On July 4, 2025, Congress cut the federal investment credit for every kind of on-site generation a factory can buy except one. Wind and solar lose it unless construction starts by July 4, 2026. Gas engines and turbines never had it. Natural-gas fuel cells, which lost theirs at the end of 2024, get it back: Public Law 119-21 section 70513(f) writes a new section 48E(j) that pays 30% of the installed cost of “qualified fuel cell property”, waives the zero-emissions test, allows no wage or apprenticeship condition, and applies to construction beginning after December 31, 2025. For a plant paying $210/MWh in California or $127/MWh in New York City, that paragraph is the difference between a 2.5-year payback and a 1.7-year one; in Ohio it is the difference between never and 16 years.
This piece walks the statute, prices a 10 MW fuel-cell plant against recip CHP and the grid in three states on the actual tariffs, shows where each breaks on gas price, lists every Bloom Energy deal since November 2024, and ends with the states that clear six years and the contract Bloom will sign.
Source: Public Law 119-21 secs. 70512 and 70513; IRC 48E; IRS Notice 2025-42, redrawn by Open Factory
Eight technologies, one row at 30% with no conditions, two at 0%, two with a deadline seven months out: that is the federal incentive map for behind-the-meter power in November 2025.
What Section 48E(j) Actually Says
The Inflation Reduction Act made the credit technology-neutral: a “qualified facility” under 48E(b)(3)(A) needs an anticipated greenhouse gas emissions rate “not greater than zero.” A gas engine cannot pass that, and neither could a Bloom Energy Server on pipeline gas, which is why Bloom’s FY2024 10-K says “the ITC for fuel cells operating on non-zero carbon fuels expired at the end of fiscal year 2024” and that it safe-harbored equipment in 2024 to keep deploying under the old Section 48 credit through 2028.
OBBBA reverses that for fuel cells alone. New 48E(j) says that for qualified fuel cell property “subsection (b)(3)(A) shall be applied without regard to clause (iii) thereof,” that “the applicable percentage shall be 30 percent and such percentage shall not be increased or otherwise adjusted by any other provision of this section,” and that the emissions recapture in subsection (g) “shall not apply.” Section 70513(g)(4) makes it effective for “property the construction of which begins after December 31, 2025.” A factory that starts construction of a gas fuel-cell plant in January 2026 gets 30% of the installed cost back as a federal tax credit; the same plant started in December 2025 gets nothing unless it sits on 2024 safe-harbor equipment. Bloom’s Q3 2025 10-Q reads it the same way.
Three fine points. “Not increased or otherwise adjusted” means no 10% domestic-content or energy-community adders, which storage, geothermal and nuclear can still stack. The credit still phases down with everything else under 48E(e): 100% for construction beginning through 2033, 75% in 2034, 50% in 2035, zero from 2036. And 48E(b)(6) denies the credit to any facility begun after 2025 with “material assistance from a prohibited foreign entity,” a China, Russia, Iran and North Korea test that Bloom’s Taiwan-heavy supply chain does not trip but that your tax counsel will audit.
Wind and solar go the other way. New 48E(e)(4) ends the credit for wind or solar “placed in service by the taxpayer after December 31, 2027,” for facilities that begin construction after July 4, 2026, and IRS Notice 2025-42 removed the 5% safe harbor: only “physical work of a significant nature” counts. Storage is carved out by 48E(e)(4)(C), which is why the Large-Load Cost Table treats a battery as the only credit-eligible way to shave a demand charge in a PJM state.
The Tax Stack on a 10 MW Plant
The credit is not the only tax change. Section 70301 restored 100% bonus depreciation for property acquired after January 19, 2025, and 48E qualified property is 5-year MACRS property under 168(e)(3)(B)(viii), so the whole depreciable basis is deducted in year one. IRC 50(c)(3) reduces that basis by half the credit, so a fuel-cell buyer expenses 85% of cost, not 100%. A recip CHP plant gets the same 100% expensing on 100% of cost and no credit.
Source: Open Factory Datacenter MEP Cost Table (compiled from PL 119-21, EIA AEO2025, Bloom Energy 10-K, PG&E, Con Edison and AEP Ohio tariffs, EIA gas and power prices; as of November 2025)
At $3,500/kW installed, a 10 MW fuel-cell plant costs $35.0M gross; the credit returns $10.5M and year-one expensing of the $29.75M basis is worth $6.25M at 21%, so the owner’s net capital is $18.25M. The $25.0M engine plant expenses all of it for $5.25M and nets $19.75M. After tax, the fuel-cell plant is $1.5M cheaper than the engine plant that costs $10M less on the invoice.
