Section 45X pays US manufacturers a fixed dollar amount for each eligible component they produce and sell -- $0.07/W for solar modules, $35/kWh for battery cells, $0.05/W for wind nacelles. Unlike the Section 48 ITC (which is a percentage of your investment), this is a pure production credit: make more, earn more. For-profit companies can receive cash refunds via direct pay for the year they elect and the next four (never past 2032). Wind components expire after 2027; most others phase to zero after 2032.
What is the Section 45X Advanced Manufacturing Production Tax Credit?
Here's what you need to know about how Section 45X works: it is a per-unit production credit, not a percentage-of-investment credit. Every qualifying component your facility produces and sells to an unrelated buyer earns a fixed dollar amount -- regardless of what you spent to build the factory. This makes it fundamentally different from the Section 48 ITC, where the credit is tied to your capital investment. If you double your production, you double your credit. If you have a slow quarter, your credit shrinks. The credit tracks output, not investment.
Section 45X was created by the Inflation Reduction Act of 2022 and codified at IRC Section 45X. It applies to US manufacturers of specific clean energy components: solar cells, solar modules, solar-grade polysilicon, photovoltaic wafers, polymeric backsheets, wind blades, wind towers, wind nacelles, offshore wind foundations, inverters, battery cells, battery modules, electrode active materials, and applicable critical minerals. The credit is earned when eligible components are sold to an unrelated party -- or, in some cases, used by the manufacturer in their own clean energy projects.
There are no prevailing wage requirements. No apprenticeship ratios. No competitive application process. No grant portal to navigate. The credit is an entitlement: produce qualifying components in the US, sell them to unrelated buyers, complete IRS Form 7207, attach it to your federal tax return, and you receive the credit. The IRS may audit your credit calculation, but there is no pre-approval or competitive scoring.
Treasury issued Final Regulations in October 2024 clarifying definitions of eligible components and the rules for related-party sales. These regulations are the operative legal authority alongside the statute itself.
Deep Dive: The production credit vs. investment credit distinction -- why it matters for your factory economics
The difference between a production credit and an investment credit shapes how you finance, scale, and exit a manufacturing facility. Under the Section 48 ITC, you receive a credit equal to 30% (or 6%) of your capital investment when the facility is placed in service -- a one-time event. Under Section 45X, you receive credits annually as long as you keep producing eligible components. This has several practical consequences:
Cash flow profile: An ITC investor gets a big credit in year one and nothing in subsequent years from that credit. A §45X manufacturer earns credits every year they produce, creating a recurring annual cash flow that scales with production volume. For a 500 MW solar module facility, that is $35 million per year at full credit rates -- not a one-time event.
Financing implications: Because §45X credits are recurring and tied to production rather than to a specific capital asset, they can be used as collateral for operating credit lines. Tax equity investors can structure multi-year transfer agreements to buy forward credits at an agreed price, providing the manufacturer with predictable revenue. This is structurally different from project-finance tax equity for §48, which is a one-time allocation at commissioning.
Scale sensitivity: A small manufacturer with 10 MW of annual solar module output earns $700,000 per year in credits -- material, but not transformational. A gigawatt-scale facility earns $70 million per year. The credit structure inherently rewards scale, which is consistent with the policy goal of building globally competitive US manufacturing capacity. Smaller manufacturers should still claim the credit, but the internal complexity of tracking production and managing credit transfers may not justify hiring a full-time tax team until production exceeds approximately 50 MW annually.
No basis reduction: Unlike the Section 48 ITC -- which reduces your depreciable basis by the full credit amount -- Section 45X carries no basis reduction. Your entire manufacturing facility and equipment remain fully depreciable. This is a significant benefit: a §48 claimant who receives a $3M ITC on a $10M facility loses $3M of depreciable basis (reducing future depreciation deductions). A §45X claimant who earns $35M over ten years in production credits retains 100% of their depreciable basis throughout.
Related-party sale restriction: The credit is earned on sales to unrelated parties. If you sell components to a subsidiary, parent company, or any entity with more than 50% common ownership, those sales do not generate a credit. However, if an intercompany transfer is subsequently sold to an unrelated third party -- and you can demonstrate that at least 90% of the intercompany-transferred components are ultimately sold to unrelated buyers -- a safe harbor may apply. Consult tax counsel if your distribution structure involves related intermediaries.
Section 45X is the most powerful federal incentive for US clean energy manufacturers -- not because of its rate, but because it is recurring, scales with output, and requires no competitive application.
A 1 GWh battery cell facility earns $35 million per year in credits at current rates. A 500 MW solar module facility earns $35 million per year. At that scale, credits routinely exceed the manufacturer's income tax liability -- making the direct pay and transferability provisions essential, not optional.
What the 2025 tax law changed in Section 45X
The 2025 tax law (Pub. L. 119-21, signed July 4, 2025) kept the Section 45X rates and for-profit direct pay, but narrowed who can claim the credit and for how long. Wind components stop earning credit after 2027, critical minerals phase out from 2031 to 2033, and metallurgical coal was added at 2.5%. From a manufacturer's first tax year beginning after July 4, 2025, no credit goes to a specified foreign entity, a foreign-influenced entity, or a component with too much material from a prohibited foreign entity.
| What changed | Rule under the 2025 law | Applies to |
|---|---|---|
| Wind components (blades, nacelles, towers, offshore foundations, offshore wind vessels) | No credit for a wind component produced and sold after December 31, 2027. The 2022 law gave them the 2030 to 2032 phase-out instead. | After 2027 |
| Critical minerals | New phase-out: 75% for minerals produced in 2031, 50% in 2032, 25% in 2033, then zero. | Minerals produced from 2031 |
| Metallurgical coal | Added at 2.5% of production costs. Ends for coal produced after December 31, 2029. | Tax years beginning after July 4, 2025 |
| Who the taxpayer is | No credit for a year in which the manufacturer is a specified foreign entity or a foreign-influenced entity. | Tax years beginning after July 4, 2025 |
| What is in the component | A component with material assistance from a prohibited foreign entity is not eligible (cost test below). | Same; thresholds start with 2026 sales |
| Stacking integrated components (cells into modules, cells into battery modules) | The inner component earns credit only if the outer one is made in the same facility and at least 65% of the outer one's direct material costs are US-made components. | Tax years beginning in 2027 or later |
| Battery modules | Must include all other essential equipment, such as current collector assemblies and voltage sense harnesses. | Tax years beginning after July 4, 2025 |
| Selling credits | A Section 45X credit may not be transferred to a buyer that is a specified foreign entity. | All §6418 transfers in tax years beginning after July 4, 2025 |
What did not change: the rates for solar, inverter and battery components, their 2030 to 2032 phase-out, and the five-year direct pay election. A solar or battery plant still earns full-rate credit through 2029; a wind plant's credit ends after 2027; and every plant now has to measure where its materials come from.
