A commercial solar return turns on which electricity purchases the building stops making, the full installed cost, and the incentives the owner can use. In this guide’s illustrative ROI model, cost recovery runs from 9.6 to 24.9 years across cases that pay back inside 25 years, and 7 of 64 never do.1 One date hides that spread.
What records does a commercial solar model need?
Collect four things before you compare bids: the installed scope, expected production, hourly building load, and the account’s tariff. Ownership matters just as much. A landlord who owns the roof but doesn’t pay the meter needs a different model, because the tenant’s bill savings may never reach the landlord.
| Input | Evidence to request | What changes the result |
|---|---|---|
| Ownership and meter | Roof rights, electricity account, lease, the proposed system owner | A tenant’s savings may never reach the landlord |
| Installed scope | Itemized proposal covering structure, electrical work, utility upgrades and roof-related work | One excluded upgrade can flip the decision |
| Production and load | Site-specific production estimate plus interval consumption data | Annual use can’t show how much solar output the building consumes as it’s made |
| Tariff and exports | Current rate schedule, supplier contract, riders, written export-credit treatment | Exported power can be worth less than power used on site |
| Operating costs | Maintenance scope, equipment-failure allowance, insurance, administration | Check whether a reserve already covers replacements |
| Incentives and taxes | Review by the tax owner’s adviser and actual program approval | A possible benefit isn’t money received |
Permits belong in the model too. Montgomery County’s Department of Permitting Services (DPS) requires two permits for rooftop commercial solar: a building permit for attaching the panels and an electrical permit for the connection to the building’s service. Both are filed online, and DPS says adequately prepared applications get first comments within 30 days.2 Filing fees follow the county’s fee schedule, so the proposal should show them as a line. Other jurisdictions run their own processes.
Keep loan payments and power purchase agreements (PPAs) out of an ownership model. In a PPA another party owns the system and the building pays that party for the electricity, so the contract sets what the building pays and keeps.3 Ownership and PPA cases need separate models. For the installed-price side, see our guide to commercial solar installation cost in Maryland.
Which electricity rate should the model use?
Use the charges that drop when the building buys less power, and leave fixed charges out of the savings. Model demand on its own, using the tariff’s measurement period. For exported power, get the utility’s credit treatment in writing before you value it like power used on site.
One Maryland tariff makes the point. This isn’t a regional rate or a complete bill. Pepco’s time-metered medium general service, low-voltage Type II schedule is called MGT LV II, and it applies based on the account’s demand or consumption, not the size of the solar array.4
| Pepco Maryland component | Published rate, as of October 25, 2026 | How to use it |
|---|---|---|
| Generation service, including its administrative charge | Standard Offer Service, October 1 to November 30, 2026: $0.10700 off-peak, $0.10772 intermediate, $0.12473 on-peak per kilowatt-hour5 | Apply each period’s rate to the power solar displaces in that period |
| Distribution energy | $0.02392 per kilowatt-hour4 | Separate component; the illustration below leaves it out |
| Distribution demand | $3.7982 per kilowatt-month for the August 28 to October 31, 2026 period4 | Test how solar changes the maximum thirty-minute demand in each billing month |
| Customer charge and riders | Listed separately in the schedule4 | Rebuild the actual bill; generation alone leaves these out |
Rates move, and the tariff itself shows it. The same schedule lists the distribution demand charge at $4.1991 per kilowatt-month for August 11 to 27, 2026, then $3.7982 again from August 28.4 Pepco says it files new generation charges effective every March, June, September and December.5 The periods above end October 31 and November 30, 2026, so a model built after that should start from the current tariff and rate notice, not from these numbers.
Standard Offer Service applies when the customer hasn’t chosen an alternative supplier, and a contract with one needs its own review.5
On this schedule, Pepco’s on-peak period runs noon to 8 p.m. on non-holiday weekdays, and weekends and holidays are off-peak all day.4 Solar output spreads across periods. A cloudy afternoon or an evening load peak can leave billed demand unchanged. Our guide to demand charges with solar and batteries goes deeper on that interaction.
