst warranty overview as a question framework, then use the signed project terms.

Ask which party pays for diagnosis, travel, access/rigging, removal, shipping, replacement equipment, labor, recommissioning, monitoring migration, roof work, and lost production. Model evidence-based expected/reserve cases for inverters, transformers, switchgear, communications, sensors, roofing interfaces, and other material components. Do not insert an internet replacement year or price as a fact.

Terminal and transaction costs

The last modeled year may include sale, transfer, buyout, removal, restoration, roof replacement, disposal, recycling, decommissioning, residual obligations, or salvage. A zero terminal value is an assumption. A positive salvage value is also an assumption and may be taxable or offset by removal costs.

If the property may be sold, identify lender consent, system ownership, tax-credit recapture review, utility transfer, roof warranty, lease/PPA assignment, buyer underwriting, and removal obligations. The model should not assume a buyer pays the remaining forecast value dollar for dollar.

Match the financial horizon to the roof, lease, and business plan

The longest equipment warranty should not automatically set the analysis period. The useful business horizon may be constrained by:

• remaining roof life and reroof timing;
• building/site ownership and planned disposition;
• tenant lease, renewal rights and utility-account control;
• lender or mortgage consent;
• PPA, equipment lease, roof lease or service term;
• operational relocation, closure, expansion, demolition or redevelopment;
• utility program term and tariff uncertainty; and
• owner ability to transfer, buy out, remove or decommission the project.

For an owner-occupied building expected to remain in service, a longer analysis may be supportable. For a tenant with a shorter lease, value after the enforceable occupancy period belongs in a renewal/transfer case, not automatically in the base case. For an aging roof, include replacement before solar or a detach/reset and downtime case.

Ask the property insurer or broker to review the design and contracts. Record incremental premium, deductible, coverage, business interruption, wind/hail/flood, roof, fire, equipment-breakdown, liability, lender, third-party-owner, and claim responsibilities that apply. Do not assume insurance is unchanged or use a generic percentage.

The Department of Energy’s Better Buildings program maintains a commercial rooftop solar FAQ focused on roof mounting and warranty questions. It is an older planning resource, so the current roof manufacturer, roofer, engineer, insurer, landlord, lease, and project contract control the specific decision.

Put ownership and financing into the right cash flow

Financing changes cash timing and risk; it does not change how much electricity the system produces.

All-equity ownership

The owner funds project costs and receives the applicable utility value, tax cash effects, operating costs, replacements, and terminal outcomes. Report unlevered project metrics and owner after-tax metrics with the tax assumptions identified.

Debt-financed ownership

Add debt draws, lender fees, interest, principal, reserves, balloon/refinancing or prepayment assumptions, and any tax treatment confirmed by advisers. Report both unlevered project return and levered equity return. A smaller initial equity check can raise modeled equity IRR even when financing increases total cash paid and downside risk.

Lease or power-purchase agreement

The host generally models the utility bill plus contract payments, escalation, minimum purchases, buyout/transfer/default/roof obligations, and remaining charges. The third-party owner models asset ownership, taxes, financing and operating costs. Do not put the owner’s tax benefits into the host’s cash flow unless the contract economically transfers them.

This article uses financing only as a model input. The product choice still needs separate review of total payments, collateral, covenants, security interests, property rights, transfer, buyout, default, end-of-term, and disclosure terms.

Keep financing and operating escalation separate

A PPA or lease escalator is a contract payment assumption. Utility-rate escalation is a tariff forecast. O&M inflation is an expense forecast. Debt interest is a financing term. Combining them into one percentage makes the model impossible to audit and can hide the case where contract payments grow faster than avoided utility value.

Model current 2026 commercial tax treatment as timed cash flow

This section is general modeling information, not tax, legal, or accounting advice. Commercial solar tax treatment changed recently and depends on owner, project, labor, equipment/source, construction, placed-in-service, basis, transfer, tax capacity, business structure, and other facts. A qualified tax professional should approve the model inputs and evidence before the investment decision.