Running a factory that also needs grants or state incentives? See which grants you qualify for.
Eligible products and per-unit credit rates
Here's what you need to know about the per-unit rates: every eligible component type has its own measurement unit and its own dollar amount. Solar is measured in watts of capacity; batteries are measured in kilowatt-hours; critical minerals are measured as a percentage of production cost; some smaller components (wafers, polysilicon, backsheets) use square meters or kilograms. Getting the measurement unit wrong -- claiming watts when the statute calls for kWh, or claiming the module rate on cells -- is the most common calculation error in IRS audits of §45X claims.
| Component | Unit of measure | Credit rate | Notes |
|---|---|---|---|
| Photovoltaic cells (solar cells) | Watts (DC capacity) | $0.04 / W | Per cell sold; separate from module credit |
| Solar modules (PV panels) | Watts (DC capacity) | $0.07 / W | Includes cells + laminate + frame assembly |
| Photovoltaic wafers | Square meters (m2) | $12 / m2 | Silicon wafers cut for solar cell production |
| Solar-grade polysilicon | Kilograms | $3 / kg | Refined polysilicon meeting solar-grade purity specs |
| Polymeric backsheets | Square meters (m2) | $0.40 / m2 | Rear protective layer for PV modules |
| Torque tubes (mounting structures) | Kilograms | $0.87 / kg | Steel racking components for utility-scale solar arrays |
| Structural fasteners | Kilograms | $2.28 / kg | Bolts, nuts, clamps used in solar mounting |
| Component | Unit of measure | Credit rate | Notes |
|---|---|---|---|
| Battery cells | kWh of capacity | $35 / kWh | Applies to each cell regardless of chemistry (Li-ion, LFP, etc.) |
| Battery modules (with cells) | kWh of capacity | $10 / kWh | Module containing battery cells; stackable with cell credit |
| Battery modules (cellless) | kWh of capacity | $45 / kWh | Module using non-cell active materials (e.g., sodium-ion, flow batteries) |
| Electrode active materials | 10% of production costs | 10% of costs | Cathode and anode materials produced from critical minerals |
| Component | Unit of measure | Credit rate | Expiration |
|---|---|---|---|
| Wind turbine blades | Watts of nameplate capacity | $0.02 / W | Dec 31, 2027 cliff |
| Wind turbine towers | Watts of nameplate capacity | $0.03 / W | Dec 31, 2027 cliff |
| Wind turbine nacelles | Watts of nameplate capacity | $0.05 / W | Dec 31, 2027 cliff |
| Fixed-platform offshore wind foundations | Watts of nameplate capacity | $0.02 / W | Dec 31, 2027 cliff |
| Inverter type | Credit rate | Typical application |
|---|---|---|
| Central inverters (utility-scale) | $0.0025 / W | Utility-scale solar farms |
| Utility inverters | $0.015 / W | Commercial + industrial solar installations |
| Commercial inverters | $0.02 / W | Rooftop commercial + small C&I |
| Residential inverters | $0.065 / W | Residential rooftop solar |
| Microinverters | $0.11 / W | Per-panel residential/commercial microinverter systems |
| Category | Credit rate | Eligible minerals |
|---|---|---|
| Applicable critical minerals | 10% of production costs | Lithium, nickel, cobalt, graphite, manganese, aluminum, antimony, barite, beryllium, cerium, cesium, chromium, dysprosium, erbium, europium, fluorspar, gadolinium, gallium, germanium, holmium, indium, lanthanum, lutetium, magnesium, neodymium, niobium, platinum-group metals, praseodymium, rubidium, samarium, scandium, tantalum, tellurium, terbium, thulium, tin, titanium, tungsten, uranium, vanadium, ytterbium, yttrium, zinc, zirconium |
A key nuance: the credit for cells and modules is not double-counting when a single manufacturer produces both. If you make solar cells and then assemble those cells into finished modules -- selling only the finished modules -- you earn the $0.07/W module credit on the entire module and also earn the $0.04/W cell credit on the same watts. The statute treats cell production and module production as separate eligible activities. An integrated manufacturer with cell-and-module production in the same US facility captures both credits on every watt they ship.
The same logic applies to battery cells and modules. If you manufacture battery cells and then build them into modules in the same US facility, you earn $35/kWh on the cells and $10/kWh on the modules for a combined $45/kWh on your integrated production -- before any phase-down.
Deep Dive: Worked examples -- calculating §45X credits for real production scenarios
Example 1: US solar module manufacturer, 500 MW annual production
Company A produces solar cells and assembles them into modules at a single US facility. Annual output: 500 MW of modules (containing A's own cells).
- Cell credit: 500,000,000 W x $0.04/W = $20,000,000
- Module credit: 500,000,000 W x $0.07/W = $35,000,000
- Total §45X credit for the year: $55,000,000
At this scale, the credit exceeds virtually any income tax liability. Company A elects direct pay for years 1-5, receiving IRS refunds. From year 6, it transfers credits to a third-party buyer at approximately 93 cents on the dollar, generating $51.15M in cash.
Example 2: Battery cell manufacturer, 2 GWh annual production
Company B manufactures lithium-iron-phosphate battery cells for grid storage at a US facility. It sells cells only (no module assembly). Annual output: 2,000,000 kWh of cell capacity sold to unrelated storage integrators.
- Cell credit: 2,000,000 kWh x $35/kWh = $70,000,000
Company B is in its third year of claiming. It has used direct pay for years 1-3 and plans to shift to transferability in year 6. It has already engaged a tax equity broker to line up buyers for forward credit purchases.
Example 3: Wind nacelle manufacturer, 3 GW annual production
Company C manufactures nacelles for onshore wind turbines at a US factory. Annual output: 500 nacelles at 6 MW average capacity each = 3,000 MW = 3,000,000,000 W.
- Nacelle credit: 3,000,000,000 W x $0.05/W = $150,000,000
Critical note: Company C must sell all qualifying nacelles before December 31, 2027. Components sold on January 1, 2028 earn zero credit. Company C should be actively planning its post-2027 production mix now -- either pivoting to another eligible component or restructuring its capital recovery timeline around a 2027 credit cliff.
Example 4: Critical mineral processor, $50M in lithium carbonate production costs
Company D refines spodumene ore into battery-grade lithium carbonate at a US facility. Annual qualifying production costs: $50,000,000.
- Critical mineral credit: $50,000,000 x 10% = $5,000,000
This is smaller in absolute terms than battery or solar credits, but it applies to the cost of production rather than a per-unit physical measure -- making it accessible to facilities at a wider range of scales. Note that critical minerals phase out one year later than other components: after 2033 rather than after 2032.
