The Lost Hills field runs along a low ridge of the same name in far western Kern County, beside Interstate 5 about 45 miles northwest of Bakersfield. Discovered in 1910 by drillers who were looking for water, the field has produced several hundred million barrels — with cumulative recovery approaching half a billion — yet most of its oil is still in the ground, locked in the Belridge Diatomite, a rock of extraordinary porosity and stubbornly low permeability. Dense drilling, hydraulic fracturing, waterflooding, and steam have made Lost Hills a signature diatomite development.
Lost Hills was discovered in July 1910, when a crew drilling a stock-water well for a land company struck oil in the shallow Etchegoin section instead. Development spread along the ridge over the following decade, and the field settled into a long career producing from shallow sands while the vast diatomite beneath remained, for practical purposes, out of reach.
The diatomite era began in earnest in the 1970s and 1980s, when operators — Chevron prominent among them, alongside the properties that later formed Aera Energy — applied closely spaced wells and hydraulic fracturing to the Belridge Diatomite. Recovery per well was small but the resource enormous; waterflooding was added to support pressure and combat the surface subsidence that depletion of the weak rock produced, including well-documented ground sinking of more than a foot per year in parts of the field during the 1990s.
Production peaked in the late 1990s and has declined gradually since, with thousands of wells still active. The Aera-operated share of the field passed into California Resources Corporation with the 2024 merger, while Chevron has remained the other principal operator. Lost Hills today is a mature, intensively managed field whose future output depends on continued infill drilling and injection.
Lost Hills sits on a narrow, elongate anticline at the basin’s western edge. Its defining reservoir is the Belridge Diatomite of the Monterey Formation: soft, light rock built from silica microfossils, with porosity of 45 to 70 percent but permeability so low that unstimulated wells barely flow. Above it lie the Etchegoin and Tulare sections that supplied the field’s early production. The diatomite’s combination of huge oil storage and minimal recovery to date — single-digit percentages of oil in place — is both the field’s frustration and its remaining prize.
Lost Hills production leans on three tools. Hydraulic fracturing makes diatomite wells flow at all; waterflooding restores pressure and slows the compaction that once sank the ground surface at measurable rates; and steam injection thins heavy oil in the shallower zones. Each is permit-intensive under CalGEM, and California’s restrictive posture toward new well stimulation permits in recent years bears directly on how quickly operators can drill the infill wells diatomite recovery requires. Royalty owners here benefit from slow base declines, but incremental volumes are tied to a permitting process the operator does not fully control.
Lost Hills royalties offer the diatomite paradox: shallow-decline income from a rock still holding most of its original oil, in a state where the permits needed to chase that oil have become harder to obtain. That mix rewards careful, current analysis — the value of your interest depends on whether your tract sits in actively drilled patterns or in acreage awaiting capital that may not come. We price both honestly, using well-level data rather than field averages. We buy minerals and royalties in Kern County and provide free written offers.
County-level well data, production charts, and selling guides for the counties this field spans:
Diatomite wells are individually small but collectively steady, and waterflood support flattens decline. The result is income that erodes gradually rather than falling off a cliff — one reason buyers value well-supported Lost Hills interests on long time horizons.
Subsidence from diatomite compaction was significant in the 1990s and is managed today with water injection. It is an operating cost and engineering constraint for the operator rather than a direct threat to royalty ownership, though it is part of why continued injection matters to future volumes.
We identify the wells tied to your decimal, review their production histories and the operator’s recent drilling and injection activity nearby, apply current pricing, and discount the projected stream to a cash value. The written offer is free, and we will explain the basis behind it.