The $3,500/kW is the number to argue about, because Bloom does not publish one. The Datacenter MEP Cost Table brackets it: AEP’s FY2024 10-K shows $430M of 2024 construction spend “driven by expenditures for fuel cell generation assets” against a 100 MW first order, $4,300/kW if every dollar is the Bloom order and its installation, and that is our high case; EIA’s generic 10 MW fuel cell at $7,291/kW (2022$) is a number no data-center buyer has paid and we do not use it; the EPA catalog’s 2014 fuel-cell prices of $4,600 to $10,000/kW make $3,000 a floor. Every input is in data/assumptions.csv with its source, and Quote Check flags a fuel-cell quote outside $3,000 to $4,300/kW installed.
Fuel, Service and the Heat Rate
A Bloom Energy Server 5 is a 300 kW box rated on its datasheet at 65% to 53% electrical efficiency (LHV, cumulative over life), 5,811 to 7,127 Btu/kWh HHV, NOx of 0.0017 lb/MWh, no water, and “exempt from CA Air District permitting.” We use EIA’s 6,469 Btu/kWh, inside that band. A gas engine runs 8,295 Btu/kWh in EIA’s AEO2025 table, 28% more fuel, and recovers about 35% of fuel input as heat per the EPA catalog’s 9.3 MW case.
Service is the fuel cell’s hidden line. Bloom’s FY2024 service revenue was $213.5M on roughly 1.4 GW deployed, about $150/kW-year or $18/MWh at a 95% capacity factor; EIA’s $34.65/kW-year is a quarter of that and we do not believe it. Stack replacements sit inside the service agreement, behind $588.1M of capped performance guarantees. The engine gets EIA’s $39.57/kW-year plus $8/MWh for oil, plugs and SCR catalyst, about $13/MWh.
Source: EIA natural gas citygate prices by state (N3050), FRED MHHNGSP via Open Factory Datacenter MEP Cost Table
Over October 2024 to September 2025 Henry Hub averaged $3.20/MMBtu while the EIA citygate averaged $5.67 in New York, $5.74 in Ohio, $3.86 in California and $3.68 in Texas. We add $1.00/MMBtu of firm transport ($1.50 in California, where the gas also carries a cap-and-trade compliance cost) for delivered prices of $5.36, $6.67 and $6.74. At those prices the fuel cell burns $34.7/MWh of gas in California, $43.1 in New York and $43.6 in Ohio; the engine burns $44.5, $55.3 and $55.9 before its heat credit.
Three Tariffs, One Flat Load
The grid side is where most on-site power models cheat, so each state’s bill is built from the tariff a 10 MW flat load saw in the fourth quarter of 2025.
Source: Open Factory Datacenter MEP Cost Table (compiled from PG&E B-20, Con Edison PSC No. 10, AEP Ohio PUCO No. 22, EIA-861M; as of November 2025)
California is $209.5/MWh all in, of which $81.1 is demand charges; New York City is $127.4 with $33.3 of delivery demand and $11.1 of capacity; Ohio is $87.5 with $25.8 of demand and transmission.
California: PG&E Schedule B-20 at primary voltage, September to December 2025, bills $36.18/kW every month on maximum demand plus $51.93/kW on summer peak and $10.57/kW on summer part-peak: $7.1M a year on a flat 10 MW, $81/MWh, before a kilowatt-hour is bought, and TOU energy adds $128/MWh. The $209.5/MWh total sits within 3% of EIA’s California industrial average of 21.61 c/kWh, our check that the load shape is not rigging the answer.
New York: Con Edison SC 9 Rate II high-tension delivery bills $11.33 plus $22.82 per kW of maximum demand in June through September, $19.41/kW the other eight months, and $0.0079/kWh. Capacity comes through the Market Supply Charge at $8.13/kW-month in the November 2025 statement. Supply energy is the one number we assume: Con Ed’s NYISO index price for NYC averaged 10.3 c/kWh from July to November 2025 with capacity embedded, and we take 6.5 c for a flat load plus $10/MWh of riders. The statewide EIA figure for New York, 9.52 c/kWh, is an upstate number; a Queens plant does not see it.
