Generate It Where We Live: Local Solar + Storage

Instead of building a 150-mile, 500 kV line to haul desert power to the coast, build more clean power where it's actually used — on rooftops, over parking lots, and at community-scale sites near the cities that consume it, paired with batteries. Planners call this a “non-wires alternative”: a portfolio of local resources that meets demand without carving a new corridor through Temecula Creek. ^[1]

Be honest about the framing up front. This isn't the claim that one rooftop is cheaper than the wire — at today's prices, putting solar on a million-plus homes would cost more than the line's roughly $2.3-billion sticker. ^{[2] [3]} The real case is what the money buys, how the costs run over decades, and a fact most people don't know: a large share of this power is already being generated locally — and the cheapest new generation on the grid is local solar, not a long-distance line. The rest of this page works through those numbers. ^{[4] [5]}

Start with the load. By the grid operator's own account this line serves San Diego and the Los Angeles basin, not Temecula — its coastal end is a new substation north of San Onofre in Orange County, feeding SDG&E's territory of San Diego County and southern Orange County: about 3.7 million people across 1.52 million electric meters, who together used 16,847 gigawatt-hours of electricity in 2023. ^{[2] [4]}

And these are among the lightest power users in the country. SDG&E's mild coastal climate and California's efficiency standards put the average home at roughly 490 kilowatt-hours a month — about 5,900 a year, close to half the U.S. average of 899 kWh a month — a fact SDG&E states in its own SEC filings. ^{[6] [4]} The size of the load decides how much local generation it takes to serve it, and a region that sips power is one rooftop and community solar can realistically supply.

It also reframes the headline you'll hear — that a 500 kV line “serves a million homes.” That's a peak-capacity rule of thumb (roughly one kilowatt of demand per home at the system's peak), not a measure of the energy delivered year-round. A line carrying intermittent desert solar runs well below its rating most of the time, so on an annual-energy basis it serves far fewer homes than the headline implies. ^{[7] [6]}

Here is the number that reframes the debate. In its 2023 annual report to the SEC, SDG&E's parent company discloses that customers in SDG&E territory have already installed 2,154 megawatts of rooftop solar — up from 1,620 MW just two years earlier, growing by roughly 250 to 290 MW a year. ^[4] A single 500 kV line is generally rated to carry about 1,000 to 1,500 MW. ^[7] In other words, the solar already sitting on local roofs is in the same range as — and likely exceeds — what this entire new line would carry. It was built with no new corridor, no towers through Temecula Creek, and no eminent domain.

And the roof is nowhere near full. The National Renewable Energy Laboratory's rooftop study finds U.S. rooftops could host more than 1,100 gigawatts of solar — over a thousand times a single line's capacity — and ranks San Diego among California's top counties for both rooftop potential and installed solar. ^[8] The local resource isn't theoretical; it's already the largest clean-energy build in the region, and most of it is still untapped.

Now the cost of building more. Each year the financial advisor Lazard publishes the benchmark the industry uses — the levelized cost of energy, the all-in cost per megawatt-hour over a project's life. In its 2024 edition, utility-scale solar is the cheapest power source there is, at $29 to $92 per MWh; even paired with four-hour battery storage it runs $60 to $210. Community- and commercial-scale solar costs $54 to $191, and residential rooftop $122 to $284. ^[5]

Read honestly, those numbers point to a portfolio, not a slogan. Rooftop-only would be the most expensive way to do it; the lowest-cost local build is mostly utility-scale and community solar sited near the coastal load, firmed with storage, with rooftop adding what it can on top. That's exactly the mix the non-wires-alternative case rests on — and independent lab data backs the price: Lawrence Berkeley National Laboratory finds utility-scale solar actually built in 2023 came in around $1.43 per watt, down about 75% since 2010. ^{[5] [9]}

The line's cost isn't its sticker, either. A transmission line is paid for the way all regulated infrastructure is: ratepayers don't just repay the capital, they pay a guaranteed return on it, plus depreciation, operations, and taxes, every year for its roughly 40-year life. Run that standard cost-of-service formula on this ~$2.3-billion line and ratepayers pay on the order of $7–8 billion over its lifetime — far more than the headline. ^{[10] [2]} (We work that math out in detail on Who profits, and why this line?)

There's also a quieter cost: distance. Hauling power 150 miles from the desert loses a few percent of it to resistance in the wires before it reaches a single home — energy ratepayers still pay for. Solar generated on a local roof or substation delivers at the meter, with essentially none of that loss. ^[11] When a utility compares the two options properly, it doesn't compare stickers — it compares the line's annual revenue requirement, in dollars per kilowatt-year, against what the same reliability would cost from a local portfolio. On that basis the gap narrows sharply, and often flips.