Baltimore Gas and Electric (BGE) accounts need that account’s own schedule and supply contract. Washington, DC and Northern Virginia need their own tariffs and export rules. Don’t carry this Maryland example, or a Maryland program benefit, across the border.
What does an illustrative commercial model show?
It shows how assumptions move the time it takes to recover the cost. It can’t give a building’s actual return without site data. The example below assumes the owner uses all production on site, and it varies the tax credit, the generation rate and production loss. Some combinations never recover the cost inside 25 years.
Illustrative calculation, run October 17, 2026. Not a quote, not a Soleil project, and not a forecast. This is a host-owned, unfinanced, solar-only example. It uses no actual building’s interval data, roof design or utility eligibility.
| Input | Value used and where it comes from |
|---|---|
| Array and inverter | Assumed 600 modules of 400 watts: 240.00 kilowatts direct current (DC), with a 200.0-kilowatt alternating current (AC) inverter, a ratio of 1.201 |
| Annual production | PVWatts model run on October 17, 2026: 1,377.9 annual AC kilowatt-hours per kilowatt DC at a Silver Spring, Maryland location. The run assumes fixed roof mounting, south-facing, 20-degree tilt, 14 percent system losses and a DC/AC ratio of 1.2. The example produces 330,706 kilowatt-hours in year one. The chosen extra 20 percent loss case produces 264,5656,1 |
| Installed price | $2.40 per watt DC, the Berkeley Lab August 2026 national median for host-owned large non-residential systems installed in 2025, before incentives, in real 2025 dollars. The $3.00 alternative is a chosen higher-cost test, not another market median or a current quote. No inflation adjustment is applied7,1 |
| Gross outlay | $576,000 at the benchmark price, $720,000 at the higher-cost price1 |
| Generation value | Separate runs use the endpoints of Pepco’s October-November 2026 generation-only rates: $0.10700 or $0.12473 per kilowatt-hour. Assigning all production to one endpoint sets a valuation bound. It is not an hourly tariff simulation. Distribution energy, transmission, taxes and other riders are left out5,1 |
| Self-consumption and exports | Chosen assumption: the building uses all generation as it occurs. No export income or export credit is included. Annual generation alone can’t confirm this assumption1 |
| Demand | Chosen 300-kilowatt billed peak each month, with either no reduction or a 10 percent reduction. The starting distribution demand rate is $3.7982 per kilowatt-month. That gives $0 or $1,367 in year-one demand savings, and later demand benefits follow the selected escalation4,1 |
| Performance loss | 0.75 percent a year, from Jordan and colleagues’ 2022 study of commercial and utility fleets. It measures whole-system performance loss, not only module wear8 |
| Operations and maintenance | $20 per kilowatt DC a year, from the 2025 Annual Technology Baseline’s modeled pricing quoted in 2023. The input isn’t inflated and stays flat. The benchmark counts insurance and component failure among its cost categories, so no separate inverter replacement cost is added9,1 |
| Escalation and horizon | Zero or 3 percent annual escalation applies to both energy and demand benefits over 25 years. Neither is a utility forecast. Operations and maintenance costs stay flat, which can flatter the result1 |
| Credit and other benefits | Separate zero-credit and conditional section 48E commercial 30 percent credit runs. The credit case assumes the whole price is eligible basis and treats the credit as received at the start. Grants, renewable-certificate income, depreciation, adders and financing are excluded1 |
The calculations below include both prices, both escalation assumptions and both demand-reduction assumptions in each row. Each range covers only the combinations in that row that recover the cost within 25 years.1
| Extra production loss | Conditional credit | Generation value per kilowatt-hour | Years to recover cost, cases that recover | Cases beyond 25 years |
|---|---|---|---|---|
| Zero | Zero | $0.10700 | 15.0 to 24.9 years | One of eight1 |
| Zero | Zero | $0.12473 | 13.1 to 21.5 years | None1 |
| Zero | 30 percent | $0.10700 | 11.1 to 17.7 years | None1 |
| Zero | 30 percent | $0.12473 | 9.6 to 14.7 years | None1 |
| 20 percent | Zero | $0.10700 | 18.3 to 22.8 years | Four of eight1 |
| 20 percent | Zero | $0.12473 | 16.0 to 22.4 years | Two of eight1 |
| 20 percent | 30 percent | $0.10700 | 13.7 to 23.8 years | None1 |
| 20 percent | 30 percent | $0.12473 | 11.8 to 19.4 years | None1 |
Take the row with no extra production loss, the section 48E commercial credit and the higher generation value. In this illustrative model the years to recover the up-front cost run from 9.6 to 14.7 under the assumptions listed.1 Now read down the table. The best row recovers the cost in under 10 years in its best case, while the worst row leaves four of eight cases unrecovered at year 25. No single range describes the whole illustration.