Federal Clean Electricity Investment Credit: do not assume 30%

The IRS’s general Clean Electricity Investment Credit page, last reviewed January 5, 2026, describes Section 48E with a 6% base amount and an increase up to 30% when applicable prevailing-wage and registered-apprenticeship requirements are met. It also describes possible bonus, transfer, or elective-payment pathways. None is automatic.

For solar, that page must be read with the newer statutory termination schedule and IRS Notice 2025-42. The notice says applicable solar facilities beginning construction after July 4, 2026 are subject to credit termination when placed in service after December 31, 2027. It supplies detailed beginning-of-construction and continuity rules.

As of August 10, 2026, a new proposal should not insert a federal percentage based on an old “30% through 2032” schedule. The tax adviser should confirm:

• taxpayer/system owner and credit recipient;
• qualified facility/property and eligible basis;
• base versus increased amount and labor requirements;
• any bonus and supporting evidence;
• construction-start facts under current guidance;
• placed-in-service schedule and delay case;
• current restricted-entity/material rules where relevant;
• transfer or elective-payment availability, registration, costs and timing;
• usable tax capacity and carryforward/timing;
• tax-credit basis reduction; and
• disposition, change-of-use, recapture and record-retention exposure.

Create at least a confirmed/adviser case and a zero-or-delayed-benefit case. A tax-credit schedule risk should not be hidden inside the construction contingency.

MACRS and bonus depreciation are deductions, not rebates

The IRS says owners of certain qualified clean-energy facilities and property may be eligible for five-year MACRS cost recovery. IRS Notice 2026-6 provides interim rules for a 100% additional first-year depreciation percentage for qualifying property acquired and placed in service after January 19, 2025, subject to its qualification, acquisition, placed-in-service and election rules.

Do not enter contract price as both a federal credit basis and full depreciation basis. The current Form 3468 instructions state that the energy-property basis is reduced by 50% of the energy credit determined and describe possible recapture events. The tax adviser should provide the eligible/depreciable basis, schedule, election, placed-in-service year, tax rate, tax capacity, state interaction, and actual annual tax cash effect.

A depreciation deduction reduces taxable income under applicable rules. Its cash value is not equal to the deduction, may not be usable on the modeled schedule, and is not money paid by the installer. Keep deduction and tax cash effect on different rows.

South Carolina’s credit can be slow relative to project size

South Carolina Department of Revenue Revenue Ruling 24-2 says the Solar Energy Credit equals 25% of qualifying purchase and installation costs at a taxpayer-owned facility in South Carolina. But the amount usable in a tax year is limited to the lesser of $3,500 for each facility or 50% of South Carolina income-tax liability. It is nonrefundable, and unused credit may carry forward for up to 10 years.

The ruling also says:

• completion of installation controls when the credit is claimed under its examples;
• the customer does not receive it for a leased system because the customer did not purchase the system;
• the lessor generally does not qualify when it does not own the facility;
• the credit is not transferable;
• financing interest, insurance, origination fees and extended warranties are excluded from qualifying cost; and
• South Carolina basis is not reduced by this state credit under the cited statute.

The cash-flow model should show the state credit generated, annual credit used, tax-liability constraint, remaining carryforward, and expiration risk separately. Do not subtract the full calculated credit from initial cost. A business with a large project can generate more credit than it uses within the modeled horizon.

Account for the tax effect of avoided electricity expense

Commercial utility purchases are generally business operating expenses under the entity’s tax facts. When solar reduces that expense, taxable income may change. NREL’s commercial SAM model explicitly reduces project cash flow for the federal/state income-tax effect of avoided deductible electricity purchases.

Ask the tax adviser whether and how this applies to the modeled entity, along with deductibility of O&M, insurance, interest, lease/PPA payments and other expenses. A proposal that adds credits and depreciation but ignores the tax effect of expense savings can overstate after-tax value.

