Solar for California Farms and Agricultural Operations

Irrigation Load Doesn't Behave Like a Rooftop Load

A house draws power fairly evenly across the year. A pump doesn't.

Central Valley irrigation runs hard from roughly April through September and drops to near-zero the rest of the year, which is a terrible match for a standalone solar system sized against that one meter's usage — you'd be paying off a system that sits mostly idle five or six months a year.

The fix isn't a bigger array at the pump. It's combining the pump's seasonal peak-season draw with steadier year-round load elsewhere on the operation — a home, a packing shed, an office meter — so the system has something to offset in the off-season too.

That's the entire logic behind meter aggregation, covered in detail below, and it's the first question a farm should answer before sizing anything: how many meters, on what parcels, with what load profile, can legally be combined onto one interconnection.

The other structural fact worth knowing going in: California's agricultural water use is under real pressure from the Sustainable Groundwater Management Act, and research by EPIC scholars at the University of Chicago finds California farmers are roughly ten times more price-responsive to electricity costs than typical residential customers — cutting usage 7.6% for every 10% rate increase in the short run (elasticity of -0.76).

About half of that response persists long-run (elasticity of -0.37), reflecting permanent crop-switching and fallowing rather than pure temporary conservation. That elasticity is the clearest evidence that ag electricity costs are already a load-bearing part of farm economics, not a rounding error.

PG&E Agricultural Rate Schedules: AG-A, AG-B, AG-C

PG&E ag customers sit on one of several time-of-use schedules, and the differences matter for how solar offsets your bill. AG-A-1/A-2 and AG-B are straight per-kWh time-of-use rates with no demand charge: summer (June-September) peak hours run 5pm-8pm daily. AG-B's summer peak generation rate is $0.22830/kWh, dropping to $0.11482 off-peak in summer and further to $0.08573 in winter off-peak.

AG-A runs slightly lower across the board — $0.21359 summer peak down to $0.07579 winter off-peak.

AG-C adds a demand-charge component (a separate fee based on your peak kW draw, not just kWh consumed) in exchange for a flatter, somewhat lower per-kWh rate: $0.12733 summer peak, $0.09999 summer off-peak. That structure tends to suit operations with large, continuous pump draw rather than short sharp peaks.

One caveat that matters if you're comparing quotes: these figures are the generation charge only, from a Community Choice Aggregator's published comparison sheet dated February 15, 2026.

PG&E's own delivery (transmission and distribution) charges, plus a PCIA "exit fee" that ranges from roughly -$0.0094/kWh (a credit, for newer-vintage accounts) to a small positive charge for older-vintage accounts, get added on top.

Your all-in bundled rate will run higher than the generation numbers above — ask your PG&E rep or installer for your account's actual all-in ag rate before finalizing system size.

A second caveat: the source document is at the cited URL with the stated February 15, 2026 effective date, but its PDF has no machine-readable text, so check the individual digits above against it — treat them as a starting point sourced from that document, not a substitute for pulling the actual rate sheet or asking PG&E directly before finalizing payback math. Older legacy schedules (AG-1, AG-4, AG-5, AG-R, AG-V) were phased out for new enrollment starting March 2021; if you're still on one, you're likely grandfathered and should not assume these current AG-A/B/C numbers apply to your bill.

SCE Agricultural and Pumping Rates: TOU-PA-2 and TOU-PA-3

SCE's agricultural and pumping schedules work on a different structure than PG&E's. TOU-PA-2 covers demand under 200 kW; TOU-PA-3 covers 200-500 kW, with special provisions above 500 kW for water agencies.

To qualify, at least 70% of your electricity use has to go to agricultural power service, water or sewage pumping, or oil pumping — no meaningful domestic-purpose load allowed on the balance.

SCE gives ag and pumping customers two structural choices. Option D charges both a time-related demand charge (based on your peak-period draw) and a facilities-related demand charge (based on your monthly maximum demand regardless of time), in exchange for lower energy rates.

Option E drops the time-related demand charge entirely in exchange for higher per-kWh energy rates — which tends to be the better fit once you add solar and battery storage, since it avoids penalizing whatever peak draw still happens after your system covers what it can.

Ag and pumping customers also get to choose their on-peak window: either the standard 4pm-9pm commercial window or a narrower 5pm-8pm ag-specific window.

Winter includes a super-off-peak window from 8am-4pm weekdays — the cheapest power of the year, and it lines up almost exactly with when solar panels produce, which is the best midday offset opportunity on the whole rate structure.

This page does not give SCE's current cents-per-kWh figures for TOU-PA-2/TOU-PA-3 — the fact sheet describing this structure carries a 2018 print code and no dollar figures, so get them from SCE's current tariff book. Don't quote a specific SCE ag rate as fact; pull the current tariff book at sce.com/tariffbooks or ask your account rep for the number before running payback math.

NEM Aggregation: One Array, Multiple Meters

Net Energy Metering Aggregation (NEMA), authorized by SB 594 in 2012, is the single most important mechanism on this page. It lets a customer-generator combine load from multiple meters — on properties they own, lease, or rent — as long as those parcels are attached, adjacent, or contiguous, with one solar system offsetting the combined total. The system is capped at 1 MW.

Without aggregation, a farm with a home meter and three separate irrigation pump meters would need to either pick one meter to serve (leaving the others on full retail rates) or build four separate small systems, each sized against a load profile that spikes for five months and sits flat the rest of the year — an expensive and inefficient way to build.

With aggregation, all four meters count as one load, and the system gets sized against the combined annual profile, which is what makes the economics work at all for seasonal pumping.

