Future Upstream Prospects

Sebastian Blanco
3 days ago
40 min read

04/12/2025

Executive Summary

This research provides a comparative evaluation of upstream oil investment opportunities in the American continent, focusing on key basins with extensive remaining reserves: Alaska (North Slope, USA), Canadian Oil Sands, Vaca Muerta (Argentina), as well as undeveloped Kerogen/Oil Shale prospects in the Green River (USA) and Saskatchewan (Canada). It aims to quantify breakeven economics, operating costs, production outlook, and infrastructure status to enable a cost-curve comparison for long-term investment.

Macro Context

Global oil demand rose by 0.8% y/y reaching ~107 million bpd in 2025 (IEA). The U.S. accounts for ~17% of global production, led by the Permian Basin, whose growth is now plateauing after contributing 93% of U.S. production growth since 2020 (EIA). Against this backdrop, capital can be refocused towards long-life assets and low-decline unconventional oil projects that offer durability beyond the shale boom.

Canadian Oil Sands (Alberta)

- Resource base: ~160 billion bbl recoverable (>140 billion in-situ).

- Extraction: Surface mining (~10%) and SAGD (~90%).

Economics:

- Brownfield SAGD project breakeven: ~ US $47/bbl Brent (operating US $10-20/bbl).

- Greenfield SAGD project breakeven: ~ US $58/bbl (decreasing y/y).

- Surface mining (truck and shovel): US $50-78/bbl; OPEX US $20-30.

- Producers: Suncor & CNRL cash OPEX ≤ US $20/bbl in 2024; CNRL mining + upgrading cost ≈ US $15/bbl.

- Longevity: Reserve life > 40 years ++, low decline rates, predictable output.

- Transport: WTI–WCS differential narrowed to US $13.8/bbl in 2024 (from US $17.9 in 2023) as new pipeline capacity came online (+590 kbpd Trans Mountain Expansion). Bilateral negotiations underway between CAD and USA to approve Keystone XL pipeline may further increase access to US Gulf Coast refineries if approved.

- Heavy sour WCS (~20° API, ~3.3% S) suits U.S. Gulf refineries; Synthetic Crude Oil (SCO) fetches near-WTI pricing.

- Refining integration: U.S. refiners with cokers capture margin from heavy discounts; SCO provides light crude feedstock option.

Kerogen / Oil Shale

- Green River (USA): 1.3 trillion bbl in place; no commercial output; consensus estimated breakeven > US $100/bbl.

- Estonia (VKG/Enefit): Breakeven US $50–60/bbl; production ≈ 1.1 million tons (~8 MMbbl) per year. Self-sufficient plants (Kiviter/Galoter retorts).

- EROEI: 1.5–4:1 vs. ~>20:1 for conventional crude.

- Status: Commercially proven only in Estonia; technology export potential but limited scalability in the Americas until major tech breakthrough.

Alaska (North Slope)

- Recoverable resources: Estimated at ~8.7 billion bbl in the NPR-A (USGS) (likely greater).

- Major projects in development: Willow (ConocoPhillips, ~600 MMbbl recoverable; peak 180 kbpd by 2029) and Pikka Phase I (Santos/Repsol, ~397 MMbbl recoverable; peak 80 kbpd by 2026).

- Economics: Willow breakeven ≈ US $26/bbl Brent; Pikka ≈ US $40/bbl Brent. Average North Slope transport cost ≈ US $10.5/bbl and royalties of 12.5%.

- Outlook: Production is projected to rise to ~660 kbpd by 2032. Projects are designed for 30-year lifespan, but depend on stable federal leasing policy.

- Risk: High capex (~US $7–8 B Willow) and policy reversals between administrations create uncertainty.

Vaca Muerta, Argentina (Neuquén Basin)

- Oil in place: ≈ 16 billion bbl; 2025 production ≈ 530 kbpd (65% of Argentina’s total 816 kbpd).

- Economics: Wellhead OPEX ~ US $24/bbl; breakeven US $35–40/bbl (McKinsey/Rystad).

- Reserves life: > 20 years (estimated) with < 10% developed to date.

- Midstream: $3 billion Vaca Muerta Oil Pipeline (2027 start-date) increases capacity from 180 → 700 kbpd.

- Risks: High inflation, currency controls, and policy instability raise effective costs (~35–40% higher than Permian per Energy Ministry 2025).

- Following Milei mid-term victory at end of Oct25, market is expected to stabilise.

Comparative Breakeven Summary (Brent USD/bbl)

Project / Region	Type	Breakeven	EROEI	Projected Lifespan
Alaska – Willow	Arctic Conventional	26	N/A	30 years
Alaska – Pikka I	Arctic Conventional	40	N/A	30 years
Canada – Oil Sands (SAGD brownfield)	Unconventional	45–47	~5:1	>40+ years
Canada – Mining + Upgrading	Unconventional	50–78	~8:1	>40+ years
Estonia – Kerogen	Unconventional	50–60	Self-sustained via in-situ natgas	15 years policy phase out
Vaca Muerta (Argentina)	Unconventional Tight Oil	45	N/A estimate >15:1	>20 years
Permian Basin (USA)	Unconventional Tight Oil	40–50	N/A estimate >15:1	5–10 years
Green River – Kerogen (USA)	Unconventional	>100	1-2:1	Non-commercial

CRUDE GRADE CHARACTERISTICS

Crude	API gravity (°API)	Sulphur content (%)	Grade	Sweet/Sour	Comments
WTI	~ 40° API	~ 0.24–0.4% sulphur	Light	Sweet	A benchmark U.S. crude; well refined for gasoline/diesel.
Brent	~ 38° API	~ 0.37% sulphur	Light	Sweet	Global benchmark for Atlantic‐basin crude.
Arabian Light	~ 33° API	~ 1.5-1.9% sulphur	Light	Sour (relatively)	While called “light”, it has higher sulphur than typical sweet crude.
WCS – Western Canadian Select	~ 20.5° API	~ 3% sulphur	Heavy	Sour	Canada’s major heavy crude benchmark.
ANS West Coast (Alaskan North Slope)	~ 31.5° API	~1% sulphur	Medium	Mild sour	Medium gravity crude; used by West Coast refineries.
Permian Basin Tight Oil	~40° API (Ranges)	~0.15% sulphur	Light	Sweet (for many wells)	Unconventional (tight) oil; quality varies considerably.
Synthetic Crude Oil (SCO)	~30° API	~0.13% sulphur	Medium	Sweet	Refined from Bitumen. Similar to a light crude. Refiners pay a premium for SCO relative to Bitumen: SCO typically prices close to WTI.

Opinion

For long-term upstream exposure in the American continent, Canadian Oil Sands stand out as the most economically viable and operational opportunity:

- Mature infrastructure and stable jurisdiction (Alberta) lower political risk vs. Alaska and Argentina – Bonus: Bilateral deal with US may see revival of Keystone XL pipeline project adding 830,000 bpd of capacity to the export market.

- Predictable cash flow and reserves life beyond >40 years ensures long-term asset duration unmatched by tight oil.

- Breakeven in the US $45–47/bbl range (brownfield SAGD) is competitive against other unconventional sources. Greenfield SAGD project breakeven: ~ US $58/bbl (decreasing y/y) would still be highly profitable in a rising oil price environment.

- Technological efficiencies and diluent recovery innovations continue to lower costs and logistics risks.

- Integration with U.S. refinery demand for heavy sour crudes supports sustained market access.

On the topic of Kerogen:

Extracting shale oil from kerogen may present a fantastic long-term opportunity if significant deposits can be acquired cheaply, it remains a speculative investment at present.