How to calculate the Section 45X credit, component by component
Multiply the statutory rate by the unit the statute names, then by the year's phase-out percentage. Wafers are paid per square meter, polysilicon and tracker steel per kilogram, cells, modules and inverters per watt, batteries per kilowatt-hour, and minerals and electrode materials as 10% of production cost. Wind parts are the exception: the rate is multiplied by the rated capacity of the whole turbine the part is designed for.
| Component | Rate and unit | Worked example | Credit |
|---|---|---|---|
| Photovoltaic wafer | $12 per square meter | A 210 mm wafer is 0.0441 m²; 10 million wafers | $0.53 each; $5,292,000 |
| Solar grade polysilicon | $3 per kilogram | 1,000 metric tons (1,000,000 kg) | $3,000,000 |
| PV cells plus modules, same plant | 4 cents + 7 cents per DC watt | 100 MW of modules made from the plant's own cells | $11,000,000 |
| Torque tubes / structural fasteners | $0.87 / $2.28 per kilogram | 5,000 metric tons of torque tubes | $4,350,000 |
| Inverters | Per AC watt: central 0.25¢, utility 1.5¢, commercial 2¢, residential 6.5¢, microinverter or distributed wind 11¢ | One 100 kW commercial inverter; one 400 W microinverter | $2,000; $44 |
| Battery cells plus modules, same plant | $35 + $10 per kWh (cell-free module: $45) | 1 GWh (1,000,000 kWh) of cells built into modules | $45,000,000 |
| Electrode active materials | 10% of production costs | $80 million of cathode production costs | $8,000,000 |
| Wind blade, nacelle or tower | Blade 2¢, nacelle 5¢, tower 3¢ per watt of the completed turbine | One nacelle designed for a 6 MW turbine | $300,000 |
| Offshore wind foundation | Fixed 2¢, floating 4¢ per turbine watt | One floating foundation for a 15 MW turbine | $600,000 |
| Related offshore wind vessel | 10% of the vessel's sales price | A $200 million installation vessel | $20,000,000 |
| Critical minerals | 10% of production costs (metallurgical coal 2.5%) | $50 million to produce lithium hydroxide; $40 million of coal | $5,000,000; $1,000,000 |
Battery capacity counts only up to a capacity-to-power ratio of 100:1. For a blade the statute's arithmetic is 2 cents times the turbine's rated watts; check Treasury's final §45X regulations on how that applies to a set of blades before booking it.
| Year | Solar, inverter, battery | Minerals | Wind | Met coal |
|---|---|---|---|---|
| 2026–27 | 100% | 100% | 100% | 100% |
| 2028–29 | 100% | 100% | 0% | 100% |
| 2030 | 75% | 100% | 0% | 0% |
| 2031 | 50% | 75% | 0% | 0% |
| 2032 | 25% | 50% | 0% | 0% |
| 2033 | 0% | 25% | 0% | 0% |
| 2034+ | 0% | 0% | 0% | 0% |
Minerals and metallurgical coal go by the year produced. Wind: no credit for a component produced and sold after December 31, 2027. Coal: no credit for coal produced after December 31, 2029.
The estimate applies the two tables above only, not the foreign-entity or integrated-component rules.
For the grants and state incentives that pay for the plant itself, see manufacturing grants and the credits worth more than them.
Direct pay for for-profit manufacturers: the 5-year window
Section 45X is one of only three credits (with §45V clean hydrogen and §45Q carbon capture) that for-profit companies can take as direct pay. Under IRC Section 6417(d)(1)(D), a for-profit manufacturer can elect to receive the §45X credit as a cash refund from the IRS rather than as an offset against income tax -- but only for the first five consecutive tax years of claiming the credit. After that window, you must shift to transferability or apply the credit against tax liability.
Under most IRA credits, direct pay (formally called "elective pay") is available only to tax-exempt entities: nonprofits, governments, tribal governments, rural electric cooperatives. For-profit businesses are typically restricted to transferability -- selling their credits to a third party for cash at a discount. Section 45X broke this pattern deliberately.
Congress created the §45X for-profit direct pay provision because the largest intended beneficiaries -- gigawatt-scale solar and battery manufacturers -- often operate as for-profit corporations with tax structures that make standard tax equity complicated. The direct pay window gives new manufacturers a clean, simple cash recovery mechanism while they are building their operations to scale.
The five-year window begins in the first tax year you elect direct pay and covers that year plus the next four, regardless of whether you claim credits in every year within that window. The window ends no later than December 31, 2032 in any case (when credits for most components expire). For a manufacturer that first claims the credit on its 2024 tax return, direct pay would be available through the 2028 tax year.
| Feature | Direct pay (§6417) | Transferability (§6418) |
|---|---|---|
| Who can use it | For-profits: the election year plus the next four, ending by 2032. Tax-exempts: unlimited. | Any taxpayer, for any year not covered by a direct pay election; never to a specified foreign entity |
| Cash recovery timing | IRS refund after return processing (12-16 weeks) | Cash at credit transfer closing (before filing) |
| Dollar value recovered | 100 cents on the dollar | Typically 90-95 cents on the dollar (market discount) |
| Buyer required? | No -- IRS is the counterparty | Yes -- must find and execute agreement with buyer |
| Pre-filing registration | Required (IRS pre-filing registration portal) | Required (IRS pre-filing registration portal) |
| Availability limit | 5 consecutive years for for-profits | Any year not covered by a direct pay election (never to a specified foreign entity) |
Here's what you need to know about choosing between direct pay and transferability: direct pay returns 100 cents on the dollar but takes 12-16 weeks to arrive. Transferability delivers cash before you file -- typically 90-95 cents on the dollar -- because the buyer discounts the credit to account for audit risk and the cost of capital. For manufacturers in their first five years, direct pay is almost always the better option unless you have an acute near-term cash need that outweighs the 5-10% discount cost. Plan the transition to transferability before year six: engage a tax equity broker in year four so you have a buyer relationship in place when direct pay closes.
Deep Dive: How to elect direct pay and what the IRS pre-filing registration process looks like
Step 1: Register with the IRS pre-filing registration portal. Both direct pay and transferability require pre-filing registration through the IRS Energy Credits Online portal (energycredits.irs.gov, launched following IRA 2022). Registration generates a registration number for each eligible credit property or credit type. You must complete registration before filing your tax return for the applicable year.
Step 2: File the elective pay election. The election is made on IRS Form 3800 (General Business Credit) and by checking the elective payment election box on Form 7207 (Advanced Manufacturing Production Credit). The election must be made by the original return due date including extensions -- you cannot make or revoke the election on an amended return.