Simple payback divides the modeled net outlay by year-one gross savings. Modeled cost recovery subtracts operating costs and includes performance loss and escalation of both energy and demand benefits. Neither measure accounts for the time value of money, and neither is an annualized return.1
The illustration leaves out depreciation, income taxes, financing costs, roof replacement, decommissioning and site-specific costs beyond the assumed installed price. The maintenance benchmark may not match an actual insurance premium or equipment-failure reserve. Our guide to commercial solar operations and maintenance shows how public benchmarks for that line differ. Before you weigh solar against another use of capital, get a discounted cash-flow analysis.
Net present value (NPV) discounts a project’s after-tax cash flows at the discount rate you assume. A positive NPV points to an economically feasible project, and a negative one doesn’t.10 The National Laboratory of the Rockies’ System Advisor Model defines internal rate of return (IRR) as the discount rate at which NPV equals zero.11 Neither equals cumulative profit, or the year undiscounted savings pass the outlay. The illustration above reports neither.
What do tax credits, depreciation and grants do to the return?
A tax credit cuts the owner’s tax bill, depreciation shifts when deductions land, and a grant pays only if the program approves the project. Give each its own line with the date the money arrives, and have a qualified tax professional confirm what the owner can use before you drop the no-incentive case.
| Item | What the source says, as of October 25, 2026 | How to treat it in an ownership model |
|---|---|---|
| Clean Electricity Investment Credit, section 48E | Base rate 6 percent. A 30 percent alternative rate applies to qualifying facilities with a maximum net output under one megawatt AC, among other routes12 | The test uses AC output, so DC array size doesn’t settle it. Larger facilities need prevailing-wage and apprenticeship compliance or another qualifying route |
| Solar deadline | Section 48E(e)(4) says the credit doesn’t apply to property of a solar facility placed in service after December 31, 2027. Public Law 119-21 applies that rule to facilities whose construction begins after July 4, 2026, which is 12 months after enactment13 | Which track you’re on depends on documenting a construction start. See our commercial solar tax credit deadline guide |
| Equipment sourcing and ownership | Section 48E restricts credits for property built with material assistance from a prohibited foreign entity, and Internal Revenue Service (IRS) Notice 2026-15 gives interim guidance on that test14 | Collect ownership and supply-chain records so the tax adviser can check the current rules |
| Bonus depreciation | The IRS Form 4562 instructions say Public Law 119-21 reinstated a 100 percent special depreciation allowance for certain qualified property acquired and placed in service after January 19, 202515 | Qualification and the owner’s ability to use deductions need tax review. A deduction isn’t a dollar-for-dollar rebate |
| Maryland solar grants | The Maryland Energy Administration (MEA) Commercial and Canopy Solar Program page says the fiscal-year 2026 budget is exhausted16. MEA’s fiscal-year 2027 Commercial and Community Buildings program opened September 9, 2026 and closes December 9, 2026 at 3 p.m. Eastern. The program’s solar measure lists nonprofits, local governments and local education agencies as eligible building types, and does not list for-profit owners17 | A for-profit owner shouldn’t count on a solar grant from this program. See our guide to Maryland commercial solar grants and C-PACE |
The statute lists the under-one-megawatt test as one way to reach the 30 percent rate, and the rest of section 48E still applies to the facility.12 The illustration assumes its hypothetical tax owner qualifies for the 30 percent rate12 and can use the credit right away. That is a modeling assumption, not a tax finding. A real owner has to confirm eligible basis, tax capacity, ownership restrictions, sourcing and timing with a tax adviser.14
Placed in service is a tax term
The December 31, 2027 date turns on when the system is “placed in service,” and that isn’t the day the panels arrive. Treasury’s regulation for the section 48E credit treats a qualified facility as placed in service in the earlier of two taxable years: the year the taxpayer’s depreciation period begins, or the year the facility is placed in “a condition or state of readiness and availability to produce electricity.”18 For a grid-connected system, your tax adviser will want commissioning and utility permission-to-operate dates in the file.