Tight oil in the Permian Basin was also once considered unrecoverable for decades, but hydraulic fracturing and elevated oil prices unlocked the flood gates. Kerogen could be analogous in the long term if a similar breakthrough occurs, but none is on the immediate horizon – Estonia has set an excellent framework for developing an oil shale resource but without big leaps in extraction technology, favourable climate policies and high oil prices it could remain unexploited for decades. Outside of the context of oil, it may find its niche commercially if extracted for alternatives such as chemical industry.

Whilst Alaska’s Willow project offers exceptionally low breakevens, its capital intensity and policy volatility limits scalability at present.

Vaca Muerta delivers competitive unit economics and is highly likely to wholly replace Permian tight oil in the next 10 years but remains exposed to significant currency and political risk – despite Milei winning the mid-term elections.

BREAKEVEN COST PER BARREL MATRIX

Region / Project	Type	Production Method	Estimated Breakeven, Brent (USD/bbl)	Operating Cost (USD/bbl)	Comments
Alaska – Willow Project (ConocoPhillips)	Conventional (Arctic)	Large-scale oilfield (NPR-A)	$26	~$10 transport + royalties (12.5%)	Rystad Energy estimate; lifecycle breakeven below $30
Alaska – Pikka Phase I (Santos / Repsol)	Conventional (Arctic)	Nanushuk formation development	$40	~$5 OPEX	Capex $2.6B, lifecycle breakeven Brent $40
Canadian Oil Sands (average in-situ SAGD)	Unconventional (Bitumen)	Steam-Assisted Gravity Drainage	$45-47	$10-20 operating	New SAGD project estimate breakeven: Greenfield $58; Brownfield ~$47
Canadian Oil Sands (surface mining)	Unconventional (Bitumen)	Truck & shovel + upgrading	$50–78	~$20-30	High capital, long-life assets; 40+ year R/P ratio
Estonia – Enefit/VKG (Kerogen)	Unconventional (Oil Shale)	Retorting (Kiviter/Galoter)	$50–60	N/A (energy self-sufficient plant)	Breakeven $10–20 above oil sands; benchmark for kerogen oil
Green River (USA – Kerogen)	Unconventional (Oil Shale)	In-situ heating / retorting (non-commercial)	>$100 (estimate)	N/A	Technically viable but uneconomic below triple digits (consensus opinion)
Vaca Muerta (Argentina – YPF)	Unconventional (Tight Oil)	Shale oil (hydraulic fracturing)	$45	~$24 wellhead	McKinsey & Rystad estimates; competitive with Permian
Permian Basin (USA)	Unconventional (Tight Oil)	Mature shale production	$40–50	~$20-25	U.S. EIA and industry data (2024–25 averages)
Saudi Aramco (Arabian Light)	Conventional (Onshore)	Low-cost, giant conventional reservoirs	$2-3	$2-3	Global cost benchmark

INTRODUCTION

“Ten counties in the Permian Basin account for 93% of U.S. oil production growth since 2020”

After years of outsized gains in the Permian Basin, it is clear U.S. shale oil production cannot continue forever.

With the shale oil boom in full swing, the US is the leading global producer of crude oil and now accounts for ~17% of global crude oil production, a marked improvement from 7% in 2010.

IEA: Global Energy Review 2025

“Growth in global oil demand slowed markedly in 2024, with consumption rising by 0.8% (1.5 EJ or 830 kb/d) to 193 EJ after jumping by 1.9% in 2023.”

The landscape for upstream oil investment in 2025 reflects a structural transition away from short-cycle shale growth toward long-lived, high-stability projects. Global oil demand, as reported by the IEA in its Global Energy Review 2025, reached 107 million barrels per day (mb/d), with global demand ever growing.

Depletion rates and geological constraints in the Permian Basin are converging to limit incremental gains. For the US to maintain its presence as the largest global producer of crude, they must pivot from a maturing resource base where efficiency and cost discipline, rather than pure expansion, are currently driving returns.

This report explores long-life, low-decline upstream prospects in the American continent. The following segments evaluate active basins such as Canada’s oil sands, Alaska’s North Slope, Argentina’s Vaca Muerta region, and the future potential of unconventional oil derived from kerogen.

In the context of a long-term investment in kerogen deposits, I have focused on the Green River Formation in the U.S. and the Pasquia Hills in Saskatchewan Canada. Whilst alternative ‘better grade’ deposits do exist such as the Alberta Formation in Canada, they have been discounted based on their total resource size which are smaller by orders of magnitude. These resources remain technically complex and uneconomic at scale, therefore deposits with a vast latent reserve base and transformative potential should next-generation in-situ or retorting technologies achieve commercial viability are the most logical targets for the purpose of this report.

CANADIAN OIL SANDS

Of ~160B recoverable barrels contained in Alberta’s oil sands deposits, only 10% are close enough to the surface to be mined. The remaining >140B must be recovered in-situ and may present a meaningful long term investment opportunity.

Historically known for high costs, the oil sands have significantly improved their cost basis in recent years.

In mining operations, upfront capital costs are enormous (multi-billion-dollar mines and processing plants), but once running, operating costs can be in the range of $20–30 per barrel for mining and bitumen extraction.

In-situ Steam Assisted Gravity Drainage projects have lower initial capital per barrel and operating costs often quoted around $20 per barrel.

By 2024, the cash operating costs of major producers like Suncor and CNRL were around $20/bbl or less, and including sustaining capital and other costs, the break-even WTI price needed was in the low $40s per barrel.

A Reuters analysis showed that the five largest oil sands producers can sustain operations (and even their dividends) at WTI $40–43/bbl. A dramatic improvement from ~$50 - $60 a decade ago. Part of this is economies of scale and tech (robotic trucks, process optimisations), and part is a focus on brownfield expansions rather than expensive new projects.

Overall supply costs (breakeven including capital) for new in-situ oil sands are in the US$50–60/bbl range (expansions at ~$47, greenfield SAGD ~$58)[1]. New surface mines are at the higher end (~$50–78)[2]. These figures reflect the need for high upfront capital; however, once they are built, many oil sands projects have cash operating costs in the teens of dollars per barrel as sunken costs are absorbed.

Existing Canadian producers also continue driving down costs through efficiency: Canadian Natural Resources achieved mining + upgrading operating costs of C$20.97/bbl (US$15.00) in late 2024. Despite high initial capital, the long reserve life (40+ years R/P) and low decline of oil sands provide a stable output base.

Recovery Methods

Mining vs. SAGD: Shallow oil sands are mined with truck-and-shovel and processed with hot water to extract bitumen, achieving ~90% extraction of bitumen from the sand. Deeper deposits use Steam-Assisted Gravity Drainage (SAGD), where pairs of horizontal wells inject steam to mobilise bitumen. SAGD typically recovers 50–70% of the oil in place over time.[3]

Oil sands projects are capital-intensive (massive upfront infrastructure cost for mines or central SAGD facilities) but yield long-lived, low-decline production. Once operational, they have predictable output for decades with minimal decline, unlike shale.

SAGD wells also have steam-oil ratios ~3:1, indicating significant energy input and associated costs. Upstream operating costs for established projects have become competitive – e.g. thermal in-situ (SAGD) operating cost averaged C$11.04/bbl (US$8.06) in 2024[4].

The recovery rate in mining is high per mine (a truck and shovel operation can feed ~200,000 bpd facilities), whereas SAGD well pairs ramp up and decline slowly over years.

Midstream, processing crude obtained from oil sands is highly comparable to Venezuelan heavy crude in that it requires upgrading or blending before it can be sold or transported. Some mining projects have onsite upgraders that convert bitumen into synthetic crude oil (SCO) – a light, sweet crude with a gravity of ~31–33° API, and very low ~0.13% sulphur.

Upgrading is effectively a pre-refining step that removes carbon and sulphur, producing a pipeline-ready light crude. This reduces reliance on diluent and allows selling at prices linked to light oil. However, upgraders are capital-intensive (on the order of $60,000–$90,000 per flowing barrel capacity per day) [5]

High costs and shrinking light-heavy differentials in the late 2010s made new upgraders economically unattractive, so recent projects tend to export raw bitumen as DilBit.