Step 3: IRS processes and issues refund. The IRS treats elective pay as an overpayment of tax and issues a refund. Processing typically takes 12-16 weeks from the return filing date. There is no separate payment system -- it flows through the standard tax refund mechanism. For large credits (over $1M), expect the IRS to issue a compliance review letter before issuing the refund; this is standard procedure and does not indicate an audit.
Failure to register before filing: If you fail to register before filing, the IRS will deny the direct pay election for that year. You cannot cure this failure with an amended return. The credit itself does not disappear -- it becomes a non-refundable credit against your income tax liability or a carryforward -- but you lose the direct pay cash refund for that year. Set a calendar reminder: registration should begin at least 60 days before your planned return filing date.
Year five planning: In your fifth and final year of direct pay eligibility, begin transferability negotiations simultaneously. Credit transfer markets require several months to identify buyers, negotiate terms, execute legal agreements, and complete IRS registration of the transfer. If you plan to transition from direct pay to transferability in year six, start the year five transfer process no later than mid-year of that final direct pay year.
For a new US solar or battery manufacturer, direct pay is the preferred cash recovery mechanism in years 1-5 -- it returns the full credit value with no market discount and no buyer to negotiate with.
At current credit market discount rates of 5-10%, a manufacturer earning $35M/year in §45X credits recovers an additional $1.75M to $3.5M per year by choosing direct pay over transferability during the five-year window.
Direct pay and credit transfers after the 2025 law
Both survived the 2025 tax law. A for-profit manufacturer can still take the Section 45X credit as a direct payment under IRC §6417(d)(1)(D), and a Section 45X credit can still be sold under IRC §6418, with two exceptions. Three rules apply: a direct pay election covers its year plus the next four (never past 2032), credits for those years cannot be sold, and no Section 45X credit may be sold to a specified foreign entity.
| First year you elect direct pay | Years covered by the election | Years outside the election |
|---|---|---|
| 2026 | 2026 to 2030 | 2031 and 2032 |
| 2028 | 2028 to 2032 | Any year before 2028 |
| 2030 | 2030 to 2032 only (the election cannot reach 2033) | Any year before 2030, and 2033 for critical minerals |
| Any year, then revoked | The years before the revocation takes effect | The revoked years. A revocation is permanent. |
A decision rule. Elect direct pay for the first tax year in which your Section 45X credit is larger than the income tax you expect to owe. If you expect to turn profitable inside the window, weigh the lock-in: the election decides all five years unless revoked, and a revocation is permanent. A plant that starts claiming late in the decade gets fewer than five years, because the election stops at 2032.
Can a Section 45X credit be sold before the factory produces anything? Not the credit itself. The credit for a tax year is the sum for components produced and sold to an unrelated buyer in that year, so nothing exists to transfer until then. A buyer can sign a forward agreement earlier that fixes price and volume for credits the plant expects to earn. If the manufacturer is a foreign-influenced entity in a year, that year's credit does not exist.
If your company also qualifies for grants or state programs, see which grants you qualify for.
Foreign Entity of Concern (FEOC) restrictions: what your supply chain must get right
Here's what you need to know about FEOC restrictions: they are evolving, they are legally complex, and a single ownership or control relationship that triggers FEOC status can disqualify your entire §45X credit claim . The bars fall on the taxpayer (a specified foreign entity or a foreign-influenced entity) and on material inputs from prohibited foreign entities; the statute has no rule about who buys your components. The 2025 tax law (Pub. L. 119-21) and IRS Notice 2026-15 are the operative sources, and annual review of your ownership chain with qualified tax counsel is not optional -- it is required due diligence.
A "foreign entity of concern" is defined by reference to the National Defense Authorization Act. The four covered nations are China, Russia, Iran, and North Korea. An entity qualifies as an FEOC if it is incorporated in, headquartered in, or owned or controlled by an entity in a covered nation, or if it is subject to the jurisdiction or direction of a covered nation's government. The specific ownership thresholds and control tests are set out in 26 U.S.C. 45X and 7701(a)(52) and differ slightly by component type and phase-in year.
Section 45X had no foreign-entity rule until the 2025 tax law. For tax years beginning after July 4, 2025, that law added two tests: (1) no credit for a manufacturer that is a specified foreign entity or a foreign-influenced entity, and (2) no credit for components that include material assistance from a prohibited foreign entity (see the material assistance section below).
The material assistance thresholds rise each calendar year from 2026 and differ by component type. Manufacturers with any non-US ownership -- or with supply chain partners in covered nations -- should complete a formal FEOC compliance analysis for each component type before claiming §45X credits.
| Compliance check | Who it affects | Risk level |
|---|---|---|
| Review ownership structure for a specified foreign entity owning 25% or more, specified foreign entities owning 40% or more in total, holding 15% or more of your debt, or able to appoint an officer | All manufacturers with non-US investors or parents | High -- triggers full disqualification |
| Review contracts with Chinese or Russian battery material suppliers (cathode, anode, electrolyte) | Battery cell and module manufacturers | High for components subject to the 2026+ material assistance thresholds |
| Confirm no credit buyer is a specified foreign entity (§6418) | All manufacturers | Medium -- bars the transfer to that buyer |
| Review joint venture agreements for covered-nation management rights or veto powers | Manufacturers with JV structures | High if control test is triggered |
| Track the Treasury safe-harbor tables and critical-mineral thresholds the 2025 law calls for | All manufacturers | Ongoing -- regulations still being finalized for some components |
| Collect supplier certifications and keep the material assistance cost ratio workpapers with your Form 7207 file | All §45X claimants | Required -- IRS audit focus area |
Deep Dive: Structuring your supply chain for FEOC compliance -- practical guidance
The battery supply chain is the highest-risk area. Global battery cell manufacturing has historically been dominated by Chinese and Korean producers. A US battery manufacturer that sources cathode active material from a Chinese supplier -- even if it processes that material further in the US -- may face FEOC questions depending on the specific processing steps, the ownership structure of the supplier, and which Treasury regulations apply to that component type in that year.
Upstream mineral sourcing. Critical mineral processing has significant Chinese presence globally. For the §45X critical minerals credit specifically, the eligible minerals must be produced from processing or refining within the US. If a US refinery processes ore from a covered-nation miner, the FEOC analysis focuses on whether the US refinery itself is FEOC-controlled, not on the origin of the ore. But supply chain documentation must clearly establish US processing occurs and that the processor is not FEOC-controlled.
Investor ownership tracking. Private equity and venture capital portfolios in manufacturing companies sometimes include limited partners with ties to covered nations. A general partner may not have clear visibility into the full LP base. Manufacturers should require their PE sponsors to represent their LP composition on an annual basis and flag any covered-nation LPs that exceed applicable ownership thresholds.
