A Presidential Solution for the California Fuels Crisis

To Address Current California Oil Production Constraints and the Potential for Oil Production Increases in the Near and Medium Terms and a Reduction in Greenhouse Emissions

By Michael Mische, James Rector, Tim Stewart, and Joseph Silvi 

The U.S. and hardworking Californians can ill-afford the state’s inability to effectively and rationally address its self-inflicted energy crisis. As we noted earlier, the U.S., California, and global security would benefit from President Trump’s further and immediate invocation of the Defense Production Act (DPA). As a blueprint for Presidential consideration, we recently suggested seven potential Executive Orders (EO) that POTUS could immediately consider ensuring that the U.S. has the necessary fuels from California to provide for its national security: Below is an amplification of EO #3 which called for increasing  California’s onshore crude oil production and the suspension or revocation of certain California regulations which inhibit increasing in-state crude oil production economically.  

1.0 Situation

California has legislated itself into a precarious position with respect to its crude oil, gasoline, and jet fuel supplies, and is now confronting a potential crisis. California has the highest gasoline retail prices and regulatory costs in the United States. Despite having the fifth largest crude oil reserves in the nation, California is the most heavily dependent state in the U.S. on foreign sourced oil to support its economy and its 36 million gallons of gasoline consumption per day. For 2025, California relied on foreign nations such as Iraq, Brazil, and Guyana for over 60% of its crude oil while its own in-state crude oil production sank to a historical low. The imports cost Californians over $80 million a day in payments to foreign suppliers while the staggering reduction of in-state oil production contributed to the collapse of San Pablo Bay pipeline, the essential north-south artery for crude oil movement in the state.

In the 1980s, California had 43 refineries supplying its growing economy; today there are only 7 remaining which supply the state with gasoline. Over the last 18-months two major refineries, Phillips 66 and Valero, voluntarily exited the state citing regulatory costs and a difficult operating environment. California could very well lose more refineries, as evidenced by their cautionary letters to the Governor and regulatory agencies. In just 4 years under Governor Newsom, California in-state gasoline production is down a staggering 22% or over 6.5 million gallons a day. California’s in-state crude oil production has also decreased by 38% under his leadership, While the Golden State may have the highest number of EVs, well over 93% of all registered vehicles in the state are internal combustion vehicles burning gasoline and diesel fuels. Gasoline consumption is not abating at anywhere the rates anticipated or advertised by the California Energy Commission (CEC) or California Air Resources Board (CARB). Consequently, and despite multiple warnings and quantitative data, California’s policies, combined with world events, have placed the state at the edge of a gasoline crisis. 

2.0 The Need for Presidential Action and Executive Order

California’s oil and gas production is constrained less by geology, capital, or downstream infrastructure than by layered statutory restrictions and administrative processes that materially delay or foreclose development. To address California’s situation and its potential impact on Nevada and U.S. national security we outlined seven potential Executive Orders (EO) for President Trump’s consideration under the Defense Production Act of 1950 (DPA). Specifically, EO #3 as envisioned would designate individual projects that are currently being delayed or halted by specific state laws or agency inaction to be administered by the federal government  with the goal of  rapidly increasing in-state production 

If the suggested EO is implemented, and assuming at least a $60 WTI forward strip, we estimate that over 500,000 bopd of new production in California is possible within the next five years roughly tripling existing production and significantly lowering dependency on foreign oil producers such as Iraq. Even if prices drop below $60, most California light oil reserves will remain economically competitive, with some of the lowest production costs in the world. Furthermore, as we will discuss in a forthcoming analysis, increasing California in-state oil production will have a favorable impact on greenhouse emissions and pollution as compared to imports and maritime oil tankers. 

Figure 1 shows the overall incremental production that could be obtained for each of the major oil producing counties in California over a one- and five-year time horizon. LOE’s are calculated based on % of incremental heavy oil in a particular county assuming that heavy oil LOE’s are 60% greater than light oil LOE’s. It should be noted that nearly all the incremental production onshore comes from private minerals. 