One trade-off worth knowing before you elect aggregation: doing so permanently forfeits eligibility for Net Surplus Compensation (NSC), the separate credit paid for surplus generation at year's end — not a decision to make lightly if your system is likely to run a large annual surplus.

You may read that AB 942 (2025-26) moves a buyer of property with an existing NEM 1.0 or 2.0 system onto newer compensation terms, with a carve-out for farms. It is not law. The Senate amended the bill on July 17, 2025 so that it deals only with the California Climate Credit, and it has not moved since August 29, 2025, when it was sent to the Senate Rules Committee (California Legislative Information, AB 942 history, checked September 24, 2026). A farm that buys land with an existing system should ask its utility which tariff the account moves to.

USDA REAP Grants: Paused, Not Dead

This is the fact that changes the financing conversation for 2026. USDA announced on April 1, 2026 that it was rescinding the October 2024 REAP funding notice and halting new grant awards, to comply with Executive Order 14315, which targets what the order calls market-distorting subsidies for renewable energy.

As of August 2026, USDA's own program page still showed grants not accepting applications, and nothing published since indicates a reopening date.

Applicants who already submitted before the pause are expected to get a chance to reapply once new program rules are finalized, but USDA has given no timeline — the agency has called the new regulations "a top focus," which is not the same as a date. A new Notice of Funding Opportunity is expected to follow whenever those rules land.

What's still open: REAP guaranteed loans, processed year-round through local USDA Rural Development offices, unaffected by the grant pause.

On the caps that applied before the pause — solar projects capped at $1 million, energy-efficiency grants capped at $500,000, cost-share up to 25% under Farm Bill funding and up to 50% under now-expired IRA funding — treat these as last-known terms, not confirmed terms for whatever program eventually reopens.

USDA Secretary Rollins has separately signaled intent to discourage ground-mounted solar on productive farmland, which could mean tighter eligibility or lower scoring for exactly the kind of ground-mount ag system this page discusses, once a new NOFO is published. Don't build a financing plan around REAP terms carrying forward unchanged.

What Farm-Scale Solar Actually Costs (and What We Don't Know Yet)

No primary source publishes a California price for a farm-scale ground-mount array.

The closest primary figures are national: LBNL's Tracking the Sun (2024 Edition) put 2023 installed prices for small non-residential systems (100 kWdc or less) at $2.50 to $4.30 per watt and for large non-residential systems (over 100 kWdc) at $1.70 to $3.10 per watt, 20th to 80th percentile, national.

LBNL's large non-residential category includes ground-mounted systems, and farm arrays in the tens of kilowatts to megawatt range fall across both bands, so extrapolating from a residential rooftop quote to a 250 kW ground-mount system would be guessing dressed up as data.

Separately, if what you actually need is a dedicated solar-powered pump rather than a grid-tied array feeding your existing electric pump under NEM, that's a different product category with its own pricing; no primary source publishes it.

Get a written, itemized quote from a CSLB-licensed installer sized against your actual acreage and load before budgeting off any number you find online.

SGMA, Fallowed Land, and the New Solar-on-Farmland Opening

The Sustainable Groundwater Management Act is reshaping Central Valley land use whether or not a given farm ever installs solar.

Groundwater basins must hit sustainability targets by 2040 or 2042 depending on basin priority, and the Public Policy Institute of California estimates 500,000 to 900,000 acres of San Joaquin Valley farmland — roughly 10 to 20 percent of the valley's irrigated footprint — may need to come out of full irrigation to meet those targets, with the lower end assuming new water supplies materialize and the upper end assuming they don't.

That pressure is opening a real, if still-forming, path: converting land that has to come out of active irrigation anyway into solar generation instead of leaving it fallow and unproductive.

AB 1156 would not end the Williamson Act cancellation fee, which stays at 12.5% of the land's cancellation valuation. It would let the Secretary of the Natural Resources Agency defer the fee by 10 years when a contract is cancelled to build a solar facility on land in a critically overdrafted groundwater basin, and the developer has a community benefit agreement with the local government. If a solar project is built before the 10 years run out, the Secretary must waive the payment. That part of the bill would expire January 1, 2037 (AB 1156, enrolled text).

The Legislature sent it to the Governor on September 14, 2026; it is not law unless he signs it. If this matters to your land-use planning, check the bill's status on leginfo.legislature.ca.gov before counting on it.

This is a land-use opportunity for acreage coming out of production, not an argument for putting solar on land you're still actively farming. If your fields are fully in production and staying that way, this section doesn't apply to you yet.

Batteries and Timing Under Ag Rate Schedules

The economics of adding battery storage to an ag solar system come down to matching your rate schedule's structure to your pump schedule. On PG&E's AG-A/AG-B/AG-C schedules, the 5pm-8pm peak window is exactly when a battery earns its keep — storing midday solar production and discharging it into the highest-priced hours instead of exporting it at low net-billing credit rates.

On SCE's TOU-PA-2/3 schedules, choosing Option E (no time-related demand charge) removes the penalty for whatever peak draw remains after solar and battery cover what they can, which matters if your pumps sometimes have to run into the evening during peak irrigation weeks regardless of price.

One structural note that applies statewide, not just to ag accounts: publicly owned utilities — LADWP, SMUD, MID, Anaheim, Roseville, Lodi, Imperial Irrigation District, Turlock Irrigation District — are not subject to CPUC net billing rules at all and set their own export terms.

If your operation is served by one of these rather than PG&E, SCE, or SDG&E, none of the NEM 3.0/net billing urgency in this page applies to you directly; check your own utility's ag rate schedule and export terms instead, since they can differ substantially from the investor-owned utility structures described above.