Joint venture structures. A US-China joint venture where the Chinese partner holds manufacturing process patents, has technology license rights, or controls key supply agreements may constitute "control" even without majority ownership. The foreign-influenced-entity tests in the statute go beyond equity ownership (debt, appointing an officer, effective-control payments).
Practical step for new manufacturers: Engage a trade law or tax counsel firm with FEOC practice experience before your first §45X claim. The cost of a FEOC compliance review ($25,000-$75,000 for most manufacturers) is trivial compared to the credit amounts at stake and the reputational and legal consequences of a disqualification finding during an IRS examination.
FEOC compliance is not a box to check once -- it requires annual review as Treasury issues the proposed regulations and safe harbor tables the 2025 law and IRS Notice 2026-15 call for and as your ownership structure and supply chain evolve.
A single undisclosed FEOC relationship discovered during an IRS examination would trigger disallowance of all §45X credits claimed for the affected years -- potentially tens of millions of dollars in disallowed credits plus interest and penalties. Annual legal review is not optional at this credit scale.
Material assistance from a prohibited foreign entity: the cost test each component must pass
From a manufacturer's first tax year beginning after July 4, 2025, a component earns no Section 45X credit if too much of its direct material cost comes from a prohibited foreign entity. The material assistance cost ratio (non-foreign-entity direct material cost divided by all direct material cost) must reach the year's threshold, which for solar components rises from 50% for 2026 sales to 85% after 2029.
Ratio = (total direct material costs − those from a prohibited foreign entity) ÷ total direct material costsBelow the threshold for the year sold, the component is not eligible.
| Component | 2026 | 2027 | 2028 | 2029 | 2030+ |
|---|---|---|---|---|---|
| Solar | 50% | 60% | 70% | 80% | 85% |
| Battery | 60% | 65% | 70% | 80% | 85% |
| Inverters | 50% | 55% | 60% | 65% | 70% |
| Wind | 85% | 90% | – | – | – |
| Minerals | 0% | 0% | 0% | 0% | 25%+ |
Wind components earn no credit after 2027. Critical minerals rise to 25% for 2030 sales, 30% for 2031, 40% for 2032 and 50% after that; Treasury must set mineral-by-mineral thresholds, at least this high, by the end of 2027.
A worked example: battery modules sold in 2026. A plant's 2026 battery modules carry $6.0 million of direct material costs. If $2.7 million of that was produced by a prohibited foreign entity, the ratio is (6.0 − 2.7) ÷ 6.0 = 55%, under the 60% floor, and those modules earn no Section 45X credit. At $2.4 million the ratio is 60%, which passes. Sold in 2027, the same modules need 65%, so the share must fall to $2.1 million: a supply plan that passes one year can fail the next.
Who counts. A specified foreign entity includes foreign entities of concern under the 2021 defense authorization act, companies on the Defense Department's Chinese military company list, and entities controlled from China, Russia, Iran or North Korea: their governments, their citizens who are not US citizens or green card holders, companies organized or headquartered there, and entities those control. A foreign-influenced entity meets any of the four tests above during the tax year, or in the previous year paid a specified foreign entity under a contract giving it effective control over production. These tests decide whether the manufacturer can claim at all; the ratio decides which components qualify.
Measuring it before final rules. Treasury must publish safe harbor cost tables by the end of 2026. Until then, IRS Notice 2026-15 lets manufacturers use the cost tables in IRS Notice 2025-08 and rely on supplier certifications. A certification does not help a manufacturer that knows, or has reason to know, a product came from a prohibited foreign entity: all of that product's cost then counts against the ratio.
For clean energy grants and incentives outside the tax code, see clean energy business grants open now.
Phase-down schedule: when does the credit zero out?
Here's what you need to know about the §45X phase-down: the schedule is not uniform across components. Wind is the most urgent -- it faces a hard cliff on January 1, 2028 with zero phase-down. Solar, battery, and most other components follow a gradual four-step reduction from 2030 through 2032. Critical minerals get an extra year. If you are evaluating a new manufacturing investment, the phase-down timeline is a core input to your IRR model -- not an afterthought.
Energy property that is not a manufacturing facility falls under the investment credit; see the Section 48 and 48E credit guide.
| Component group | 2024-2029 | 2030 | 2031 | 2032 | 2033+ |
|---|---|---|---|---|---|
| Wind (blades, towers, nacelles, offshore foundations) | 100% through 2027; 0% in 2028-29 | 0% | 0% | 0% | 0% |
| Solar (cells, modules, wafers, polysilicon, backsheets) | 100% | 75% | 50% | 25% | 0% |
| Battery (cells, modules, electrode active materials) | 100% | 75% | 50% | 25% | 0% |
| Inverters | 100% | 75% | 50% | 25% | 0% |
| Critical minerals | 100% | 100% | 75% | 50% | 25% in 2033, 0% after |
The wind cliff is the most strategically significant feature of the phase-down schedule. Wind blade, tower, and nacelle manufacturers receive no gradual reduction -- full credit through 2027, then nothing. A wind component factory that finishes its qualifying production on December 31, 2027 earns the full credit. The same factory on January 1, 2028 earns zero. This binary structure creates enormous pressure on wind supply chain investment decisions in 2025 and 2026: facilities that cannot reach full production before the cliff have a far shorter payback window and less favorable project economics.
For solar, battery, and inverter manufacturers, the 2030-2032 phase-down is more manageable but still material. At 75% in 2030, a facility that earns $70M at full rate would earn $52.5M. At 25% in 2032, it earns $17.5M. These are still significant credits, but a manufacturing facility designed around full-rate economics will see its credit-driven IRR decline meaningfully in the 2030-2032 window. Manufacturers should stress-test their financial models at 75%, 50%, and 25% credit rates before committing capital.
Deep Dive: Modeling the phase-down impact on manufacturing facility IRR
For a 500 MW solar module facility placing in service in 2026 and producing at full capacity through 2033, here is how the phase-down affects cumulative §45X credit revenue (solar modules only, ignoring cell credit for simplicity, at $0.07/W):
- 2026: $35M (100%)
- 2027: $35M (100%)
- 2028: $35M (100%)
- 2029: $35M (100%)
- 2030: $26.25M (75%)
- 2031: $17.5M (50%)
- 2032: $8.75M (25%)
- Total: $192.5M over 7 years
If you assume you also claim the cell credit ($0.04/W = $20M/year at full rate), total integrated credits peak at $55M/year in 2026-2029 and step down similarly. Total credit revenue over 7 years: approximately $330M.
For IRR purposes, the key question is how much of this credit revenue is captured at full value (via direct pay in years 1-5) versus transferred at a discount (90-95 cents). A manufacturer claiming direct pay in 2026-2030 and transferring at 93 cents in 2031-2032 recovers the credit with only modest discounting even in the phase-down period.
