Commercial Solar Before the Window Closes

US federal solar incentive rules changed under the One Big Beautiful Bill Act (OBBBA), signed July 4, 2025. The legislation preserved the 40% Investment Tax Credit for commercial projects but introduced two hard dates and a new compliance layer that together compress the planning window.

Two dates every operator should know

A third pressure: structural electricity demand

The January 2026 outlook from the US Energy Information Administration (EIA) projects the strongest four-year growth in US electricity demand since 2000, driven by data centres, AI computing, manufacturing reshoring, and electrification of transport. Commercial-sector summer demand is forecast to grow 2.6% in 2026 and 5.8% in 2027, well above the long-run average. National wholesale electricity prices rose 23% in 2025 and are forecast up another 8.5% in 2026; the commercial sector retail rate grew 10.7% year-on-year in the most recent EIA monthly update.

Georgia is at the leading edge. The state's Public Service Commission approved in December 2025 the addition of 9,885 MW of new generation capacity, roughly a 50% expansion of Georgia Power's fleet, primarily to serve data centre load. The implication for a commercial operator is direct: solar locks tomorrow's electricity cost at today's rate, and as underlying utility prices rise, the value of every self-generated kWh compounds.

Why this is sharper for European operators specifically

European capex approval cycles for non-strategic infrastructure typically run nine to eighteen months from initial business case to authorised commitment, with parent-company governance adding review steps beyond those US peers face. Board calendars cluster authorisations in Q4 and Q1, so the July 4 deadline sits awkwardly mid-summer. Clearing full board approval before July 4 from a standing start in May or June is unrealistic. Fortunately, that is not what the safe-harbor rule requires; the two-phase approach in Section 05 explains why.

The Investment Tax Credit is not a deduction against taxable income. It is a credit against US federal tax liability, applied dollar-for-dollar against tax owed. For a project costing one million dollars, the ITC reduces the entity's US federal tax bill by four hundred thousand dollars in the placed-in-service year.

Two paths exist:

• Path A: For-profit US subsidiary. For taxable US operating entities, the 40% ITC combines with MACRS accelerated depreciation. Under current Section 168(k), the federal tax basis of the system is depreciable in the placed-in-service year at 100% bonus, reduced by 50% of the credit claimed. Georgia permits state-level depreciation conforming to federal MACRS rules. The combined effect typically recovers 50% to 55% of system cost through Federal and State tax benefits in the first two years.
• Path B: Tax-exempt US holding or affiliate. Under IRA §6417, tax-exempt entities (including certain foundations, charitable arms, and qualifying public-purpose subsidiaries) elect to receive the 40% ITC as a cash refund from the US Treasury rather than as a credit against tax liability. The refund is filed with the entity's annual return and arrives 12 to 24 months after the year the system is placed in service.

Before any meaningful payback or IRR figure can be calculated, five decisions must be made in order. Most projects that stall at internal review do so because one was deferred past the point where the financial model could proceed.

1. 1

   Entity Type

   Which legal entity owns the system on paper. A US for-profit operating subsidiary captures both ITC and MACRS depreciation; a tax-exempt subsidiary elects Direct Pay under IRA §6417.

2. 2

   Deal Structure

   How the project is procured. Three structures dominate:

   • Direct purchase. Full ownership of the system, full capture of ITC and depreciation benefits, highest IRR. Requires capex authority and tax appetite at the entity claiming the credit.
   • Power Purchase Agreement (PPA). A third party owns and operates the system; the operator buys the electricity it produces at a contracted per-kWh rate, typically set below the local utility rate. No capex; the value proposition is a guaranteed reduction in electricity opex versus continued utility purchase.
   • Operating lease. A third party owns the system; the operator pays a fixed monthly amount for use of the equipment regardless of production. No capex; the value proposition is predictable opex on a known schedule.

   Direct purchase suits operators with capex authority and tax appetite. PPAs and leases both suit operators avoiding capex, but they answer different questions: a PPA guarantees electricity opex below the utility rate; a lease guarantees the line-item itself is predictable. The right choice usually comes down to which the parent-company finance committee scrutinises more closely — the magnitude of the energy bill or its variance.