Calculate NPV, IRR, payback, and ROI from one cash-flow series

NREL’s System Advisor Model calculates commercial cash flow from electricity value, installation, O&M, taxes, incentives, debt and other inputs. Whether the team uses SAM, another model, or its own workbook, metrics should come from the disclosed annual series.

Metric	What it answers	Important limitation
Net present value (NPV)	What are the modeled future net cash flows worth today at the approved discount rate?	Changes with horizon, cash-flow convention, discount rate, terminal value and every underlying assumption
Internal rate of return (IRR)	Which discount rate makes NPV zero for this defined cash-flow series?	Can mislead with unusual/multiple sign changes and cannot replace scale or NPV
Simple payback	When does cumulative undiscounted cash flow recover the defined initial investment/equity?	Ignores time value and value/cost after the cutoff
Discounted payback	When does cumulative discounted cash flow recover the defined investment?	Still ignores later value and depends on discount rate
ROI percentage	A defined net benefit divided by a defined investment over a defined period	The label is ambiguous unless numerator, denominator, period and perspective are stated

Net present value

NPV = sum of each year’s net cash flow discounted to today at the approved rate

A positive modeled NPV means the modeled discounted benefits exceed modeled costs at that rate and horizon. It is not a guaranteed profit. The business’s finance team—not a solar calculator default—should choose the rate and confirm whether cash flows and discount rate are nominal or real, pre-tax or after-tax.

Use NPV to compare mutually exclusive designs at the same perspective and convention. A smaller system can have a higher IRR but lower NPV; a larger system may add value until low-value exports or marginal construction costs reduce the next increment’s return.

Internal rate of return

IRR is the discount rate that makes the series’ NPV zero. Compare it with the company’s approved hurdle rate only when both use the same risk, tax, financing and cash-flow perspective. Report unlevered and levered IRR separately.

If the cash-flow series changes sign more than once because of large replacements, roof work, buyout or decommissioning, IRR can have multiple or misleading solutions. Show NPV over a range of discount rates and keep the full cash flow visible.

Payback

State exactly what “paid back” means. Is the starting amount gross CAPEX, net initial cash after a confirmed rebate, or owner equity after debt proceeds? Does annual cash include tax benefits, financing, replacements and terminal obligations? Is the crossing interpolated within a year?

Simple payback is a liquidity/risk screen, not a complete return measure. A project can cross payback and then face a major replacement, roof event, or escalating contract obligation. Another project can miss a short payback target but still have positive NPV over a controlled long horizon.

ROI percentage

Do not accept “15% ROI” without a formula. It could mean first-year utility benefit divided by project cost, average accounting return, total undiscounted benefit over cost, or IRR. Those are not equivalent. Prefer NPV, IRR and payback together, then include a defined ROI ratio only if the business uses one consistently.

Build a year-by-year cash-flow bridge

Each year should reconcile from operational value to owner cash. A useful structure is:

Utility value

• avoided imported energy
• export credits or payments
• defensible demand-charge difference
• confirmed program or attribute revenue
• unchanged/new utility charges

Operating cash

• monitoring and routine O&M
• insurance and property/site expenses
• corrective maintenance and downtime
• component and roof events
• administration/reporting/contract costs

Tax cash effects

• federal credit/transfer/elective-pay net receipt actually available
• depreciation tax effect
• South Carolina credit actually used
• tax effect of avoided/added deductible expenses
• recapture, sale or terminal tax effects if applicable

Financing and ownership cash

• equity investment and debt proceeds
• fees, interest, principal and reserves
• lease/PPA payments, escalators and buyout/residual obligations
• terminal sale, transfer, removal or decommissioning

The resulting net cash flow feeds every metric. Keep raw source data, calculation tabs, assumption register, change log and output dashboard. Locked formulas are fine for control, but reviewers need a viewable formula or calculation specification.