What happened to the construction-start rules
On June 6, 2026, a federal district court vacated IRS Notice 2025-42 and sent it back to the IRS. That notice gave the IRS’s method for deciding when construction began on wind and solar facilities for the credit-termination rule. It also made the cost-based five percent safe harbor unavailable except for solar facilities of 1.5 megawatts AC or less.19
The government normally has 60 days to appeal a district-court judgment, and that window closed August 5, 2026.20 The public docket, refreshed October 12, 2026, lists no notice of appeal and shows the case terminated on June 8.20 The docket can’t say whether the IRS will issue replacement guidance, so ask your tax adviser which construction-start method applies to your project.
Depreciation rules shifted too
The IRS instructions for Form 4562 say solar or wind energy property is no longer five-year property under the old route. The same instructions list property that is a qualified investment under section 48E, placed in service after 2025, among five-year property.15 Which class applies to a given system is a question for the owner’s tax adviser.
Basis matters too. Section 50(c) of the Code reduces the property’s basis when a credit is determined, and for the clean electricity investment credit only 50 percent of the credit counts toward that reduction.21 A tax professional has to apply that adjustment before calculating depreciation benefits.
Maryland storage funding is a separate project case
MEA’s fiscal-year 2027 Residential and Commercial Energy Storage (RCES) program funds eligible storage. It isn’t a general rebate for the solar array. The rebate is 30 percent of total project cost, capped at $150,000 for a business or nonprofit property.22 Funding moves. As of October 25, 2026, MEA’s funding table showed 20.90 percent of the $4,000,000 budget requested and 4.15 percent reserved, last updated October 19, 2026.23 The table is headed “Total FY26 RCES Grant Program Budget” even though the page covers the FY27 program, so treat the percentages as a snapshot and check MEA’s page for current figures.
The September 24, 2026 announcement requires MEA to approve a reservation before installation, and applicants request payment after installation and utility permission to operate. The program requires eligible ownership or payment arrangements, permanently installed equipment and a grid connection, and a system that already received funding or a reservation under certain MEA programs can be ineligible.22 The announcement says a reservation expires after 180 calendar days, and installation, utility permission and the payment application have to finish inside that window unless MEA grants an extension. The application deadline is May 31, 2027, at 3 p.m. Eastern Time, or earlier if the funds are fully requested.22
Adding storage changes cost and operation, so model it as its own project once you’ve confirmed program eligibility and tax interactions. This solar-only illustration includes no storage grant. Before you sign, check how a reservation’s timing fits the installation schedule.
Where do proposals flatter the numbers?
A proposal can overstate returns by treating the whole bill as avoidable, pricing exports like daytime consumption, or assuming the credit arrives on day one. Dividing total bill dollars by total kilowatt-hours is the classic slip: fixed charges, demand charges and exports behave differently from the energy charge. Rising rates and left-out maintenance also flatter the result on paper.
