On a clear day, the summit of Mt. Diablo looks straight down on the Sacramento–San Joaquin Delta. Most people up there are looking at the view. But the rock layers under your feet on the way up, the same ones that once fed California's biggest coal field, bend down under that Delta and hold California's largest dry gas field. Today, the emptied-out gas fields around the mountain store the fuel that keeps Northern California warm in winter.
This post walks through that story in four steps: how Mt. Diablo formed, how one sandstone ended up as coal mines on the mountain and a gas reservoir under the Delta, how those gas fields became Northern California's winter storage, and why that storage still moves PG&E Citygate prices today.
How did Mt. Diablo form?
Mt. Diablo is young for a mountain. It began to take shape about 2 million years ago, and most of its uplift happened in the Quaternary, the last 2.6 million years, according to California State Parks' geology guide and a 2021 USGS study of the mountain's framework by Russell Graymer and Victoria Langenheim.
Three groups of rock make up the mountain:
- The core is old seafloor: the Franciscan Complex, a jumble of rock scraped off an ocean plate, and an ophiolite, a slice of oceanic crust and upper mantle.
- Around the core sit thousands of feet of sandstone and shale from the Great Valley sequence, laid down in shallow seas from the Cretaceous into the Eocene and later.
- On the outer edges are younger sediments, including the fossil-rich Miocene and Pleistocene beds.
A buried "blind" thrust fault under the mountain pushed the core upward, folding the sedimentary layers over it like a rug pushed against a wall, as Wikipedia's summary of the mountain's geology explains. Erosion stripped the top, so the oldest rock now sits near the summit and the layers on the flanks are tilted steeply away from it. The mountain is still rising, squeezed between the Greenville and Concord faults.
That tilting is the key to everything else in this post. The layers that stick up out of the ground on Mt. Diablo's northeast side keep going. They dip down under Antioch and Brentwood and lie thousands of feet beneath the Delta.
One sandstone, two jobs: coal on the mountain, gas under the Delta
The star of this story is the Domengine Formation, an Eocene sandstone about 50 million years old. It was laid down in shallow estuaries along an old coastline, and plant-rich swamps along that shore became coal.
On Mt. Diablo: coal and glass sand
Where the Domengine reaches the surface on the mountain's north side, it carried the coal seams of the Mount Diablo coal field. Miners worked those seams from the 1860s into the early 1900s and pulled out roughly 4 million tons of low-grade coal, according to the East Bay Regional Park District. It was California's most productive coal field. From the 1920s to the 1940s, miners went back for the sandstone itself, which was clean enough for glassmaking and foundry casting. The old mining towns of Nortonville and Somersville are now part of Black Diamond Mines Regional Preserve.
Under the Delta: a gas reservoir
Follow the same Domengine northeast and it goes underground. By the time it reaches the Delta it is buried thousands of feet deep, sealed under shale, and full of gas. At the Rio Vista gas field, the Domengine is a major gas-bearing unit, and an AAPG paper on the field's history notes that the Domengine and Margaret Hamilton sands produced most of the field's gas. Other pay zones carry names you will recognize from the mountain: the Nortonville and the Markley.
The cross-section above shows the idea. On the left, the uplift has tipped the layers up and eroded them, so the Domengine is at the surface where it was mined. On the right, the same layers arch over a buried dome at Rio Vista, and gas rising from below gets caught at the top of that dome under shale seals.
Where does the gas come from?
Sandstone holds gas; it does not make it. Geologists suspect the gas under the Delta came from the Winters Shale, a Cretaceous source rock deeper in the basin. The USGS describes it as gas-prone, generating mostly methane, though it notes the chemical evidence is not conclusive. Gas generation in the Delta area started about 70 to 80 million years ago. The gas then moved upward along faults and porous sands until it hit a trap.
The result is unusually pure gas. The same USGS chapter reports that gas in the southern Sacramento Valley fields runs 99 to 99.99% methane. That is why Rio Vista is called a dry gas field: it produces almost no oil or heavier liquids, just pipeline-ready methane.
Rio Vista: California's largest dry gas field
Amerada Petroleum drilled the discovery well, Emigh No. 1, in June 1936. The field turned out to be a large dome cut by the north–south Midland fault, which offsets the Domengine by up to 500 feet, according to Wikipedia's field history. The field covers more than 29,000 acres under parts of Solano, Sacramento and Contra Costa counties, and its gas pools range from about 2,450 feet to 9,600 feet deep, with some wells producing from even deeper sands.
World War II made Rio Vista. With oil tankers pulled into the war effort, the pipeline that had carried gas from Kettleman Hills to the Bay Area was converted to carry oil, and the Bay Area suddenly needed gas from somewhere closer. Rio Vista filled the gap. By late 1944 it had 70 active wells, and production peaked in 1945 at more than 160 billion cubic feet (Bcf) for the year.
| Year | What happened |
|---|---|
| 1936 | Emigh No. 1 discovers the field |
| 1944–45 | Wartime boom; 70 wells by late 1944 and a peak of 160+ Bcf in 1945 |
| 1965 | Most of the field is unitized under one operator |
| Late 1990s–2000s | Calpine buys most wells and raises output from about 40 to 100 MMcf/d |
| 2010s–today | Mature field worked by smaller operators, with some deeper sands still being tested |
Over its life Rio Vista has produced more than 3.6 trillion cubic feet (Tcf), and the AAPG puts ultimate recovery at almost 4 Tcf. Natural Gas Intelligence reported that Calpine's work in the 2000s lifted output to about 100 million cubic feet per day (MMcf/d), still far below the field's historic peak of roughly 500 MMcf/d. Smaller companies still drill and rework wells there. In 2016, Royale Energy used 3-D seismic to find gas in deeper Martinez sands, and more recently Sacgasco restarted production after buying a pipeline from PG&E.