Six reconciliation tests

1. Energy balance: at every interval, solar equals self-use plus export, subject to explicitly modeled storage/curtailment/loss boundaries.
2. Bill baseline: no-solar modeled bills reconcile to actual bills.
3. Bill bridge: energy, export, demand and fixed-charge changes explain the solar-case difference.
4. Production bridge: hourly/monthly output sums to year one; future years reconcile to degradation/availability assumptions.
5. Cash bridge: every model benefit/cost maps to a bill, quote, contract, tax-adviser schedule, insurer input or documented assumption.
6. Metric bridge: NPV, IRR and payback are calculated from the same labeled net cash-flow series.

Require sensitivity, not one optimistic forecast

A decision-ready model includes base, downside and management/upside cases. The base is not the salesperson’s preferred case; it is the business-approved expected set of inputs. The downside should combine adverse factors that can plausibly occur together.

Driver	Base evidence	Downside test
Load/self-consumption	Interval history and committed plan	Lower daytime operation, shutdown, vacancy or tenant/load change
Tariff/export	Current tariff and approved program	Lower export/avoided value, new/remaining charges, changed demand treatment
Production	Site model and equipment/design	Poor weather sequence, downtime, shade/soiling change, lower availability, more degradation
Demand	Monthly interval calculation	Peak shifts outside solar hours or coincides with low production
CAPEX/schedule	Complete approved scope	Allowance/change order, service/interconnection/roof/civil event, delayed operation
O&M/replacement	Service/warranty/owner evidence	Uncovered labor/access/shipping, monitoring loss, major component event
Federal tax	Tax-adviser schedule	Zero/lower benefit, delay beyond required date, lower usable basis, transfer cost, recapture review
South Carolina tax	Tax-liability/use schedule	Slower use or carryforward expiration
Financing	Term sheet/contract	Higher cost, draw delay, refinance/balloon/buyout or covenant pressure
Business horizon	Board-approved site plan	Early sale, roof replacement, tenant nonrenewal, relocation or closure

Report each case’s NPV, IRR, payback, minimum annual cash position, and any metric that is not reached or not meaningful. Do not force a payback year when cumulative cash never crosses zero inside the horizon.

Find the break-even assumptions

Sensitivity is more useful when it identifies thresholds:

• What minimum self-consumption keeps NPV at or above zero?
• How much demand reduction is actually required to clear the hurdle rate?
• Which CAPEX or change-order amount eliminates the margin?
• How late can placed-in-service occur before the tax case changes?
• How many years must the business control the site?
• Which production/availability level triggers a contract remedy?
• At what PPA/lease escalation does host value disappear under a conservative tariff?

These are decision limits, not predictions. They tell the business what to verify, negotiate, monitor, or make a condition precedent.

Compare the model with the business’s alternative uses of capital

A positive solar NPV does not automatically make solar the best next investment. Compare it with efficiency, roof replacement, process equipment, inventory, debt reduction, site expansion, resilience work, or other projects using the company’s consistent risk and tax conventions.

Also consider non-energy objectives separately:

• resilience or outage-cost mitigation;
• emissions or reporting targets;
• customer/tenant commitments;
• covered parking or shade from a carport;
• roof/site improvements;
• energy-price exposure; and
• operational learning or future electrification.

Quantify these only when there is a defensible method and do not use them to fill a financial gap by assertion. A resilience benefit needs outage probability, consequence, load, architecture and performance assumptions. A marketing benefit needs an approved business case. A carbon value needs ownership and accounting rules. Keep financial and strategic scorecards visible rather than blending everything into “savings.”

Decide: proceed, redesign, stage, or pause

Proceed to final diligence

This path can fit when baseline bills reconcile, interval self-consumption/export/demand are auditable, project scope is sufficiently defined, tax/ownership assumptions are adviser-confirmed, roof/site control covers the horizon, and the downside case remains within the company’s approved risk boundary.