Ohio: AEP Ohio Schedule GS primary bills $8.08/kW of demand plus a $10.79/kW Basic Transmission Cost Rider, and the Generation Capacity Rider passes PJM’s $329.17/MW-day 2026/27 price through at 1.607 c/kWh. We take EIA’s Ohio industrial price for September 2025, 8.75 c/kWh, as the all-in; the PJM Capacity Charge Estimator puts the capacity piece alone near $12,000 per MW-month for a plant that peaks with the RTO, and the Large-Load Interconnection Cost tool prices the alternative of asking AEP for more service.
Standby Is the Line Bloom’s Brochure Skips
An on-site plant does not remove the utility; it changes what you pay it for. In California and New York a natural-gas fuel cell pays full standby rates, and the New York exemption most buyers remember was rewritten to exclude it.
PG&E’s Schedule S charges a reservation fee of $17.17/kW-month at primary voltage on 85% of reservation capacity, $1.75M a year on 10 MW or $21/MWh of output, and bills outage energy at standby TOU rates that reach $1.3265/kWh on summer weekday afternoons; at a 5% outage rate and our hours-weighted $290/MWh that is another $1.27M. Together they cost the California plant $36/MWh, more than its gas.
Con Edison’s General Rule 20.3.2 exempts “Customers With Designated Technologies” from standby rates, but the 2019 order in Case 15-E-0751 narrowed that to “fuel cells which do not utilize a fossil fuel resource in the process of generating electricity” and closed the efficient-CHP exemption to units of 1 MW or less in service by May 31, 2021. A 10 MW Bloom plant on pipeline gas in Queens lands on SC 9 Rate IV: a contract demand delivery charge of $4.31/kW-month at high tension ($9.88 low tension) plus as-used daily charges of $0.71 to $0.85/kW-day when it draws. We carry $0.77M a year, $9/MWh.
Ohio is the gap in the record: AEP Ohio routes self-generators to Schedule SBS, whose sheets are not in the posted book, so we assume half of the $18.87/kW-month demand and transmission charges survive. State money is gone too. California’s SGIP still lists fuel cells and pays a $2.00/W generation incentive, but section 7.4 of the 2025 handbook requires “100% renewable fuel for the lifetime of the project,” and NYSERDA’s 2025 fuel-cell money ($3.7M) is hydrogen only. The 30% federal credit is the last subsidy standing, and the only one that does not care what the fuel is.
Payback by Gas Price
Source: Open Factory Datacenter MEP Cost Table
At the state’s own delivered gas price the fuel cell with the credit recovers its $18.25M in 1.7 years in California, 3.7 in New York City and 16.1 in Ohio; without the credit, 2.5, 5.6 and 24.4 years. Ohio clears six years only at $3.00/MMBtu delivered, a price its citygate has not touched since 2024.
The mechanism is simple. In California the plant displaces $18.35M of PG&E bills with $2.89M of gas, $1.5M of service, $1.75M of standby reservation and $1.27M of top-up, saving $10.9M a year. In New York City it saves $4.9M against an $11.2M bill. In Ohio it saves $1.1M against $7.7M, because the fuel cell’s fuel, service and standby alone run $78/MWh against an $87.5 grid. The Genset TCO tool reproduces these cash flows for any gas curve; data/payback-by-gas-price.csv has every point.
The engine is the honest surprise. At the state gas price recip CHP pays back in 1.8, 3.6 and 11.4 years, tying the fuel cell in California and beating it by a month in New York, because $2,500/kW with full expensing is cheap capital and using 60% of the recovered heat is worth $12 to $15/MWh. Take the heat away, at a plant with no year-round thermal load, and the engine’s New York payback stretches to 4.6 years and its levelized cost to $102/MWh, above the fuel cell. Then add permitting: a lean-burn engine sits at 3.05 lb NOx/MWh at the NSPS floor before SCR against the fuel cell’s 0.0017, and in the Bay Area or Los Angeles basin that is offsets, BACT and a year. The Lead-Time-Adjusted Schedule carries 16 to 18 months for a fuel-cell delivery against 24 to 30 months for a new large engine, per the dealer allocation in Cummins and Caterpillar Are Sold Out Through 2028, and the Lead-Time Monitor has the switchgear and transformer that both plants still need at 44 and 128 weeks.