Dilbit (Diluted Bitumen): Most in-situ SAGD production is blended with a lighter hydrocarbon (typically natural-gas condensate or naphtha) to form dilbit that can flow in pipelines. Bitumen by itself is near solid at room temperature (viscosity like cold molasses), so ~30% vol of diluent is added. The resulting Western Canadian Select (WCS) blend has a gravity of ~20.5° API and ~3% sulphur[6] – still heavy and sour, but fluid enough for transport.

The need for diluent incurs a volume penalty (e.g. 1 barrel of bitumen plus 0.3 barrel diluent yields 1.3 barrels dilbit).

Diluent is often costly (priced similarly to light oil), effectively reducing the producer’s netbacks, and in times of low oil prices, buying diluent can consume a large share of bitumen revenue.

Midstream operators have introduced diluent recovery units (DRU) at rail terminals to reclaim and recycle diluent, shipping bitumen as a semi-solid (“neatbit”) by rail, but pipelines still require dilution.

Transport

Landlocked in Alberta, Canada’s oil sands industry remains heavily dependent on long-distance pipelines to reach refineries - most of which are located in the United States. Limited pipeline capacity has frequently acted as a bottleneck, widening price differentials between Western Canadian Select and benchmark West Texas Intermediate. According to the Canadian Energy Centre (2022), transporting crude oil by rail from Western Canada typically costs US $5–10/bbl more than via pipeline [6].

When pipeline space is tight, producers are forced to adopt transport by rail to ship dilbit or raw bitumen.

In 2024, the average WTI–WCS discount narrowed to US $13.84 /bbl, compared with $17.85 /bbl in 2023, reflecting a modest easing of infrastructure constraints.

Rail remains a swing option within the transport system, though its use has declined year on year. The completion of new projects such as the Enbridge Line 3 Replacement and the Trans Mountain Pipeline Expansion (adding roughly 590,000 bpd of capacity to the Pacific coast) has been instrumental in reducing pressure on existing networks.

The cancellation of Keystone XL under the Biden administration removed a major potential outlet for Canadian crude, however reports published by the Financial Times on October 16^th suggest renewed talks over reviving the “zombie” Keystone XL project has morphed into a tariff bargaining chip between the US and Canada. If approved, the extension could deliver an additional 830,000 bpd of capacity, providing a direct route to refineries on the U.S. Gulf Coast.

Analysis published last year by Enkon Energy Advisors underscored the strategic importance of Diluent Recovery Units (DRUs) in improving the economics of bitumen-by-rail transport. Innovation is expected to narrow the historical cost gap between rail and pipeline logistics, bringing DRUbit shipments close to pipeline cost parity under optimised conditions. If no new pipeline expansions were to come online, Western Canadian producers are projected to encounter renewed capacity constraints by 2027, as demand from U.S. Gulf Coast refiners for heavy crude continues to grow. [7].

Whilst the use of rail has fallen in recent years, it remains an integral part of the oil transportation system because it serves regions without pipelines and can be relied upon when pipelines are running at capacity (such as in 2019). When the WCS-WTI differential narrows, some crude-by-rail becomes an uneconomic export option – especially without improved DRUbit logistic costs.

Downstream

Dilbit requires a highly complex refinery typically with a delayed coker or resid hydrocracker. Many U.S. Midwest and Gulf Coast refineries invested in coking capacity specifically to process Canadian heavy and similar crudes. Firms like Valero, Marathon, and Phillips 66 have refineries with cokers in the 25–50 kbbl/d range dedicated to breaking down resid. The refiner’s incentive to process WCS is the price discount: WCS trades at a significant discount to light crude, often ~$10–20/bbl, which can make it attractive if the refinery can upgrade the barrel. The complexity of refining dilbit is comparable to Venezuelan heavy – both need similar equipment. Many Gulf Coast refineries that historically ran Maya (Mexican heavy) or Venezuelan crude now run Canadian WCS due to availability.

Synthetic Crude Oil (SCO) flips the tables by doing much of the work upstream. Upgraders in Alberta create a partially refined crude that is light and low in sulphur. SCO can typically be processed in medium-complexity refineries similar to other light-medium sweet crudes. For instance, Suncor’s SCO has ~31° API and <0.2% sulphur after hydrotreating, making it comparable to a light conventional crude.

Refineries running SCO do not need cokers or extensive residue upgrading because the upgrader has already cracked the heavy fractions and removed most sulphur. Instead, the upgrader byproducts (coke, heavy gas oil) are produced in Alberta. The refining yield of SCO is high in light products – essentially, upgraders produce a synthetic oil that yields ~80% or more light/middle distillates when refined, similar to a light crude.

Refiners pay a premium for SCO relative to bitumen: SCO typically prices close to WTI.

The trade-off is that the upstream operator captures that value but also incurred the cost of upgrading. Economically, SCO shifts the margin upstream. In times when heavy crude discounts are very wide (>$20/bbl - see earlier chart), having an upgrader (making SCO) is advantageous; when heavy discounts are narrow (<$15/bbl), the expensive upgrader investment might not pay off[8].

Refining Margins

Refiners calculate a “coking margin” (value of gasoline + diesel + xyz from heavy crude) minus (cost of heavy crude + conversion costs). A well-configured refinery can make very healthy margins on heavy crudes when the heavy feed is discounted enough.

U.S. Gulf Coast coking margins were strong in 2022 when WCS traded ~$20 under WTI, diesel prices were high, and cokers ran at high utilisation. Conversely, if heavy crude supply tightens and discounts shrink, those margins erode.

Synthetic crude (SCO) typically yields a lower refining margin because it is bought at near light-crude price but still yields slightly less gasoline than a WTI (due to being slightly heavier than WTI). However, refiners processing SCO don’t need to invest in cokers or deal with coke piles, so it’s a simpler operation.

From a value chain perspective, Canadian oil sands producers either: A. sell dilbit at a discount and let refiners capture the coking margin, or B. invest in upgrading to sell SCO at a better price but take on the upgrading cost. This trade-off has swung over time.

As noted by the Canada Energy Regulator in 2022 many oil sands producers decided to export diluted bitumen.

Since the shale boom shrank heavy-light differentials in the late 2010s, “skyrocketing upgrader capital costs and shrinking light-heavy differentials… made it difficult to build new upgraders”[9].

Land acquisition

Oil sands direct purchases can be made from the Government of Alberta [10].

Sales Schedule 2025-2026 can be viewed here (note back to front dating in Canada …)[11].

Average price paid per hectare YTD - Direct purchase price is based on 125% of the average $/ha.

Average cost per hectare (Average $/ha) is calculated using bonus amounts received divided by total hectares leased. This excludes the bonus received and hectares leased on Metis Settlement lands (or distributed via permits) in the previous 6 months, as indicated in the Public Offering Statistics.

To acquire top-tier oil sands leases in Canada, you’ll want to focus on securing Crown mineral rights in provinces like Alberta or Saskatchewan, since the provincial government holds the majority of the subsurface rights.

For a Brownfield development you should evaluate parcels against the following criteria:

- Existing roads, pipelines, upgrader access

- Proven resource quality bitumen grade

- Depth of overburden (layer of material that lies above the bitumen-bearing formation),

- Whether it has mining potential or will require SAGD (in situ)

- Favourable royalty terms

For a Greenfield development, undeveloped Crown mineral rights parcels in provinces of Alberta where subsurface oil-sands zones are known and infrastructure is emerging but not yet fully exploited (i.e. Athabasca, Cold Lake or Peace River) would make strong candidates.

Allow for higher upfront costs (exploration, infrastructure, environmental impact assessment) and longer lead times.