Redesign the array or operating plan

This can fit when marginal panels export at low value, a demand assumption is weak, roof/site work makes one area uneconomic, a smaller system increases value per invested dollar, load shifting improves alignment, or a future load changes the right design. Compare increments rather than only whole-project averages.

Stage the decision

This can fit when roof work, service upgrades, efficiency, a new production line, tenant renewal, interval-metering availability, or a financing/tax decision is pending. Preserve a clearly defined first stage and avoid claiming the later stage’s benefits now.

Pause

Pause when the model relies on average rates, unsupported self-consumption, automatic demand savings, a blanket federal percentage, unusable state credit, zero O&M, an unowned roof/lease horizon, unresolved interconnection scope, a hidden financing escalator, or a return below the business’s hurdle rate. “Not yet” is a valid feasibility result.

What to request from a commercial solar assessment

Ask for a portable model rather than only a PDF chart:

• source bills, interval file, tariff and solar-program documents;
• no-solar bill reconciliation and solar bill bridge;
• hourly/monthly production file and assumption register;
• complete capital, recurring, periodic and terminal cost schedule;
• ownership and financing cash-flow perspectives;
• tax-adviser-confirmed input schedule with an unconfirmed/zero case;
• annual cash flow and NPV/IRR/payback formulas;
• base, downside, and alternative-design sensitivities;
• model version, source dates and change log; and
• named unresolved items, responsible party, decision date and model impact.

Sunburst’s commercial solar service supports load, demand, tariff, site and project feasibility review for South Carolina facilities. If your team can provide bills, interval data, the current tariff, operating/load plans, site and roof records, lease/ownership horizon, proposal scope, insurance input, financing assumptions, tax-adviser criteria and hurdle rate, you can request a commercial solar assessment built around the decisions your business actually needs to make.

Sunburst supplies those inputs in a form your finance team can re-run: the production time series and its assumptions, the tariff logic including demand components, the lifecycle cost schedule, the tax treatment as timed cash flow, and stated sensitivities. We would rather present a defensible range than an attractive point estimate, and we do not use guaranteed-savings language.

That discipline comes from doing the construction as well as the modeling. Our commercial solar service carries projects from feasibility through interconnection and closeout in Dominion, Duke, Santee Cooper and co-op territory, so the operating assumptions in the model are the ones we have to meet on site.

If demand charges dominate your bill, read the demand-charge guide alongside this one, and consider whether storage belongs in the scope. Request a commercial assessment to have the model built from your meter data — or see commercial solar in your city.

Red flags in a commercial solar ROI model

Slow down when a model:

• presents a statewide “typical” ROI, IRR, payback, cost, or savings figure;
• uses an EIA/state average or total bill divided by kWh as the tariff;
• values every solar kWh at the retail import rate;
• assumes a fixed self-consumption percentage without interval matching;
• claims solar eliminates demand charges or uses one best-month reduction every month;
• escalates utility rates aggressively with no flat/downside case;
• models annual solar kWh but no hourly/monthly production or weather range;
• uses one combined loss factor for weather, degradation and downtime;
• sets O&M, insurance, replacements, roof work, or terminal obligations to zero without evidence;
• assumes warranty coverage pays all labor, shipping, access and lost production;
• subtracts tax credits, depreciation and financing proceeds from price as if they were the same day-one cash;
• assumes a 30% federal credit in August 2026 without current schedule and labor/tax review;
• counts the full South Carolina calculated credit in year one despite annual/liability limits;
• gives the host tax benefits owned by a lessor/PPA provider;
• reports equity IRR without unlevered project return or total financing cash flows;
• uses a module warranty term as the horizon despite a shorter roof, tenant or site-control period;
• reports “ROI” without numerator, denominator, period and perspective; or
• cannot provide the annual cash-flow series behind the summary.