Put it all together. Serving the coastal load means paying for the clean power either way — and that part is close to a wash, because both options are mostly solar. The difference is everything built around it. Bring the power from the desert and ratepayers also buy a $2.3-billion line, pay its guaranteed return for forty years, and lose about 3% of the energy hauling it 150 miles. Generate it near the coast and there's no line to build and nothing lost in transit. ^{[10] [11]}

Run that over the line's life and the gap is real money. On illustrative midpoint costs, the line path runs on the order of $13–14 billion over 40 years; the local solar-and-storage path — even paying more per megawatt-hour for local siting and batteries — lands near $11 billion, roughly $3 billion less, more than the line's entire sticker price. The exact numbers move with the assumptions; the direction doesn't, and a peer-reviewed national study reaches the same conclusion. ^{[5] [14]}

That comparison is deliberately narrow — it counts only what ratepayers pay for the wire and the power. It leaves out the costs the line forces on the communities it crosses, which local generation avoids entirely: the wildfire-ignition risk of a new energized line through a Very High fire-hazard corridor, the higher home-insurance and FAIR Plan premiums that fire country brings (Riverside County's last-resort policies are up about 509%), the documented hit to property values along a transmission easement, the threat to a nearly $1-billion-a-year wine-country tourism economy built on the very scenery the towers would alter, and the health, viewshed, and habitat impacts detailed across this site. Every one of them lands on Temecula — not on the San Diego and Orange County customers the line serves. ^{[16] [17] [18]}

And the tail risk dwarfs the whole chart. SDG&E's own 2007 power-line fires cost about $2.4 billion to settle — roughly the line's entire sticker price — and a single transmission fire, the 2018 Camp Fire, caused around $16.5 billion in damage, more than the line's full 40-year cost. A line strung through fire country carries that risk every year; local rooftops and substations don't. We can't put a precise figure on these costs, but they push the real gap between the two paths far wider than the chart can show. ^{[19] [20]}

Two caveats run the other way, in fairness. Building all that local capacity takes more cash upfront than the line's sticker — the ratepayer savings are a lifetime result, not a day-one one — and the real world is messier than any straight line. But the direction holds: the line is a cost, and a risk, that local generation simply never takes on. ^[14]

This isn't advocacy math — it's the test California's own regulator runs. The CPUC's Avoided Cost Calculator values distributed solar and storage across everything they offset, including transmission and distribution capacity, and a local portfolio qualifies as a cost-effective “non-wires alternative” whenever its cost comes in below the avoided cost of the wires project it would replace. ^[12]

And it has just happened, to an identical kind of line. In its 2025–2026 plan, California's grid operator canceled a brand-new 500 kV line in the Los Angeles Basin — one it had approved three years earlier — after updated costs came in, and met the same reliability need instead with battery storage and a small upgrade to an existing line. What won was storage and a cheap fix to the grid that already exists — not a new long-distance line. The same scrutiny should apply here; the state denied a 500 kV line in this very corridor once before. ^[13]

Zoom out and the conclusion holds at grid scale. A peer-reviewed optimization study found that the lowest-cost path to a clean U.S. grid by 2050 includes about 247 GW of local solar and 160 GW of local storage — saving ratepayers roughly $473 billion versus a transmission-and-utility-scale-only build. Generating closer to home isn't just lower-impact; at scale it's cheaper. ^[14]

If local is so competitive, why is the state building the line instead? Part of the answer is how utilities earn money — they profit on the capital they build and own, and earn nothing when you put panels on your roof (the full story is on “Who profits”). And state policy has pushed the same way: in 2023 California cut the credit for exported rooftop-solar power by roughly 75–80%, and home-solar sales fell by more than half. ^[15] The local option keeps getting cheaper, and keeps getting discouraged.

We'll be straight about the limits of this argument. Rooftop solar alone is not cheaper than the line, and solar doesn't shine at night — a serious local alternative needs storage and a real mix of distributed and utility-scale generation, which is what the numbers above describe. Some long-distance transmission will still be needed to hit California's 2045 clean-energy goal, and demand may rise with electric vehicles and electrification. ^[1] The claim here is specific: for this load, in this place, a local solar-and-storage portfolio can meet much of the need at competitive lifetime cost and a fraction of the footprint — and the law requires that option be studied seriously before a new corridor is carved through Temecula.