3. 3

   System Type

   What is actually being built. Three architectures cover essentially every commercial case in Georgia:

   • Grid-tied. Solar PV connected to the utility grid; excess generation receives net-metering credit, shortfalls draw from the grid at standard rates. Maximises ITC value per dollar; the default for most commercial rooftops and carports. Savings type: offset-purchase only (every kWh generated displaces a kWh purchased from the utility).
   • Hybrid (solar + battery). Adds resilience and demand-charge management. Battery storage carries a separate ITC under Section 48E with a longer runway (full credit through 2033, phase-downs starting 2034). Suitable where operational continuity is mandate-critical. Savings types: offset-purchase, plus four battery-enabled outcomes — self-consumption (store solar generation to use later instead of selling it back at lower rates), time-of-use energy arbitrage (purchase from the grid when cheap, draw from battery when expensive), peak shaving (use battery during demand peaks to reduce demand-charge billing), and day-to-day arbitrage for large consumers on day-ahead tariffs.
   • Off-grid. Fully independent of the utility. Rare in Georgia, where utility infrastructure is generally reliable and grid-tied or hybrid economics are stronger. Not recommended for the vast majority of commercial cases.
4. 4

   Scope of Work

   What the installer delivers versus what the operator retains: supply only, supply and build (turnkey), or supply, build, and maintain (full lifecycle with production guarantees and O&M). For multi-site portfolios, the third option typically reduces total cost of ownership and standardises performance reporting. A 30-year extended warranty is available as an additional product, providing long-tail coverage on equipment and workmanship.

5. 5

   Financing

   How the capex is funded. Cash purchase recovers fastest and captures every incentive at full value; commercial loan terms run 5 to 10 years. If Decision 2 was a lease or PPA, this decision is effectively pre-made; financing affects IRR and balance-sheet treatment, not the underlying project economics.

For groups operating under the Corporate Sustainability Reporting Directive, a Georgia solar installation contributes directly to two of the most-scrutinised reporting categories:

• Scope 2 emissions reduction. Self-generated solar electricity displaces grid-sourced consumption at the asset level. In Georgia, grid carbon intensity remains higher than most European jurisdictions, which means the Scope 2 reduction per kWh generated is typically larger than the equivalent European installation would produce.
• EU Taxonomy alignment. Solar PV installation qualifies under the substantial contribution criterion for climate change mitigation, supporting Taxonomy-aligned capex disclosure under Article 8.
• Double materiality. The same transaction generates a financial return and a reportable environmental outcome.

FEOC compliance, briefly

OBBBA introduced a parallel compliance layer that affects ITC eligibility based on supply-chain composition. The rules restrict the involvement of entities tied to a defined list of jurisdictions (China, Russia, Iran, North Korea). A recapture provision applies if a qualifying project later receives components or services from a restricted entity. BTS handles FEOC documentation as part of the standard project workflow.

Safe-harboring before July 4, 2026 does not require completing the project before July 4, 2026. The IRS rule requires either a 5% expenditure of the qualifying project costs, or the start of physical work of a significant nature, by the deadline. Either path preserves the 40% ITC, 2026 equipment pricing and 2026's lower FEOC requirements for the full project.

The argument of this brief has not been that you should install solar because a deadline is approaching. The deadline forces the decision earlier than your normal planning cycle would suggest, and the responsible response to a forced timeline is to model the decision properly before committing to it.

The companion ROI calculator is built for that purpose. It takes four inputs and returns three outputs in approximately sixty seconds: fast enough to use in a working session, detailed enough to inform whether a fuller engineering review is justified.

Better Tomorrow Solar was founded in 2018 by Roji Aldashi (CEO) and Kaveh Kamooneh (COO), making BTS the only woman-owned and operated solar company in Atlanta. Headquartered at 1074 Memorial Drive SE, Atlanta, the firm operates as a Georgia-licensed and family-owned engineering and installation company.

Engagements are led by David Ewing P.E.

Professional Engineer licensed in Georgia, Georgia Tech Electrical Engineer, with 18+ years of experience in sustainability and clean energy.