As an investment strategy, feasible Greenfield development ground in a prime region could potentially be sold on for a profit without proving up the lease – those which are surveyed and have completed EIAs would likely command a premium.

KEROGEN

Kerogen is the insoluble, waxy, organic matter found in sedimentary rocks, formed from the accumulation and burial of dead organisms like plants and algae. It converts into shale oil when heated over geological time.

As the precursor to oil in oil shale, kerogen represents a vast but currently untapped resource base. This section discusses the different types of kerogens, notable regional deposits in the Americas, and the status of technologies and economics for producing oil/gas from kerogen.

Classified into types 1, 2 and 3, based on the underlying origin of its sediments.

Kerogen Type	Origin	H/C Ratio	Hydrocarbon Potential	Dominant Hydrocarbons
Type I	Algal (lacustrine)	1.4–1.7	Very high (oil-prone)	Aliphatic-rich, long-chain paraffins, n-alkanes
Type II	Planktonic (marine)	1.2–1.5	Moderate–high (oil & gas)	Mixed aliphatic and aromatic
Type III	Terrestrial (woody)	0.7–1.0	Gas-prone	Aromatic, oxygen-rich, poor in aliphatics

WELL KNOWN GRADES OF KEROGEN

Green River Formation (USA)

Spanning parts of Colorado, Utah, and Wyoming, this is the world’s largest oil shale deposit. The USGS estimates 1.32 trillion barrels of oil in place in the Green River formation’s oil shale zones[12].

Of that, a significant portion (perhaps 600–800 billion barrels) is considered of high grade (rich enough to yield >25 gallons/ton) [13].

Current status: No commercial production.

Companies like Exxon, Shell and Chevron have spent decades researching extraction from the Green River. The most famous section is the Mahogany Zone in Colorado’s Piceance Basin. During the 1970s oil crisis, several pilot mines and retorts were built (e.g., Union Oil’s Parachute Creek retort).

These projects produced some shale oil, but at great expense and with environmental issues (massive mine tailings, water requirements, etc.). After oil prices collapsed in the 1980s, the efforts were shelved (the “Black Sunday” in 1982 when Exxon shut its Colony project is notable). In the 2000s, interest returned: Shell’s ICP in-situ experiment in Colorado ran for a few years and produced a few thousand barrels of oil by heating a small volume over 30 months; it proved technically possible but economically questionable.

The resource remains as a strategic reserve – often cited that Green River could alone hold over a trillion barrels, greater than world proven oil reserves. But no one has found a way to tap it profitably at scale. The U.S. government still maintains R&D leases for oil shale, and companies hold some leases, but development is dormant due to cost and environmental regulation (e.g. leaching of groundwater by in-situ heating, huge CO₂ emissions if done at scale, etc.).

One small success story on the American continent is Petrobras in Brazil, which operated a facility (Petrosix) to retort oil shale from the Irati Formation, producing on the order of 3,000–4,000 barrels per day of shale oil. This oil was used for specialty fuels (the process yields a high-quality, low-sulphur oil suitable for fuels like jet and diesel)[14]. But even that plant is relatively small and heavily subsidised by Petrobras’ R&D budget.

Comparatively, oil sands in Alberta are a proven commercial resource with established recovery methods (mining, SAGD), whereas kerogen oil shales remain a potential resource for the future with unresolved technical and economic challenges – Current EROEI metrics for Green River deposits are 1/8^th that of conventional oil. Tight oil (shale oil) like Permian and Vaca Muerta sits in between – it was once considered unrecoverable, but hydraulic fracturing unlocked it. Kerogen could be analogous in the long term if a similar breakthrough occurs, but none is on the immediate horizon.

Colorado & Utah Oil Shales

Utah’s portion (Uintah Basin) has slightly richer shales near the surface (more amenable to mining). There was a small commercial retort near Vernal, Utah in the 2010s by Red Leaf Resources using an “EcoShale capsule” – effectively mining shale, piling it in a capsule with insulating layer, and slow-heating it. It produced some oil in pilot scale but not yet proven at commercial scale. The Utah Geological Survey has been bullish on their oil shale potential, estimating about 77 billion barrels of oil equivalent in Utah’s portion of Green River as potentially developable [15]. However up-to-date commentary remains scarce, and there is no active commercial production.

Saskatchewan, Canada

The Pasquia Hills in eastern Saskatchewan hold a large oil shale deposit (within the Cretaceous Second White Specks Formation).

Estimates for Saskatchewan’s total oil shale resource are on the order of several billion barrels (one figure published in 2010 was 15.4 billion barrels in place for all of Canada’s identified oil shales)[16]. The Pasquia Hills kerogen is Type II (sapropelic from marine algae) and the shale yields a medium gravity oil upon pyrolysis. A company called Xtra Energy has been exploring there, with an eye on possibly developing it using modern retorting tech.

As of 2021, Saskatchewan’s government has issued oil shale leases (indicating interest) [17], but they stressed it’s very early stage. No extraction has occurred yet in SK; it’s all exploratory. If it were developed, likely surface mining in a rural, sparsely populated area could be done, but would require a market for the shale oil and significant investment.

Unlike the Green River formation, land is available in Saskatchewan and may offer a lower cost of entry/greater area of acquisition opportunity for investment (although monetising an oil shale deposit via upstream production at the same volumes as an oil sands plot is currently not possible).

Oil shale dispositions in Saskatchewan are acquired through Crown Public Offerings. Companies request land to be posted in the Public Offerings and bid on parcels within the Integrated Resource Information System (IRIS).

More information on the acquisition process can be viewed here:

https://www.saskatchewan.ca/business/agriculture-natural-resources-and-industry/oil-and-gas/crown-land-sales-dispositions-and-tenure/crown-dispositions/oil-shale-dispositions

Open Crown Public Offerings can be viewed here: https://www.saskatchewan.ca/business/agriculture-natural-resources-and-industry/oil-and-gas/crown-land-sales-dispositions-and-tenure/public-offerings/schedule-of-crown-land-sales

Whilst kerogen resources are not currently commercial at scale in the Americas. The potential is enormous if technology and economics align.

As earlier stated, Green River’s trillions of barrels would constitute a mammoth prize. If even a fraction (say 30%) became recoverable, it could provide tens of millions of barrels per day for centuries. This attracts periodic interest when conventional oil prices spike or when energy security is in focus. i.e. during high oil prices in 2008, there was renewed talk of oil shale; pilot projects got funding. Similarly, energy security concerns in the 1970s drove the U.S. government to fund the initial oil shale boom (with loan guarantees etc., many of which collapsed in 1982). The resource acts as a kind of “backstop” – one could imagine that if oil were $200/barrel and supplies scarce, oil shale projects would be rapidly advanced.

The tech for surface retorting is mature in a basic sense (we know how to do it, from 19th century coal retorts to modern rotating kilns). The problem is scaling it up economically and handling the environmental footprint. A single large commercial retort facility producing ~50,000 bbl/day would have to mine and process on the order of 100,000+ tons of rock per day – that’s like a large mining operation, with huge material handling. The waste rock (spent shale after heating) expands and must be disposed of and there are environmental concerns (unsurprisingly) about leachate from spent shale (which can contain heavy metal salts).

Water usage is significant for cooling and dust control. The overall energy return on energy invested (EROEI) for surface retorting is low – some estimates around 1.5:1 to 2:1, compared to >20:1 for conventional oil historically.

In-situ technologies are less mature: Shell’s ICP showed proof of concept but required freezing the ground water around the test patch to prevent contamination – an expensive step. Electric heating for years is very energy intensive; the process only makes sense if cheap electricity (or nuclear heat or something) is available. Some newer ideas involve radio waves or downhole combustion to heat shale more efficiently. Exxon’s older “Electrofrac” concept would pump conductive material and then send current to heat resistively. These remain experimental. As of 2025, no company has a fully proven, economically viable in-situ method ready for commercial deployment in oil shale.