Fifteen-Year Cost per MWh, Three Ways
Source: Open Factory Datacenter MEP Cost Table
Levelized over 15 years at 8%: California $209.5/MWh on PG&E, $108.9 with fuel cells, $109.6 with engines; New York City $127.4, $95.4 and $89.0; Ohio $87.5, $98.9 and $92.0.
The fuel cell’s levelized number decomposes cleanly: $24/MWh of net capital recovery, $18 of service, $35 to $44 of gas, and $9 to $36 of standby and top-up depending on the utility. Without the credit the capital line is $46/MWh and the fuel cell loses to the engine in every state and to the grid in Ohio by $24/MWh. Ohio is the case to remember because it is where AEP put the first 100 MW: as a time-to-power product sold to data centers at a premium, not as a bill-cutter at $87.5/MWh. And that route is closed to newcomers. AEP’s Q3 2025 10-Q reports that Ohio House Bill 15 “repeals the statute that permits electric distribution utilities, including OPCo, to execute contracts to provide customer-sited renewable generation service such as fuel cell technology” after August 14, 2025, grandfathering only two PUCO-approved contracts of about 98 MW now before the Ohio Supreme Court. An Ohio factory buys its own or signs with Bloom; the Large-Load Policy Tracker carries the docket.
Sensitivity is where to spend your skepticism. At $3,000/kW installed the paybacks are 1.4, 3.2 and 13.8 years; at $4,300/kW they are 2.0, 4.5 and 19.8 (data/sensitivity-fc-capex.csv). Doubling service to $300/kW-year adds $18/MWh. What does not move is the ordering: California always clears, Ohio never does at today’s gas, and New York City clears with the credit and is marginal without it.
Bloom’s Order Book Without a Price
Source: Bloom Energy press releases; AEP 10-K FY2024 and 10-Q Q3 2025, redrawn by Open Factory
Six named counterparties, one gigawatt of option, one 15-year factory PPA, and the only dollar figure that lets anyone infer a unit price is AEP’s $430M of 2024 construction spend against a 100 MW first order.
The deals are real and the disclosure is thin. AEP’s 100 MW with an option to 1 GW (November 14, 2024), Equinix passing 100 MW across 19 sites, Oracle with no megawatts stated and Brookfield’s $5 billion all came without a price. The one factory deal, Conagra’s 15-year PPA for about 6 MW covering 70 to 75% of two Ohio food plants, is, tellingly, a PPA rather than a purchase.
The financials say the pricing is firm. Bloom’s Q3 2025 release reported revenue of $519.0M, up 57.1%, gross margin of 29.2% against 23.8% a year earlier, and its first positive GAAP operating income at $7.8M; the 10-Q credits “improved pricing” and says the factory goes from 1 GW to 2 GW a year by the end of 2026. A vendor with rising margins, a doubling factory and a new 30% subsidy that lands on its customer’s tax return does not cut price in 2026; the buyer’s lever is structure, not discount. The OEM Disclosure Scorecard grades Bloom on the $/kW question in December.
What to Do Monday
Do not start construction in December. The 30% credit attaches to property whose construction begins after December 31, 2025, and under the physical-work rules a binding contract with off-site manufacturing under way is a start; if you sign in December, write the contract so the manufacturer’s work begins in January, and put the 48E(b)(6) prohibited-foreign-entity representation in the same document.
Pull your last twelve bills and split them the way the bill-anatomy chart does: energy, demand and transmission, capacity, riders. If demand and transmission are under 25% of the bill and your all-in is under $100/MWh, you are Ohio, and the fuel cell does not pay unless someone else is paying for it. If you are above $120/MWh with a flat load, run the Datacenter MEP Cost Table case with your own gas transport tariff and your utility’s standby schedule, not the vendor’s. If the reason you are looking at on-site power is a service upgrade you cannot get, price the wait first: the Large-Load Cost Table carries the study fees and energization years by utility, as laid out in October’s launch piece, and a 143-week transformer is the reason a 16-month fuel cell is being bought at all.
Then get the standby sheet from the utility before the quote from Bloom. It is $21/MWh at PG&E and $9/MWh at Con Ed high tension, and it is the number the brochure leaves out.
Behind the paywall: the two states where a factory clears a six-year payback on fuel cells today, a 12-state ranking with and without the credit, and the four contract forms Bloom sells, with the terms to demand in each, from the Datacenter MEP Cost Table.