Legislative risk: the 2025 law moved the other way, ending the credit for wind components after 2027 and adding a phase-out for critical minerals. Plan on the statutory schedule and treat any extension as upside you cannot count on.
Section 45X vs. Section 48 ITC: different credits, different bases, not mutually exclusive
Here's what you need to know about combining §45X and §48: they operate on entirely different tax bases and are not mutually exclusive. Section 45X is a production credit -- it applies to the components you manufacture and sell. Section 48 is an investment credit -- it applies to the clean energy property you install at your facility. A solar module manufacturer that installs solar panels on the roof of their own factory can claim §45X on the modules they produce and sell, and simultaneously claim §48 on the cost of the rooftop system they installed. Different assets, different credit bases, both valid.
| Feature | §45X (Manufacturing PTC) | §48 (Energy ITC) | §45 (Energy PTC) |
|---|---|---|---|
| Credit type | Per-unit production credit | % of investment (30% or 6%) | Per-kWh electricity production credit |
| What it applies to | Manufactured components sold to unrelated buyers | Clean energy property placed in service | Electricity produced from wind, solar, etc. |
| Basis reduction? | No -- full basis remains depreciable | Yes -- basis reduced by credit amount | No |
| Prevailing wage requirement? | None | Yes, for projects >= 1 MW to get 30% (vs. 6%) | Yes, for bonus rate |
| For-profit direct pay? | Yes -- first 5 tax years | No -- for-profits must use transferability | No -- for-profits must use transferability |
| Form used | Form 7207 | Form 3468 | Form 8835 |
| Expires | 2027 (wind) / 2032 (others) | §48E takes over for post-2024 construction | 2032 (§45Y takes over) |
| Can you combine with §45X? | N/A (this is §45X) | Yes -- different bases | Yes -- different assets/activities |
The most common question about §45X and §48 concerns a manufacturer who installs solar panels on their own manufacturing facility. The answer is clear: the solar installation is §48 ITC property (the installed energy system), and the solar modules the same company manufactures and sells to third parties are §45X production credit property. These are separate assets generating separate credits. There is no offset, no stacking limitation, and no double-dipping concern -- they apply to genuinely different activities and assets.
A separate, more nuanced scenario arises when a manufacturer uses its own produced components in its own clean energy project. For example, a battery cell manufacturer that uses its own cells to build a behind-the-meter storage system at its factory. In this case, the manufacturer can still claim the §45X cell credit on those cells (because the statute allows credit for cells "used" by the taxpayer as well as "sold" to unrelated parties) and can simultaneously claim §48 ITC on the storage system as installed property. Again, these are not mutually exclusive -- but the documentation requirements for "self-use" credits are more complex than for outright sales, and careful record-keeping is essential.
For most US clean energy manufacturers, Section 45X is the primary credit to maximize. Section 48 is a secondary opportunity that applies when the same company also installs clean energy property at its own facilities.
A battery manufacturer with a 2 GWh facility that also installs a 5 MW solar system on-site earns approximately $70M/year in §45X credits on production plus a one-time $1.5M §48 ITC on the solar installation. The production credit overwhelms the investment credit in scale, but neither is trivial.
Compliance, audit, and recordkeeping for §45X
Here's what you need to know about IRS audit risk for §45X: the audit focus areas are predictable and the documentation requirements are clear. The most common IRS examination issues are: incorrect component classification (claiming the module rate on cells, or confusing inverter subcategories), related-party sale exclusion failures, FEOC compliance documentation gaps, and wind component credits claimed after December 31, 2027. None of these are obscure technical traps -- they are the exact issues the statute and the Treasury regulations address explicitly.
Section 45X is an entitlement credit with no pre-approval process. The IRS reviews claims through its standard examination program, with audit selection based on credit size, industry, and document matching. For credits exceeding $1M, expect a higher likelihood of examination. The good news: the credit calculation itself is straightforward arithmetic once you have accurate production and sales records. The documentation burden is largely about proving three things: (1) the components were manufactured in the US, (2) they were sold to unrelated parties, and (3) the correct per-unit rate was applied to the correct measurement unit.
The 2025 law and IRS Notice 2026-15 allow supplier certification and interim safe harbors to support the material assistance cost ratio. Manufacturers must obtain and retain certifications from their foreign-sourced component suppliers and counterparties. These certification requirements are ongoing -- a certification obtained in year one does not cover subsequent years if ownership structures change.
| Document | Purpose | Retention period |
|---|---|---|
| IRS Form 7207 with supporting schedules | Credit calculation and claim | Until statute of limitations expires (3-6 years from return date) |
| Production and sales records by component type | Substantiate units and measurement | Minimum 6 years |
| Customer contracts and invoices (unrelated-party evidence) | Prove sales were to unrelated third parties | Minimum 6 years |
| Manufacturing facility documentation | Prove components were produced in the US | Ongoing (facility exists throughout claim period) |
| FEOC compliance certification | Annual certification of ownership structure and counterparty compliance | Annual; retain each year's certification for 6 years |
| IRS pre-filing registration confirmation | Required for direct pay and transfer elections | Per-year election; retain indefinitely |
| Transfer agreements (if applicable) | Irrevocable transfer election documentation | Minimum 6 years |
Deep Dive: Component classification errors -- the most common §45X audit issue
The IRS audit technique guides for §45X focus heavily on component classification. Each component type has a precise statutory definition, and claiming the wrong rate on the wrong component is a direct route to credit disallowance. Here are the most common classification errors encountered in practice:
Solar cell vs. solar module: A solar cell is the individual photovoltaic unit. A solar module (panel) is the assembled product containing cells, encapsulant, backsheet, frame, and junction box. The rates are different ($0.04/W for cells, $0.07/W for modules) and apply to different production steps. A manufacturer that assembles modules from purchased cells can only claim the $0.07/W module rate -- not the cell rate. A vertically integrated manufacturer that makes both cells and modules claims both rates.
Inverter subcategory misclassification: The inverter credit rates vary significantly by subcategory ($0.0025/W for central inverters vs. $0.11/W for microinverters). The subcategory definitions are based on technical specifications, not marketing descriptions. A commercial inverter sold and marketed as a "central inverter" may meet the statutory definition of a commercial inverter at $0.02/W. Classification should be based on the statutory technical criteria, not product naming conventions.
Wind component nameplate capacity measurement: Wind credits are measured in watts of nameplate capacity of the turbine system, not of the individual component. A nacelle installed in a 3 MW turbine earns $0.05/W x 3,000,000 W = $150,000 per nacelle. Manufacturers must track which turbine configurations their components are installed in, which requires customer-supplied installation data. Absent that data, conservative capacity assumptions are appropriate to avoid overclaiming.