All attempts so far to make oil shale economically viable have struggled to compete with conventional oil. A 2010s estimate suggested that oil production from kerogen would need sustained oil prices well above $100/bbl to be attractive, and even then, initial capital needs and environmental permitting would be hurdles.

The US Government Accountability Office in 2012 suggested oil shale might become viable in 20–30 years with R&D, but also warned of water and land impact in the Colorado River basin [18] Right now, with oil trading near $60/bbl in 2025 and plenty of cheaper options available (shale, deepwater, oil sands), there’s no economic driver for oil shale. Additionally, many major companies have pulled out – Shell ended its oil shale program around 2013; Chevron and others have exited oil shale leases. That leaves smaller players or government-funded efforts.

Commercial oil shale would face heavy scrutiny. In the US, leasing of federal oil shale lands is allowed but NEPA (environmental assessment) processes are stringent. CO₂ emissions are a major concern: retorting releases CO₂ and uses carbon-intensive power. If climate policies tighten, oil shale could be penalised. On the other hand, there’s research into carbon capture for in-situ processes (e.g., capturing CO₂ from produced gas streams or even using some of the carbonate minerals in the shale to sequester CO₂). But those add cost.

If kerogen is developed, the products could be tailored: Shale oil can be hydrotreated into excellent jet fuel or #2 diesel as noted in a pipelineonline interview. This is because shale oil is often very paraffinic (especially Type I kerogen oil) and low in sulphur – almost like a synthetic crude produced via the Fischer-Tropsch process in some cases. So, there is an appeal: a domestic source of clean-burning diesel/jet if it could be made cheaply and cleanly. During wars or strategic crunches, such liquid fuel from shale might be tapped irrespective of cost.

Scientific research in recent years has also highlighted the polymer structures of kerogen as a potential source of a myriad of different organic compounds used across chemistry, making it a commercial prospect to industries beyond energy.

In the US applications for leases are made directly to the BLM and are first offered as a research demonstration and development (RD&D) lease. RD&D leases provide the right to explore for, but not develop, oil shale. They are acquired through a work commitment bid process and are best suited to areas that are under-explored.

Oil shale leases, which provide the right to develop oil shale and oil shale products, are acquired through the cash bonus bid process and are located in areas that have identified the presence of prospective oil shale resources. Similar to petroleum and natural gas leases, there is no requirement to prove up an oil shale lease. The understanding is that the resource has already been identified, either through exploratory work conducted under a special exploratory permit or through a review of available data, and the lessee will work towards developing the resource.

As earlier discussed in the section on Saskatchewan, oil shale leases in Canada are more easily acquired and offer more favourable terms to an investor than those offered on a case-by-case basis from the BLM. Under the US framework, a lessee may choose to ‘sit on’ the lease for the duration of the primary term of the lease provided they pay the annual lease rental. However, at the expiry of the primary term the lease will be subject to an annual lease review and any lands that are not actively being produced or under unit operation will be terminated – which presents an obvious problem to a speculator[19].

ESTONIA AS THE GLOBAL BENCHMARK PRODUCER FROM OIL SHALE

Estonia is unique in relying on oil shale (kerogen-rich rock) as a primary energy source – it’s the only country where oil shale fuels most of the electricity and liquid fuels production. The nation’s oil shale industry is among the most developed in the world[20], built on nearly 100 years of expertise.

Decades of investment has made Estonia a global benchmark for unconventional oil shale technology and development. While conventional “shale oil” in places like the U.S. refers to tight oil extracted by drilling, Estonia’s oil shale is a solid rock (Kukersite) that must be mined and heated to release oil[21]. Despite its small size, Estonia leads in commercial kerogen-based oil production, operating the largest shale oil plants in the world and exporting technical know-how to countries like Jordan and the U.S.[21]

Oil shale is extracted via underground mining in Estonia’s Ojamaa mine operated by Viru Keemia Grupp (VKG)[22]Estonia employs traditional mining and specialised retorting to produce oil from kerogen. The country’s rich Kukersite shale is obtained through both open-pit and underground mines – over 10 million tonnes of oil shale ore are extracted annually. After mining, the shale rock is crushed and fed into retort processors that pyrolyze (heat) the kerogen in absence of oxygen, releasing shale oil vapors.

Estonia has pioneered two major retorting technologies: Kiviter and Galoter (Enefit) processes.

Kiviter is an older vertical retort method, while Galoter (used in newer Enefit plants) employs a rotating kiln with a hot solid heat carrier (like spent ash) to efficiently heat the shale[23].

State-owned Enefit (Eesti Energia) uses the Galoter/Enefit process, and private producer VKG operates both Kiviter retorts and advanced Galoter units.

The latest Enefit280 next-generation plant can process 280 tons of oil shale per hour to yield about 38 tons of liquid shale oil per hour, alongside oil shale gas and electricity co-production.

Notably, these modern plants are self-sufficient in energy – the retorting heat and gas byproducts generate power to run the operation[24]. Overall, Estonia’s processing methods represent the cutting edge of oil shale technology, allowing a solid fossil resource to be converted into shale oil, gas, and electricity on a commercial scale.

VKG manufactures more than 40 different chemicals produced from oil shale and has been selling Honeyol™ in the United States since mid-2019. Honeyol™ is used in the production of rubber resins in the tyre industry, in the production of adhesive resins for the timber industry, and is one of the best alternatives to resorcinol which one could considered the benchmark reagent for these processes.

The below graphic from VKG illustrates the numerous outputs from an operating mine – demonstrating how versatile the resource can be to end users and markets beyond crude oil.

Over the past decade, Estonia’s shale oil output has grown dramatically.

In the early 2010s, Estonia only produced on the order of 1–1.2 million barrels of shale oil per year[21]. By 2019, annual production had reached between 7 and 8 million barrels[25] annually, of which 99% is exported to world markets[25]. Since domestic use is limited shale oil is a key export commodity.

Image Source: Estonian Oil Shale Industry Yearbook 2019

In recent years output has hit new highs: for example, state-owned Enefit Power alone produces over 450,000 tons of liquid shale fuels per year (~3 million bbl) in the 2020s[26], and together with VKG the national total exceeds 1.1 million tons annually (~7.5 million bbl).

On the economic side, Estonian shale oil’s breakeven price is estimated around $50–60 per barrel, meaning world oil prices must stay in at least the mid-double-digits for profitability[27] – not bad considering the forecasts made on undeveloped projects earlier in this review, however the sunk costs in Estonia have been made over generations. Estonia’s estimated breakeven remains $10-20/bbl higher than established (Brownfield) Canadian Oil Sands developments despite the similar investment time frame.

Nevertheless, when oil prices are strong (e.g. $80+), Estonia’s shale oil sector can be very lucrative. The surge in oil prices in the 2021–2022 period boosted shale oil revenues and prompted additional investment. In 2022 the shale oil segment of Eesti Energia earned hundreds of millions in revenue, contributing to solid profits[28].

Eesti Energia reported production of 451,000 tons of shale oil in FY2024, 5% lower than 2023, attributing the decline to us of lower calorific oil shale to avoid exceeding emission limits – highlighting the impact a stringent climate policy can have on production via retorting.

Despite comparatively low total bpd figures across their projects vs. conventional upstream projects, given their proven technologies Enefit / VKG could be considered the most viable partners to begin cost competitive operations should you opt to invest in a kerogen deposit.

ALASKA

Alaska’s Central North Slope region was defined by the discovery of the Prudhoe Bay field in 1968 and the subsequent construction of the Trans-Alaska Pipeline System in 1977.

Production peaked in 1989 at 2 million barrels per day but is now a shadow of its former self, averaging 421,000 bpd in 2024.

Significant assessments of undiscovered oil and gas resources in the Central North Slope of Alaska have been conducted by the USGS since at least 2005.