Frequently asked questions

What is a good commercial solar ROI in South Carolina?

There is no responsible universal percentage. Define the business perspective, cash-flow horizon, after-tax/pre-tax convention and metric, then compare NPV and IRR with the company’s approved discount/hurdle rates. Use payback as a secondary liquidity screen and test a combined downside case.

How do you calculate commercial solar payback?

Build annual net cash flow from tariff-based bill value, lifecycle costs, tax cash effects and financing for the named entity. Simple payback occurs when cumulative undiscounted cash flow recovers the defined investment or equity. Discounted payback applies the approved discount rate. State every included and excluded row.

Is commercial solar ROI the same as payback?

No. Payback is a time to recover a defined outlay. ROI is an ambiguous percentage unless its formula and period are stated. NPV expresses present value at a discount rate; IRR is the rate that sets NPV to zero. A decision should review the full cash flow and several metrics.

Does commercial solar reduce demand charges?

It may, but annual production does not prove it. Recalculate each month’s billing demand from facility load and solar production at the tariff’s interval, window, ratchet, minimum, contract-demand and power-factor rules. Use a downside case where important peaks occur outside strong solar production.

Can a business assume a 30% federal solar credit in 2026?

No. The general Section 48E framework has a 6% base and an increase up to 30% when applicable requirements are met, but current solar termination timing, labor, basis, ownership, construction, placed-in-service and other rules matter. As of August 10, 2026, have a qualified tax adviser approve the input and model a zero/delayed case.

Is MACRS depreciation cash received from the government?

No. Depreciation is a deduction that may reduce taxable income under applicable rules. Its cash value depends on qualified/depreciable basis, credit basis adjustment, schedule/election, placed-in-service timing, tax rate and tax capacity. Show the deduction and resulting tax cash effect separately.

Can the full South Carolina solar credit reduce project cost in year one?

Do not model it that way without a tax-adviser-approved schedule. Revenue Ruling 24-2 describes a 25% calculated credit, but annual use is limited to the lesser of $3,500 per facility or 50% of state income-tax liability, with a nonrefundable 10-year carryforward. Actual use can be slower or incomplete.

How much historical data should a commercial ROI model use?

Use at least 12 complete bills and the best interval data available; more history helps when operations, seasons, tenants or peaks vary. Reconcile the no-solar tariff model to actual bills before calculating value. Treat committed future loads and speculative growth as separate cases.

Should a tenant use the solar array’s full expected life as the model horizon?

Not automatically. Use the period the tenant controls the account/site or has enforceable renewal, transfer or energy rights. Value beyond that period belongs in an explicit renewal, assignment, buyout or terminal case. Coordinate with the landlord, lender, insurer, legal counsel and tax adviser.

Sources and methodology

This guide was researched and updated August 10, 2026. It uses official IRS and South Carolina Department of Revenue tax guidance, current utility materials, EIA electricity-data methodology, NREL performance/financial models and demand-charge research, and DOE/NREL lifecycle sources. No Sunburst customer price, realized savings, return, tax result, degradation, O&M cost, insurance change or project performance was inferred.

Decision-critical sources include:

• NREL System Advisor Model: residential and commercial financial model;
• NREL SAM: commercial financial parameters;
• NREL PVWatts V8;
• NREL: estimating commercial PV demand-charge savings;
• EIA Electric Power Monthly;
• IRS: Clean Electricity Investment Credit and Notice 2025-42;
• IRS: clean-energy cost recovery, Notice 2026-6, and Form 3468 instructions;
• South Carolina Department of Revenue Revenue Ruling 24-2;
• Dominion Energy South Carolina business solar; and
• Santee Cooper Solar for Business.

Every real model should be rerun with the current account tariff/program, approved design and scope, signed ownership/financing documents, insurer and roof/site inputs, and written tax-adviser conclusions. This article is educational and is not tax, legal, accounting, insurance, investment, utility, or engineering advice.