Battery module "cellless" rate: The $45/kWh cellless module rate applies only to modules that use non-cell active materials -- meaning the module assembly does not contain conventional battery cells. This rate is designed for emerging battery chemistries like flow batteries or solid-state technologies that do not use conventional cell-format electrochemistry. Do not claim the $45/kWh rate on a conventional lithium-ion module that contains cells -- that rate is $10/kWh.
Your situation, specifically
A solar cell and module manufacturer
You are in the strongest position of any §45X claimant. You earn two credits on every watt you ship: $0.04/W on cells + $0.07/W on modules = $0.11/W combined on integrated production. At 500 MW of annual output, that is $55 million per year at full rates. Your priority actions are: (1) confirm whether your supply chain for polysilicon, wafers, and backsheets involves any FEOC-adjacent suppliers -- Chinese-origin materials are prevalent in the global solar supply chain; (2) elect direct pay for your first five years of claiming the credit, recovering full value without a market discount; (3) start building a transfer relationship in year four so you have a buyer in place when direct pay closes. The phase-down from 2030 to 2032 will compress your credit revenue, but a 500 MW facility still earns meaningful credits through 2032 -- the investment math works even with phase-down modeled in.
A battery cell manufacturer (lithium-ion or iron-phosphate)
Your credit is the largest in absolute dollars per unit: $35/kWh for cells, stackable with $10/kWh for modules if you also assemble. A 2 GWh cell facility earns $70M per year before any module credit. Your main challenges are FEOC compliance -- battery cell manufacturing globally relies heavily on Chinese cathode and anode material suppliers -- and the capital intensity of meeting production scale where credits become financially material. On FEOC: you need a formal supply chain compliance analysis before your first claim. On scale: credits at 2 GWh/year are transformational; credits at 50 MWh/year are helpful but unlikely to finance the facility alone. Battery cell manufacturing has a high minimum efficient scale, and §45X credit economics reinforce that dynamic. If you are operating below 500 MWh annually, the credits are real money but your investment case likely depends more on customer contracts and pricing than on tax credits alone.
A wind component manufacturer (blades, towers, nacelles)
The wind component cliff is your defining strategic constraint. Wind credits expire entirely on December 31, 2027 -- no phase-down, no grace period. If your facility is not at full production before then, the remaining useful life of the §45X credit is shorter than for any other component type. At a 3 GW nacelle facility earning $150,000 per nacelle, the credits are significant -- but only until 2027. Your investment case should not assume credit extensions exist unless Congress enacts them. Build your financial model on a 2027 cliff, treat extensions as upside optionality, and ensure your facility's capital recovery timeline reflects the hard deadline. If you are evaluating whether to break ground on a new US wind component factory in 2026, the two-year credit window (2026-2027) may not be long enough to justify greenfield construction costs. Expansion of existing facilities or brownfield conversions with shorter construction timelines are more likely to have positive credit-adjusted economics under the current statute.
A critical minerals processor (lithium, nickel, cobalt)
Your §45X credit is simpler to calculate -- 10% of qualifying production costs -- and your phase-down schedule is slightly more favorable (expires after 2033, not 2032). At $50M in annual qualifying processing costs, you earn $5M per year. That is real money, but it is also modest compared to the capital costs of a lithium refinery. Your bigger opportunity may be on the customer side: battery cell manufacturers who need FEOC-compliant US-processed mineral inputs are willing to pay premium pricing for qualifying domestic supply. The §45X credit is additive to that pricing premium. If you are a critical minerals processor, your competitive position in the battery supply chain -- and the pricing premium your FEOC-compliant output commands -- is likely a larger driver of your business case than the §45X credit itself. But claim the credit: 10% of costs requires minimal additional compliance effort for a facility already tracking production economics.
An existing domestic manufacturer scaling US production
If you already manufacture eligible components in the US and have been doing so since 2023, you may have unclaimed §45X credits on prior-year production. The credit applies to components sold beginning January 1, 2023 (the IRA's effective date). File amended returns for tax years 2023 and 2024 if you have not yet claimed. The three-year amended return statute of limitations applies, so years 2023 and 2024 remain open through at least 2026 and 2027, respectively. Scaled manufacturers with existing US operations often discover that §45X generates credits far exceeding their current income tax liability -- which makes direct pay planning essential even for established companies. For an existing manufacturer in its first five years of credit claiming, the five-year direct pay window starts at first claim, not at facility commissioning. Check with your tax counsel on how to structure the election going forward if you are still within the five-year window.
Decision trees
Is my product eligible for the Section 45X credit?
Eligibility qualification tree
IF NO: Section 45X does not apply. Installers, developers, and project owners are not manufacturers. Look at §48 ITC for project-side credits.
IF YES: Continue.
IF NO: Section 45X does not apply. Components manufactured outside the US are explicitly excluded, regardless of where they are sold.
IF YES: Continue.
IF NO: No §45X credit is available for your product type.
IF YES: Continue.
IF YES: Credit is disqualified if your company is a specified foreign entity or a foreign-influenced entity. Engage tax counsel immediately.
IF NO: Continue.
IF NO (related-party sale): Credit is generally not available unless 90%+ of the related-party transfer is subsequently sold to unrelated buyers. Consult safe harbor rules.
IF YES: You qualify for the §45X credit. Proceed to Form 7207 and determine whether to use direct pay or transferability.
Should I use direct pay or transferability?
Cash recovery method selection tree
IF NO (year 6 or later): Direct pay is not available for for-profit manufacturers. You must use transferability (§6418) or apply the credit against income tax. Go to transferability analysis below.
IF YES (years 1-5): Continue.
IF YES: Consider transferability -- you receive cash at closing, before filing. Direct pay comes 12-16 weeks after filing. The 5-10% transfer discount may be worth the earlier timing for some businesses.
IF NO: Continue.
IF NO: Direct pay is administratively simpler -- no buyer to find, no transfer agreement to negotiate. Use direct pay.
IF YES: Continue.
IF NO: You cannot use direct pay or transferability for this year if the return is already filed without registration. File the return as a standard non-refundable credit and establish registration for next year.
IF YES: Elect direct pay on Form 7207 and Form 3800. Ensure the election is made by the original return due date including extensions.
How do I structure my supply chain for FEOC compliance?
FEOC supply chain compliance decision tree
IF YES: Engage qualified trade law counsel immediately before claiming §45X credits. The ownership and control analysis under the statute is complex. Do not self-certify FEOC compliance without professional review.
IF NO: Continue.
IF YES for battery materials (cathode, anode, electrolyte) or critical minerals: Review whether the supplier is an FEOC under Treasury's definitions. Country of origin is not the only determinant -- supplier ownership matters. Obtain supplier FEOC certifications and retain them annually.
IF NO or not for covered categories: Continue.