Current discoveries and analysis indicate that there may be 8.7 billion barrels of recoverable oil in the National Petroleum Reserve Alaska (NPR-A) – with Trump legislating for lease sales and exploration to take place.

Recent projects aim to reverse declining output. In 2023, ConocoPhillips’ new Nuna drill site (an extension of the Kuparuk field) added ~20,000 bpd this year[29], and larger developments are underway. Santos (with partner Repsol) is developing the Pikka project, targeting first oil by 2026 with a plateau of ~80,000 bpd[30]. ConocoPhillips is building the Willow project in the National Petroleum Reserve–Alaska (NPR-A), expected online by 2029 with up to 180,000 bpd at peak[31]. These new fields, each holding hundreds of millions of barrels (Willow ~600 million barrels recoverable[31]; Pikka Phase-1 ~397 million barrels with >50% chance recoverable reserves [32]), will significantly boost output. Industry forecasts project Alaskan production rising to ~490,000 bpd by 2028 (as Pikka ramps up) and ~660,000 bpd by 2032 once Willow is at full capacity[29]. This would return North Slope volumes to levels not seen since the early 2000s. The scale of these investments in the upstream segment on the North Slope suggests a resurgence of Arctic oil after decades of decline.

Alaskan North Slope crude is a medium, sour grade: ~30° API and ~1.0% sulphur. It falls between light shale oils like Permian and Vaca Muerta (~40° API and sulphur ~0.15%) and heavy crudes like Western Canadian Select (~20.9° API and ~3.5% sulphur). West Coast U.S. refineries are well configured with hydrotreaters and visbreakers to handle ANS’s sulphur and resid content. Typical product yield after conversion: ~35% gasoline, ~30% diesel, ~15% jet fuel, and ~10% resid. ANS’s sulphur is manageable using hydrotreating, and refining margins are generally good, as the crude trades at a slight discount to Brent, offering refiners a moderate margin advantage. North Slope reservoirs (e.g. Prudhoe Bay, Kuparuk) are conventional and use traditional enhanced oil recovery (EOR) methods; waterflooding and miscible gas injection (CO₂ and hydrocarbon gas) for pressure maintenance. Recovery factors reach up to ~60% of original oil in place, among the highest for conventional fields.

Midstream, A single artery; the Trans-Alaska Pipeline System (TAPS), connects North Slope crude to market[32].

TAPS is an 800-mile, 48-inch pipeline running from Prudhoe Bay to the ice-free port of Valdez.

Today, throughput is only about 25% of capacity (roughly 460,000 bpd) and these low flow rates pose operational challenges.

If throughput drops too far, the oil cools and waxes, risking pipeline integrity. New supply is therefore critical to TAPS’ long-term viability.

ConocoPhillips’ Willow project was touted as “ensuring the continued operation of the Trans-Alaska Pipeline System” by offsetting declines.

Midstream investments focus on connecting new fields to TAPS via feeder pipelines and processing facilities. Santos’ Pikka Phase 1 is using existing pipeline capacity in the Kuparuk network to transport its oil[33], and Willow will tie into ConocoPhillips’ Alpine infrastructure. No new long-distance pipelines are needed beyond TAPS, but extensions and upgrades near the fields are required to gather production.

The Alaska Department of Revenue reported FY24 transportation costs for North Slope oil averaged $10.53 per barrel and are expected to average $10.92 in FY25 and $10.31 in FY26. These costs must be factored into estimated breakeven prices for new projects as a fixed cost per barrel alongside royalties, which under Alaska Statutes § 38.05.180, requires that most oil & gas leases include a minimum fixed royalty of 12.5 % (one-eighth) of production removed or sold from the lease.

Downstream, two small north coast refineries in Prudhoe Bay (24,000 bpd total) process a portion of production into fuel for local use.

In the midlands, a tap at Fairbanks diverts some oil to Petro Star’s separate 24,000 bpd refinery for regional fuel supply. Once oil reaches Valdez, the vast majority of North Slope crude (~80%) is exported by tanker to refineries in Washington and California. Smaller volumes occasionally go to Hawaii or Asia, and Petro Star’s 60,000 bpd Valdez refinery can also receive oil via a short pipeline from the terminal[29].

California’s refining capacity is shrinking under stringent environmental policies, potentially reducing one of the traditional outlets for Alaskan crude[29]. However, West Coast refineries still rely on Alaska’s medium-gravity, low-sulphur ANS crude blend. In-state consumption of North Slope oil is relatively minor (Alaska uses ~130,000 bpd total), so maintaining export routes is essential.

Project Economics

Due to the remote Arctic conditions, Alaskan oil projects are capital-intensive but recent developments aim to improve cost efficiency. Historically, the North Slope has had some of the highest break evens in the U.S. – in 2024 the average WTI price needed for new drilling was ~$64/bbl, up slightly from 2023[34]. Reflects high logistics and production costs (ice road construction, winter-only access, etc.) and the maturing of easy oil in legacy fields. However, the large-scale new projects show markedly better economics than the average. ConocoPhillips’ Willow development cost is approx. $7–8 billion and Rystad Energy estimates a breakeven Brent price below $30/bbl (~$26/bbl WTI currently).

Similarly, Santos/Repsol’s Pikka Phase 1 initial phase capital expenditure was ~$2.6 billion gross[33], and annual operating costs were last projected at ~$150 million[35]. This equates to a very manageable op-ex of about $5 per barrel at plateau and a lifecycle breakeven Brent price of $40/bbl (~$36/bbl WTI) [33], inclusive of a 10% expected return.

Based on the projected financials of the above projects, new North Slope oil may be economically viable at oil prices in the $30s–$40s. That said, smaller projects can be expected to struggle at lower prices. At ~$75 oil, some high-cost North Slope drilling was classified as “currently unprofitable” in a June 2024 review of Alaska’s Economy by First National Bank Alaska [34], underscoring that project economics can vary widely.

Prioritising “best cost” barrels from larger discoveries (like Willow) or reservoirs in the Nanushuk formation that yield high output per well should be a focus for strong returns. Project lifetimes are generally long: new developments are engineered for ~30 years of production (Willow’s plan spans 30 years for 600 million barrels[35]). Similarly to Canadian Oil Sands projects longevity helps to distribute upfront costs, but the unstable policy setting in Alaska from Biden to Trump will need to endure beyond the end of his tenure to prompt other players to commit capital.

On the topic of shifting U.S. government policy for Alaska

U.S. Executive Order: January 20^th “Unleashing Energy Dominance Through Efficient Permitting”

Image Source: BLM NPR-A Oil and Gas Lease Sale 2025/2026

The Department of Interior is proposing to repeal or roll back key Biden-era rules that limited leasing on ~13 million acres in the NPR-A.

The National Petroleum Reserve–Alaska (NPR-A) is a focal point for future oil growth. This 23-million acre federal reserve west of Prudhoe Bay holds vast untapped resources – recent U.S. Geological Survey estimates put recoverable oil at ~8.7 billion barrels in NPR-A (an order of magnitude larger than Willow’s share)[35]. To date, industry activity has concentrated on NPR-A’s eastern edge, near existing infrastructure. ConocoPhillips’ Alpine field (just outside NPR-A) and its satellites – like Greater Mooses Tooth-1 and 2 – demonstrated success in the region. The Willow discovery (in NPR-A’s Bear Tooth unit) opened eyes to the reserve’s potential, and companies are now pursuing more. In 2025, ConocoPhillips announced plans for aggressive exploration in NPR-A, proposing four exploratory wells and 300 square miles of seismic surveying in winter 2025-26[35]. These wells target prospects around Willow (Bear Tooth) and farther south, aiming to identify the next big accumulation.