Brentwood: the oil field at the foot of the mountain
Closer to the mountain, the Brentwood oil and gas field was discovered in June 1962. Its Paleocene and Cretaceous sands tilt gently north and are cut off by an old erosion surface, with a shale on top acting as the seal. That north tilt reflects the same long history of uplift and erosion around the mountain. The field went on to produce almost 10 million barrels, the most of any oil field in Northern California, according to Bay City News. By 1992 the wells were producing almost all water, and the field was abandoned in the 1990s. Some of the old wells still vent methane through lamp-post-style vents in the housing tracts built on top of it, CBS San Francisco reported.
From gas fields to gas batteries
A depleted gas field is a natural storage tank. The rock already proved it can hold gas under pressure for millions of years, and the wells and pipelines are already in place. So as the Delta fields ran down, PG&E turned two of them into storage. In summer, when gas is cheap, PG&E injects gas back underground. In winter, when demand peaks, it pulls the gas back out.
- McDonald Island, on a Delta island about 10 miles west of Stockton, is PG&E's largest storage field, with 82 Bcf of capacity. PG&E says it can supply about 25% of Northern California's gas on the coldest winter days. PG&E has run the field for more than half a century and has called it the battery of the gas system, KTVU reported.
- Los Medanos, in the hills north of Concord between Martinez and Pittsburg, is PG&E's second-largest field at 17.9 Bcf, with 22 wells, according to a 2024 state environmental filing. KQED notes it is an old gas field reused for storage.
These fields are not risk-free. In late 2015 a valve left open at McDonald Island let wet gas into PG&E's system and knocked out service to customers around Discovery Bay, KQED reported. In 2016 PG&E paused the field after finding small leaks around some wells, according to NGI. Both came soon after the Aliso Canyon leak in Southern California, and the state has since added tougher well standards for storage wells.
Why this matters for natural gas traders
California makes very little of its own gas. The California Energy Commission says the state relies on out-of-state supply for nearly 90% of what it uses. That gas arrives by long pipelines from the Rockies, the Southwest and Canada. When a cold snap hits and those pipelines are full, local storage is the only fast extra supply. That makes the Delta storage fields one of the biggest swing factors for PG&E Citygate, the main price point for Northern California gas.
December 2022 showed what happens when that cushion is thin. On December 21, spot prices at PG&E Citygate, Malin and Sumas all went above $50 per MMBtu, the highest at PG&E Citygate since December 2000, while Henry Hub sat near $6, according to the U.S. Energy Information Administration. The EIA pointed to cold weather, lower imports from Canada, pipeline maintenance in West Texas and Pacific region storage that was 30% below its five-year average. PG&E later told KTVU that drawing on McDonald Island during that winter saved its customers more than $1 billion.
For traders, the lesson is that West Coast gas is a regional market with its own storage story. Henry Hub can be calm while PG&E Citygate blows out. Three things are worth watching each winter:
- Pacific region storage in the EIA's weekly report, compared with its five-year average. The Lower 48 total can look comfortable while the West is short. For the week ending October 23, 2026, Lower 48 storage stood at 3,724 Bcf, about 1% above the five-year average, on the Arc Research EIA storage page.
- West Coast weather, especially cold that reaches from the Pacific Northwest into California at the same time.
- Pipeline constraints on the routes from the Rockies, the Permian and Canada.
Is there more gas under the Delta?
Some, but not a lot by national standards. The USGS's 2019 assessment put the mean undiscovered, technically recoverable gas in the Sacramento Basin at 512 Bcf. That is about six times McDonald Island's capacity, but only about five or six days of total U.S. gas use.
Rules also limit new drilling near people. Under California's SB 1137, the state stopped issuing new well permits inside a 3,200-foot health protection zone around homes, schools and hospitals, and the law has been fully in force since June 2024. Much of the land over the old Brentwood and Rio Vista fields is now suburbs. So the Delta's main role in the gas market today is storage, not production.
Track Northern California's gas market on Arc Research
The geology under Mt. Diablo explains why Northern California gas behaves the way it does: a big import market with a small, valuable storage cushion sitting in old Delta gas fields. When that cushion runs low in a cold snap, PG&E Citygate can decouple from the rest of the country.
The Natural Gas Hub on Arc Research puts the data that drives those moves in one place:
- Weekly EIA storage, with the storage report breakdown and a public storage-call scorecard that grades our weekly storage estimates
- Weather model shifts from the GFS and ECMWF, turned into gas-weighted degree days
- CFTC positioning, so you can see how funds are set up before a cold snap
The NG Terminal, which brings the storage call, weather model shifts, fund positioning and the futures curve into one screen, opens in late November or early December, and beta invites go out by email before then. Create a free Arc Research account to follow the launch and get the Weekly Commodity Brief.
This article is for education and is not financial advice.