IF YES: That transfer is barred under §6418. Your component sales to that customer are unaffected; use another credit buyer or direct pay.
IF NO: You are in a position to claim. Prepare your annual FEOC compliance certification and retain it with your Form 7207 documentation.
Stacking §45X with the §41 R&D Credit
Here's what you need to know about combining §45X and §41: they apply to different activities and are genuinely stackable. Section 45X rewards production -- the output your factory generates. Section 41 rewards innovation -- the qualifying research your engineers conduct to improve your manufacturing process, develop new products, or solve technical uncertainty. If your R&D team is developing a more efficient solar cell architecture, improving battery chemistry, or engineering a novel inverter topology, those R&D wages and supplies generate §41 credits. When those innovations produce qualifying components that you sell, those sales generate §45X credits. The two credits apply to different dollars of expenditure and different types of activity.
| Feature | §45X (Manufacturing PTC) | §41 (R&D Credit) |
|---|---|---|
| What activity it credits | Production and sale of eligible components | Qualified research activities (wages, supplies, contract research) |
| Dollar basis | Per-unit of components sold | Percentage of qualifying R&D expenditures above base |
| Can activities overlap? | No -- §41 R&D wages are specifically excluded from §45X's credit base (you cannot credit the same dollar of wages twice). But they are different activities: production workers earn §45X credits; R&D engineers earn §41 credits. | |
| QSB payroll-tax offset | Not applicable | Up to $500K/year against payroll taxes (for businesses under 5 years old with under $5M gross receipts) |
| Form used | Form 7207 | Form 6765 |
| Pre-revenue availability | Not applicable (requires sales to unrelated parties) | Yes -- QSB payroll offset works before profitability |
For a manufacturing company with an active R&D program, the combination of §41 and §45X can be substantial. Consider a battery manufacturer with a 100-person engineering team (average fully-loaded cost $200K/person = $20M in qualifying R&D wages) and a 500-person production team at 500 MWh annual output. The §41 credit on $20M of R&D wages at 14% ASC rate generates approximately $2.8M in R&D credits. The §45X credit at $35/kWh on 500 MWh of battery cells generates $17.5M. Neither credit reduces the other's base -- they are genuinely additive.
One important nuance: R&D that is funded by a third party -- a government contract, a SBIR grant, or a customer-funded development arrangement -- is excluded from §41 qualifying research expenses. For manufacturers that also participate in DOE SBIR programs or government contracts, careful segregation of funded vs. internally-funded R&D is required to correctly compute the §41 credit base.
Frequently asked questions
What is the Section 45X credit rate for solar modules?
The §45X credit for solar modules is $0.07 per watt of DC capacity sold to an unrelated party. Solar cells (the individual cells inside a module) earn a separate $0.04 per watt credit. A manufacturer that produces both the cells and the finished module can claim both credits on the same watts of capacity -- a combined $0.11/W for vertically integrated producers.
Can a for-profit company get direct pay under Section 45X?
Yes. Section 45X is one of only three credits (with §45V and §45Q) that for-profit taxpayers can take as direct pay. Under IRC Section 6417(d)(1)(D), for-profit manufacturers can elect direct pay for up to five consecutive tax years of claiming the credit. After that window, they must shift to transferability under Section 6418 or apply the credit against income tax liability.
When do wind component credits expire under Section 45X?
Wind energy components -- blades, nacelles, towers, and fixed-platform offshore wind foundations -- terminate entirely after December 31, 2027. There is no gradual phase-down for wind components: the credit goes from full rate to zero on January 1, 2028. All other components (solar, battery, critical minerals) follow a phased reduction: 75% in 2030, 50% in 2031, 25% in 2032, and 0% after 2032 (critical minerals one year later: 75% in 2031, 50% in 2032, 25% in 2033, 0% after 2033).
Can I claim both Section 45X and Section 48 ITC on the same facility?
Yes. Section 45X and Section 48 operate on different tax bases and are not mutually exclusive. Section 45X applies to the production and sale of manufactured components. Section 48 applies to the investment in clean energy property placed in service at your facility. A manufacturer who installs solar on their own facility can claim Section 48 on the installation cost and Section 45X on the modules they produce and sell to third parties -- these are separate assets generating separate credits.
What is a Foreign Entity of Concern and how does it affect Section 45X?
A Foreign Entity of Concern (FEOC) is an entity owned, controlled, or subject to the jurisdiction of a covered nation: China, Russia, Iran, or North Korea, as defined under the National Defense Authorization Act. Under the 2025 tax law (Pub. L. 119-21), no §45X credit is allowed to a taxpayer that is a specified foreign entity or a foreign-influenced entity, and a component that includes material assistance from a prohibited foreign entity is not eligible, for tax years beginning after July 4, 2025. Before that law, §45X had no foreign-entity rule. Annual compliance review by qualified counsel is essential for manufacturers with any supply chain or ownership ties to covered nations.
What is the Section 45X credit rate for battery cells?
Battery cells earn $35 per kWh of capacity. Battery modules earn $10 per kWh if they contain battery cells, or $45 per kWh if they are "cellless" (using non-cell active materials such as flow battery or sodium-ion chemistries). A manufacturer producing both cells and modules can stack both credits on the same kWh capacity, for a combined $45/kWh on integrated production.
What form do I use to claim the Section 45X credit?
File IRS Form 7207 (Advanced Manufacturing Production Credit) with your federal income tax return for each tax year in which you sell eligible components. If electing direct pay, also file the elective pay election by the return due date. If transferring credits, register through the IRS pre-filing registration portal and execute transfer agreements with buyers before the return is filed.
Does Section 45X require prevailing wage compliance?
No. Section 45X has no prevailing wage or apprenticeship requirements. This is an intentional policy choice to encourage US manufacturing competitiveness. This distinguishes it from Section 48 (ITC), where projects of 1 MW or more must meet prevailing wage rules for 5 years to receive the full 30% credit rate (rather than the 6% base rate).
Can I claim Section 45X credits on components I use myself rather than sell?
Yes, in limited circumstances. The statute allows the credit for eligible components that are "used" by the taxpayer as well as "sold" to unrelated parties. However, the "self-use" credit applies primarily to components used in the taxpayer's own clean energy projects -- not to components held in inventory. Documentation requirements for self-use claims are more complex than for outright sales. Consult qualified tax counsel before claiming self-use credits.
Can I claim Section 45X credits on prior-year production I did not claim at the time?
Yes, by filing an amended return. The §45X credit applies to eligible components sold beginning January 1, 2023. The standard three-year amended return statute of limitations applies, so tax years 2023 and 2024 remain open for amendment through 2026 and 2027, respectively. If you have been manufacturing eligible components since 2023 without claiming the credit, file amended returns promptly -- each year that closes without amendment permanently forfeits that year's credits.