The opportunity space has recently expanded because of the executive order, which makes more of NPR-A accessible to leasing. Beyond NPR-A, another major prize is the Arctic National Wildlife Refuge (ANWR) Coastal Plain, east of Prudhoe. The ANWR is believed to overlie a prolific basin with a mean resource potential in the billions of barrels (up to ~10 billion bbl technically recoverable, per USGS estimates). After completion of a Supplemental Environmental Impact Statement (SEIS) required by President Biden's E.O. 13990, The Department of Interior (DOI) scheduled the second Coastal Plain lease sale for January 10, 2025. For the second lease sale, the Bureau of Land Management (BLM) required stricter environmental protections and offered less acreage than was offered at the first sale.

By January 8, 2025, the DOI announced that no bids had been received for the January 2025 lease sale by the bid deadline, thus concluding the sale with no acres leased [36] . Some observers, including the Alaska Industrial Development and Export Authority, stated that the BLM's "strict" terms for the lease sale discouraged participation [37].

As of new policy shifts, there is potential for reoffering ANWR leases with more favourable terms[38], though industry interest will once again depend on long term policy, economics, and environmental controversy.

The Biden administration previously adopted a more restrictive stance on Arctic drilling. Notably, in 2023 the DOI cancelled all ANWR leases issued in the prior Trump administration[39], citing legal and environmental deficiencies, and proposed strengthened environmental reviews. A rule was put forward to ban new oil/gas leasing on ~50% of the NPR-A’s acreage, Biden officials also moved to limit drilling in nearly 13 million acres of NPR-A by designating new “special areas” off-limits.

By contrast, the Trump administration’s return in 2025 has swiftly reversed course. In early 2025, the UEDTEP Executive Order reinstated the void ANWR leases and ordered agencies to facilitate lease development[40]. A federal court also vacated the lease cancellations in March 2025, effectively restoring the possibility of drilling on those tracts.

The ‘One Big Beautiful Bill’ budget act passed on July 4^th 2025 mandates the BLM to hold at least five lease sales over 10 years, offering at least 4 million acres per sale in NPR-A, as well as, four new ANWR lease sales by 2033[41], offering at least 400,000 acres each, with revenue-sharing incentives to Alaska.

The DOI rescinded Biden-era protections in mid-2025, it withdrew proposals that had elevated “special area” protections and instead approved a new Integrated Activity Plan opening much more of the reserve to leasing.

Interior Secretary Doug Burgum, 2025: “Alaska’s resource potential has been held hostage for years by anti-development ideologues”

At the federal level, the Bureau of Land Management (BLM) issues oil & gas leases (on federal lands) via competitive sales.

Leases on state lands open for bidding can be viewed here: Alaska Oil & Gas Lease Sales - DOG

VACA MUERTA, ARGENTINA

Argentina’s Vaca Muerta formation has emerged as one of the world’s most important shale plays.

As a medium-term investment spanning the next 20-30 years, shale oil in the Vaca Muerta region, offers an attractive breakeven per barrel.

Majority state-owned YPF reports a cost of ~$24/bbl at wellhead, and a breakeven of ~$45/bbl after lifting and development – figures which are broadly on par with Permian Delaware and competitive on the worldwide cost curve.

YPF’s inventory snapshot indicates decades of drilling at current activity:

- Gross well inventory of ~15.2k wells, ~10% developed so far

- Net equivalent inventory at YPF WI, ~8.8k wells, ~9% developed.

- At today’s cadence economic life of project would extend multiple decades, barring policy or market shocks.

Located in Neuquén Province, Vaca Muerta is a massive Upper Cretaceous shale deposit holding an estimated 16 billion barrels of oil in place (and over 300 T cf of gas)[42]. Over the past decade, Argentina – led by state-controlled YPF and partners – has unlocked this resource, driving a spectacular rise in oil output.

National crude production hit a 20-year record of 816,000 bpd in August 2025[43], 65% of which was shale oil from Vaca Muerta.

This is a 15% year-on-year increase[43] and marks Argentina as Latin America’s fourth-largest oil producer (after Brazil, Mexico, and Venezuela). For context, in 2018 Argentina produced only about 100,000 bpd from Vaca Muerta – the fivefold surge to ~530,000 bpd of shale oil in 2025 attests to rapid development.

The key risks for Vaca Muerta oil are policy and economic uncertainties rather than subsurface risk. A stable, market-oriented framework – one that ensures companies can profitably produce and export oil – would likely unlock the full potential of the shale.

On the other hand, if Argentina fails to maintain a favourable investment climate (such as durable guarantees on export rights and currency convertibility), development could plateau below lofty targets, forcing companies to redirect capital to more predictable jurisdictions.

Geologically, Vaca Muerta’s performance has exceeded early expectations. The shale is thick and high-pressure, yielding extraordinary well productivity. A typical VM well delivers ~30 barrels per foot of lateral in the first year, double the output per foot of top U.S. plays like the Permian’s Delaware/Midland basins (15–23 bbl/ft)[43]. This high productivity offsets the higher drilling and service costs in Argentina, enabling competitive economics.

Key players in the upstream segment include YPF (the largest operator, nationalised in 2012), which partnered with Chevron, as well as Pan American Energy (BP-controlled), Shell, TotalEnergies, Vista Energy (an independent), Pluspetrol, Tecpetrol (Techint Group), and others… in the landmark Loma Campana block.

These companies have progressively moved from pilot wells to full production drilling. Only ~8% of Vaca Muerta’s acreage is under development so far[44], focusing on sweet spots mostly in the oil window in central Neuquén, suggesting an enormous inventory remains still untapped and supporting production expansion for decades if fully developed. Industry plans are ambitiously targeting 1 million bpd of oil by 2030[42], potentially making Argentina a significant oil exporter. Argentina’s Secretary of Energy even floated a 1.5 million bpd long-term goal[44], though that would likely require additional investment and infrastructure beyond current trajectories. Achieving these targets will involve drilling thousands of wells; projections had called for ~24,000 fracking stages in 2025 alone, though cost challenges may temper that pace. Nevertheless, the upstream story of Vaca Muerta is one of rapid growth, transforming Argentina’s oil fortunes and positioning the country as a potential leader in non-OPEC supply.

Midstream, a critical challenge for Vaca Muerta’s oil boom has been infrastructure bottlenecks. The Neuquén Basin is landlocked, so moving large volumes of crude to market requires pipelines to Argentina’s coast or over the Andes. For years, takeaway capacity lagged behind output and is now being addressed through major infrastructure projects.

The primary route for Vaca Muerta crude is the Oldelval pipeline system, which carries oil ~600 miles to the Atlantic port of Bahía Blanca. Oldelval (Empresa Oleoductos del Valle) has been expanding its capacity, and additional pipelines are under construction.

A pivotal project is the Vaca Muerta Oil Pipeline (Vaca Muerta South) – a new $3 billion pipeline linking Neuquén directly to an Atlantic terminal.

Slated to start operations in 2027, it will initially add 180,000 bpd of capacity, expandable to 550,000 then 700,000 bpd with further phases. This consortium-built line (partners include YPF, Pampa Energía, Chevron, Shell, and Vista) is a game-changer: it will relieve congestion, lower transportation costs, and facilitate higher exports[45].

Already, incremental upgrades have allowed Argentina to begin exporting surplus crude. In 2023, oil exports averaged ~110,000 bpd (up more than threefold from a decade prior)[42], and export volumes continue rising in 2024–25 as output grows.

Most exported crude is Medanito light sweet (the flagship grade from Vaca Muerta) which has found buyers in regions like Asia and Europe, given its quality. Domestically, Argentina’s refining capacity (around 600–700,000 bpd) can absorb a good portion of production, but with output now exceeding consumption, exports are essential.

In addition to pumping crude to the east, there is a smaller pipeline connection westward: intermittently, Argentina has sent modest volumes of oil to Chile through the OTASA pipeline to reach the Pacific, though the main thrust remains towards the Atlantic.