| Assumption to challenge | Evidence or comparison to request |
|---|---|
| All generated electricity offsets purchases | Interval load matched with production, with self-consumption, exports and curtailment shown separately |
| Demand savings follow annual energy savings | A monthly tariff-based demand simulation, including a case with no peak reduction |
| Full retail bill divided by consumption is the avoided rate | A component-by-component bill comparison that separates energy, demand and fixed charges |
| Rising rates make the investment work | A flat-rate comparison and a source for any contracted rate change |
| Incentives are deducted as cash on day one | Approval, eligibility, tax-capacity review and the actual receipt timing |
| Maintenance and replacements cost nothing | Written scope and reserve assumptions, with no duplicate replacement allowance |
| A large lifetime total equals an attractive annual return | Discounted cash flows using the owner’s hurdle rate, consistent tax treatment and the same analysis period |
Service costs belong in from the start. A written solar monitoring and maintenance scope shows which ongoing responsibilities land in the owner’s model.
When should you move ahead, and when should you pause?
Go to a detailed assessment when the project still clears your hurdle rate under conservative assumptions and every unresolved cost has an owner. Pause when the result depends on an unapproved grant, an unsupported peak reduction or unconfirmed tax treatment. Redo the model whenever utility terms, project scope, ownership or operating hours change.
- Collect records. Bills, interval consumption, ownership documents and the complete proposed scope.
- Rebuild the bill. Have the analyst map production to tariff periods, exports and monthly demand.
- Review eligibility. Get the tax professional and the program administrator to confirm benefits and receipt timing in writing.
- Compare alternatives. Use the same horizon and hurdle rate for solar and any competing use of capital, and settle the roof, utility and ongoing costs before approval.
If you want a Maryland project assessed, Soleil Energy’s solar engineering, procurement, and construction scope runs from design through construction and commissioning.24 Commercial inquiries use the form on that page; choose the project type that fits, such as Rooftop solar. Bring your tariff and the assumptions you want tested: Request a proposal or call (301) 953-4140.
Solar savings and incentive eligibility depend on your roof, your usage, your utility, and your tax situation. Incentive programs change and some have limited funding. We are not tax advisors — we will review your bill with you and tell you what you may qualify for. Confirm any tax credit with a qualified tax professional.
Program rules decide who qualifies. Ask any installer whether it is on the program’s contractor list.
Sources (24)
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Illustrative calculation, run October 17, 2026, with production, installed-cost, maintenance, performance-loss and tariff inputs sourced at 7, 6, 8, 9, 4 and 5. Remaining choices and exclusions are stated in the illustrative block. ↩ ↩2 ↩3 ↩4 ↩5 ↩6 ↩7 ↩8 ↩9 ↩10 ↩11 ↩12 ↩13 ↩14 ↩15 ↩16 ↩17 ↩18 ↩19 ↩20 ↩21 ↩22
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Montgomery County Department of Permitting Services, Commercial Solar Building permit process, undated page, read October 25, 2026. Confirm the site’s jurisdiction, current fees and project requirements with DPS. ↩
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National Laboratory of the Rockies (formerly NREL), System Advisor Model, Third Party: Host / Developer, undated documentation, read October 24, 2026. General concept only. ↩
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Pepco, Maryland electric tariff, Schedule MGT LV II, pages 7 to 7.2, issued August 14, 2026, read October 25, 2026. Rates shown are from the schedule’s most recent effective-period column (August 28 to October 31, 2026). ↩ ↩2 ↩3 ↩4 ↩5 ↩6 ↩7 ↩8
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Pepco, approved Maryland Type II supply rates, rates approved July 2026 for September 2026 and for October 1 through November 30, 2026, read October 25, 2026. The notice also gives the filing months for generation and administrative charges. ↩ ↩2 ↩3 ↩4 ↩5
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National Laboratory of the Rockies (formerly the National Renewable Energy Laboratory, NREL), PVWatts model and documentation, model run October 17, 2026 for a Silver Spring, Maryland location; current documentation page, read October 24, 2026. The model assumptions are stated above. The result is an annual estimate, not a site design or promised output. ↩ ↩2
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Lawrence Berkeley National Laboratory, U.S. Distributed Solar and Storage: 2026 Data Update, published August 2026, slide 8 (large non-residential median, 2025 installs) and slide 21; report, read October 24, 2026. ↩ ↩2