Figure 1:

Estimated California incremental production over 1- and 5-year time horizons from federal measures outlined in this paper

3.0 Abundant Offshore Oil Access from Onshore Locations

California is one of the most oil rich areas in the world. Billions of barrels of undeveloped, but economically recoverable oil resources remain offshore Southern and Central California, spanning both state and federal waters from Orange County through Santa Barbara and north into San Luis Obispo County. There is currently substantial production from fields beneath Federal waters, however most production in state waters has been stopped by regulation. These offshore fields, such as the South Ellwood Field in the Santa Barbara Channel, contain on the order of 1–2 billion barrels of recoverable oil across federal and state lease areas.  

Critically, a large portion of these offshore reserves, particularly those in state waters, can be accessed without new offshore platforms. Advances in extended-reach and directional drilling allow operators to develop offshore reservoirs from onshore locations well separated from the coast. As a result, development can proceed while avoiding any oil spill risk from new platforms.  In addition, offshore fields accessible from Vandenberg Space Force Base land presents a unique opportunity where drilling operations could be staged entirely onshore under federal jurisdiction.

From a policy standpoint, this creates a distinct advantage. Development from land-based locations eliminates the need for new offshore platforms, avoids incremental risk to the coastal and marine environment, and leverages existing infrastructure and controlled industrial settings. 

In addition, there are substantial benefits to the local environment and for climate change.  Oil production from the South Ellwood Field, which spanned over 40 years, dramatically reduced hydrocarbon seepage in the Santa Barbara Channel by lowering reservoir pressures and capturing hydrocarbons that would otherwise migrate to the surface. For perspective, the shutdown of production by the State of California due to the 2015 Refugio oil spill (~2,000 barrels of oil), which shut down oil production in state waters, has added the equivalent of 700 Refugio-sized spills to the coastal environment over the last decade due to additional hydrocarbon seepage. 

From a production standpoint, these resources are not only large but highly actionable. With a clear permitting pathway and reliance on onshore drilling locations, an initial phase of development focused on South Ellwood and adjacent federal waters could deliver approximately 50,000 bpd within 5 years, driven by a combination of extended-reach wells and redevelopment of known reservoir compartments. As infrastructure and drilling programs expand, particularly with access from federal lands near Point Conception and Vandenberg Space Force Base, total production across the offshore trend from Santa Barbara through San Luis Obispo could scale to 100,000 bpd within 5 years.

4.0 California Constraints

Through the years, a litany of California regulations has combined to constrain in-state oil production, increase producer costs, and drive the dependency for foreign oil sources to supply the state’s gasoline, jet, and diesel fuels to historical levels. The revocation or suspension of these inhibiting regulatory actions would have a favorable influence on in-state production as well as employment and tax revenues. 

4.1 Setbacks (SB 1137)

Replacing California Senate Bill 1137 (SB 1137) with a federally authorized Conditional Use Permit (CUP) framework would shift California’s current distance-based prohibition to a performance-based regulatory standard. Under such an approach, drilling and production activities would be permitted from existing sites subject to enforceable conditions on safety, emissions, noise, and surface disturbance—requirements that are already met at enclosed and/or controlled facilities across Los Angeles, Orange, Kern, Ventura, Santa Barbara, Monterey, Kings, Fresno and San Luis Obispo Counties. 

Because these basins are mature and infrastructure-rich, the current constraint is regulatory and legislative rather than technical feasibility. A federal CUP structure—implemented via executive action with clear eligibility tied to existing pads and facilities—would immediately restore the ability to drill, sidetrack, and recomplete wells with minimal incremental surface impact. This would unlock near-term production from known reservoirs without requiring new field development.

Under this framework, approximately 25,000-35,000 barrels per day of incremental production could be realized within 6–12 months at a forward WTI price of $60, driven by reactivation of shut-in wells, recompletions, sidetracks and new wells. With continued redevelopment of stranded reserves through directional drilling from existing sites in known fields, an estimated 125,000-200,000 barrels per day of additional production could be sustained within five years.

4.2 Well Stimulation (SB 4): 

California Senate Bill 4 (SB 4) established a comprehensive regulatory framework for hydraulic fracturing and other well stimulation treatments, administered primarily by California Geologic Energy Management Division (CalGEM). While SB 4 does not prohibit hydraulic fracturing in statute, its current implementation—combined with executive direction and permitting practices—has resulted in a de facto cessation of new stimulation activity in California.