Pampa Energía is investing $426 million in a new 45,000 bpd crude treatment plant at its Rincón de Aranda field[43] to handle increasing volumes. Gas infrastructure (like the new Néstor Kirchner gas pipeline) also indirectly supports oil by freeing up field logistics, but since our focus is crude, the key takeaway is that midstream constraints are gradually being removed.

By the late 2020s, pipeline capacity should no longer be the limiting factor for Vaca Muerta oil – a stark contrast to the early 2020s when takeaway was a serious bottleneck. This build-out is crucial for hitting the lofty production forecasts, as analysts have noted that shortages of pipelines and storage were weighing on output growth and keeping costs higher. With new pipelines in place, Vaca Muerta’s oil will more easily reach export markets, enhancing Argentina’s trade balance and encouraging further upstream investment.

Vaca Muerta’s oil development has rapidly improved its cost-competitiveness, approaching parity with North American shale plays. According to McKinsey, the technical breakeven price for Vaca Muerta shale oil is around $36 per barrel[43]. Rystad Energy similarly estimated recent breakevens around $40/bbl or lower - below typical U.S. shale breakevens ($40-50/bbl) as of 2024[42].

These figures reflect major gains since the early 2010s, when Argentina’s shale was thought to need $70+ prices.

However, inflation and Argentina’s economic turmoil have brought new challenges.

On October 7^th, Argentina’s Energy Secretary noted that Vaca Muerta production costs were 35–40% higher than in the Permian[44], due to surging labour, equipment, and financing costs. Inflation and currency volatility mean services (often priced in stronger dollars) have become expensive in local terms. This cost uptick, combined with the current oil price dip (~$65 Brent), has squeezed margins and caused a short-term slowdown in drilling activity[44]. The number of new wells and frac stages per month began to plateau or decline slightly this summer as firms reacted to lower prices and higher costs[44].

So, whilst Vaca Muerta’s fundamental breakeven might be $35–40, the effective breakeven (accounting for current inflation and risk) is almost double. If oil prices stay moderate (~$60-70) and costs aren’t contained, growth could slow; conversely, a stable economic environment and $80+ oil could unleash another surge of investment.

Future Potential

The Vaca Muerta play is often compared to the Permian Basin a decade ago – a vast resource with many years of drilling ahead. The largest future potential lies not in single “mega-projects” (as in offshore developments) but in the scaling up of drilling across the formation. Many concessions in Vaca Muerta are still in pilot or early development phase, especially on the oil side. As companies move to full-field development, each could add tens of thousands of barrels per day. For instance, Chevron, already a major investor with YPF, stated in 2025 that it expects its Vaca Muerta production to more than double by 2030[43].

New entrants and joint ventures are also lining up. International majors like Shell, Equinor, Petronas, and ExxonMobil have all taken positions in Vaca Muerta blocks.

On a macro level, the production forecasts of 1.0–1.5 million bpd by 2030-2033 imply roughly doubling the 2025 output. This will require continuous drilling and completion on a larger scale, but the resource base is certainly there.

For context, Argentina’s Ministry of Energy reported Vaca Muerta’s proved shale oil reserves at only a fraction of the total potential, indicating that as drilling expands, reserves will grow in tandem.

In terms of projected field lifetime, Vaca Muerta could sustain output well into the 2040s. Shale wells decline steeply, but the play itself doesn’t have a fixed “end date” – as long as new wells are drilled, production can be maintained or grown. We should note that while oil is the focus here, Vaca Muerta also contains huge gas potential, and gas development (for domestic use and future LNG export) might drive investments that incidentally benefit oil (by building out roads, power, etc.)

The crux of the issue: It’s Argentina….

Besides the terrible macroeconomic situation, realising Vaca Muerta’s promise hinges on Argentina’s policy environment, which is famously unpredictable. Unlike the U.S., where private sector and mineral rights drive shale development, Argentina’s government policy plays a huge role – from controlling currency exchange to setting oil prices.

During the 2010s, investment was hampered by regulated oil prices (the “Barril Criollo”), capital controls, high export taxes, and the aftermath of YPF’s nationalisation. However, recognising the strategic importance of Vaca Muerta, recent governments introduced some incentives – for example, allowing producers to export a portion of oil at international prices once certain output thresholds were met, and special regimes to access U.S. dollars for debt payments.

The geopolitical/policy landscape shifted in late 2023 when Argentina elected Javier Milei, who campaigned on radical free-market reforms. By 2024, Milei’s administration moved to encourage energy investment, aiming to “bolster dollar reserves” through oil and gas exports[44]. Industry players (Chevron, TotalEnergies, Tecpetrol, etc.) have urged the government to remove barriers; they want guarantees that exports won’t be restricted and that currency controls will be lifted. These are crucial for profitability – without the ability to repatriate profits in hard currency, foreign investors should be wary.

Milei’s government has signalled intent to loosen exchange controls (e.g. allowing firms to keep some export earnings offshore) and reduce punitive taxes. Still, Milei faces an opposition-controlled Congress and many of his reforms have stalled.

Compared to some other countries, Argentina does not face significant insurgency or security risks in its oilfields, and relations with importers (like agreements to potentially send oil to international markets or swap for refined products) are generally good. However given the political risk associated with investing in Argentina, the once privately owned, now majority state-owned enterprise YPF S.A. should serve as a reminder to any would be wildcatter to treat the region with caution.

LEXICON

API Gravity

A measure of crude oil density; higher values indicate lighter oils. WTI ~40°, Brent ~38°, WCS ~20°.

BLM (Bureau of Land Management)

U.S. federal agency managing onshore oil & gas leases including Alaska’s NPR-A and ANWR

Brownfield Project

A brownfield project expands or modifies an existing oil and gas operation, making use of existing infrastructure. Brownfield projects have lower capital requirements, faster development timelines, and lower breakeven costs. For instance, brownfield oil sands expansions can achieve breakeven around $47/bbl.

Dilbit

Diluted bitumen; a blend of bitumen and light hydrocarbons enabling transport via pipeline.

DRU (Diluent Recovery Unit)

Facility that recovers and recycles diluent from Dilbit to improve transport economics

EROEI (Energy Return on Energy Invested)

Ratio of energy output to energy input in fuel production; kerogen oil shale typically ~1.5–4:1

Galoter Process

Estonian oil shale retorting method using hot solid ash as a heat carrier for efficient pyrolysis.

Greenfield

A greenfield project is a completely new development built from scratch on undeveloped land. Greenfield projects have high capital costs, longer lead times, and higher breakeven prices. For example, new greenfield SAGD oil sands projects typically require around $58/bbl to break even.

Kerogen

Insoluble organic matter in sedimentary rocks, precursor to oil and gas when thermally decomposed.

Kiviter Process

Vertical retort system developed in Estonia for pyrolyzing oil shale to produce shale oil and gas.

In-situ Recovery

Oil extraction technique such as SAGD used for deep deposits, injecting steam to mobilize oil underground.

NPR-A (National Petroleum Reserve–Alaska)

Large federal reserve in Alaska with ~8.7 billion barrels of recoverable oil targeted for new exploration.

Retorting

Thermal process for converting kerogen in oil shale into synthetic crude oil.

SAGD (Steam Assisted Gravity Drainage)

In-situ method using paired wells and steam injection to extract bitumen from deep oil sands.

SCO (Synthetic Crude Oil)

Upgraded bitumen product similar to light crude; ~31–33° API, ~0.13% sulphur.

Shale Oil (Tight Oil)

Light crude extracted from low-permeability rock via hydraulic fracturing, e.g. Permian, Vaca Muerta.

VKG (Viru Keemia Grupp)

Estonian private energy company operating Kiviter and Galoter oil shale retorts.

WCS (Western Canadian Select)

Heavy, sour Canadian crude (~20° API, ~3.3% sulphur) priced at a discount to WTI.

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