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Jordan and colleagues, Photovoltaic fleet degradation insights, 2022; publisher research record (National Laboratory of the Rockies, formerly NREL), current page, read October 24, 2026. The abstract reports an overall performance loss rate of 0.75 percent a year. ↩ ↩2
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National Laboratory of the Rockies (formerly NREL), 2025 Annual Technology Baseline: Commercial PV, operations and maintenance section, 2025 edition, read October 24, 2026. The figure is modeled pricing quoted in 2023, not a current maintenance quote. ↩ ↩2
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National Laboratory of the Rockies (formerly NREL), System Advisor Model, Net present value, undated documentation, read October 24, 2026. ↩
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National Laboratory of the Rockies (formerly NREL), System Advisor Model, Internal rate of return, undated documentation, read October 24, 2026. ↩
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26 U.S.C. 48E, subsection (a)(2), statutory rates and the alternative rate, current text, read October 25, 2026. Taxpayer-specific application requires tax review. ↩ ↩2 ↩3
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Public Law 119-21, section 70513(a) and (g)(5), enacted July 4, 2025, read October 25, 2026, with 26 U.S.C. 48E(e)(4), current text including the 2025 amendments, read October 25, 2026. ↩
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26 U.S.C. 48E, prohibited-entity and material-assistance provisions, current text, read October 25, 2026; IRS Notice 2026-15, sections 1 and 4, interim guidance, issued February 12, 2026, read October 25, 2026. The IRS says more guidance is coming, so check IRS.gov for later notices. ↩ ↩2
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IRS, Instructions for Form 4562 (2025), bonus depreciation and five-year property provisions, current page, read October 25, 2026. ↩ ↩2
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Maryland Energy Administration, Commercial and Canopy Solar Program, undated page, read October 25, 2026. The exhaustion notice at the top applies over the older open-program text below it. ↩
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Maryland Energy Administration, FY27 Commercial & Community Buildings Grant Program, undated program page showing the September 9, 2026 launch and December 9, 2026 deadline, read October 25, 2026; and the FY27 funding opportunity announcement, issued September 9, 2026 (file version dated September 28, 2026), section 9.3 and section 10.3.1, read October 25, 2026. Solar measures list nonprofits, local governments and local education agencies as eligible building types. ↩
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26 CFR 1.48E-2(b)(2)(i), Treasury regulation on when a qualified facility is placed in service, current republication, read October 25, 2026. Confirm how it applies to a specific project with a tax adviser. ↩
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U.S. District Court for the District of Columbia, Oregon Environmental Council v. Internal Revenue Service, memorandum opinion, June 6, 2026, case 1:25-cv-04400, document 50; opinion in the public RECAP archive, conclusion section, read October 25, 2026. The description of Notice 2025-42 comes from the notice itself, IRS Notice 2025-42, sections 1, 2.02 and 6, read October 25, 2026. ↩
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Federal Rule of Appellate Procedure 4(a)(1)(B), 60-day appeal period when the United States is a party, current text, read October 25, 2026; and the CourtListener docket for case 1:25-cv-04400, read October 25, 2026 (the site shows it last refreshed October 12, 2026; the public archive can lag the court’s own docket). June 6, 2026 plus 60 days is August 5, 2026. ↩ ↩2
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26 U.S.C. 50(c), basis adjustments and the clean electricity investment credit rule, current text, read October 25, 2026. ↩
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Maryland Energy Administration, FY27 RCES Funding Opportunity Announcement, issued September 24, 2026; sections 2, 3, 4.5, 7, 9, 10 and 11, read October 25, 2026. ↩ ↩2 ↩3
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Maryland Energy Administration, Residential and Commercial Energy Storage program page, funding table “Last Update to Total Budget Reserved: October 19, 2026,” read October 25, 2026. The table heading on the FY27 page reads “Total FY26 RCES Grant Program Budget”; the $4,000,000 matches the FY27 anticipated budget stated on the same page. ↩
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Soleil Energy, utility-scale solar EPC, current page, read October 24, 2026. ↩