This constraint is most consequential in the low-permeability reservoirs of Kern County, particularly diatomite formations, where commercial production depends on routine stimulation. In these reservoirs, drilling without stimulation yields sub-economic results, and legacy wells decline rapidly without refracturing or treatment. As a result, a substantial volume of technically recoverable oil remains stranded despite existing infrastructure, known geology, and available capital.

A federal policy action that restores a functional permitting pathway by implementing a programmatic approval structure would immediately unlock this constrained resource base. Based on historical performance and current field conditions, approximately 20,000–40,000 barrels per day of production could be restored within 9–12 months at a $60 WTI price environment. This near-term response would be driven by recompletions, refracturing of existing wells, and completion of already drilled or readily drillable locations.

Over a longer horizon, the impact is more substantial. With predictable permitting and the ability to systematically develop low-permeability intervals, operators can reestablish a sustained drilling and stimulation program. Within five years, this supports 60,000–80,000 barrels per day of stable incremental production, reflecting both new well development and improved recovery from existing assets.

This approach does not require repeal of SB 4; rather, it requires restoring its original function as a regulatory framework rather than a barrier to activity. A federally directed permitting structure—with defined timelines, programmatic environmental review, and clear scope—would maintain transparency and environmental safeguards while enabling timely development of known resources.

4.3 Injection Capacity

Injection well constraints in California affect both produced water disposal and enhanced oil recovery; however, disposal capacity is the binding constraint. Produced water must be managed in real time, and limitations on disposal wells—whether due to permitting delays, injection rate caps, or loss of approved zones—force immediate curtailment of oil production. 

The core of this constraint for California oil lies in the limited availability of approved disposal zones under the UIC framework. Injection is only permitted into formations formally exempted from protection as underground sources of drinking water, and this process has become the principal bottleneck. Many zones that historically accepted produced water have been reclassified, restricted, or subjected to heightened scrutiny following federal and state reviews of the UIC program.

At the same time, replacement capacity has not kept pace. Numerous aquifer exemptions—some of which correspond to well-understood, long-producing intervals—remain stalled for five to ten years within the permitting processes of the California Geologic Energy Management Division, the State Water Resources Control Board, and District 9 of the Environmental Protection Agency. This has created a structural imbalance: disposal capacity is being constrained or removed faster than it can be replaced. Because produced water volumes scale directly with oil production, the inability to maintain or expand injection zones translates immediately into reduced field throughput.

 The problem is compounded by increasingly conservative, often scientifically-unjustified limits made by CalGEM on injection rates and pressures applied to active wells. In many cases, permits now restrict operations below historically demonstrated safe conditions, effectively reducing the volume each well can handle. This silent derating of existing infrastructure requires additional wells to manage the same produced water volumes, yet new permits and modifications are subject to extended timelines. The result is a cascading loss of system-wide capacity: even where physical infrastructure exists, it cannot be fully utilized.

The impact of this constraint is most pronounced in Los Angeles County and San Joaquin Basin, particularly in Kern County, Kings County, and Fresno County, where high water cuts and large, mature fields make disposal capacity central to ongoing operations. Similar dynamics are present in coastal and Southern California oil provinces, including parts of Ventura County, Orange County, San Luis Obispo County, Santa Barbara County, Monterey County, and San Luis Obispo County. 

Overall, the inability to inject or expand existing injection capacity is currently limiting production by on the order of 25,000 to 40,000 barrels per day in the near term (12 months), with the potential to support 75,000 to 100,000 barrels per day of sustained incremental production within five years if constraints are relieved. To quickly remedy this issue, revoking California’s primacy over regulating Class II wells, aquifer exemptions and injection limits by instead making it a federally-administered process through the EPA and DOE would be critical.

FOR FURTHER INFORMATION:

Northern California Contact

Professor James Rector, University of California, Berkeley

Email: jwrector@berkeley.edu

Southern California Contact

Professor Michael Mische, University of Southern California

Email: mische@marshall.usc.edu      

Washington, D. C. Contact

Tim Stewart, President, U.S. Oil & Gas Assoc.

Email: tstewart@usoga.org 

Joesph Silvi

Graduate Assistant

University of California, Berkeley

Email: jsilvi0@berkeley.edu