The Above Ground Oil Field: or, why $65 and $94 oil are inflection points for renewable fuels

September 7, 2015 |

60DoilUnlimited oil production, no exploration risk, positive on environment, cheaper than unconventional US crude — what’s not to like about certain biofuels?

This year, Joule Unlimited noted that a “10,000 acre plant represents a reserve value of 100 million barrels of Solar Fuels, equivalent to a medium-sized oil field,” and the company projects that $1.25B in CAPEX would uncover some $10B in oil reserves.

The company goes on to note that conventional oil fields deplete over time, require high-risk exploration, complex downstream refining, typically require costly exportation to reach a market, and have negative environmental impacts.

By contrast, solar fuel reserves increase over time, can be produced on demand, have a “copy and paste” roll-out, directly produce drop-in fuels, can be produced in any market that needs fuels, and feature a sustainable production system.

The idea of comparing petroleum reserves to biobased “reserves” for financial purposes is relatively new. It’s a difficult process initially for people to get their heads around because bio-based projects have, theoretically, unlimited potential over many years while petroleum reserves have finite potential.

However, the emergence of new petroleum technology — especially fracking — that changes the “finite reserve” value for a given oil field, reminds us that “proved reserve” is a flexible term, taking into account the feasibility and cost of recovery.

So much so that, as the US Energy Information Administration observed here:

At the end of 2008, the U.S. Securities and Exchange Commission (SEC) adopted a rule that made substantial changes in the ways oil (crude oil and natural gas liquids) and natural gas reserves are accounted for in the financial reporting subject to its jurisdiction….Briefly, the rule, “Modernization of Oil and Gas Reserve Reporting,” has four major stipulations. One changed the specification of the price of oil or natural gas that is used to determine whether oil and natural gas resources can be included in proved reserves. Previously, the price specified was the price on the last day of the previous year. The new rule uses an average of monthly prices…[also, now] companies will be able to include previously excluded resources such as “saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas.” Another change redefines “reliable technology” to broaden the types of technologies that a company may use to estimate reserves. And finally, in addition to proved reserves, companies may now disclose probable and/or possible reserves.

A group including BP, Shell and DuPont have been hard at work building a framework for “renewable reserve accounting” that parallels “fossil reserve accounting,” because the presence of recognized reserves assists in financing. More about that here.

In the case of Joule, seeing the company as a uniquely “low risk upstream play” is important in the context of raising project financing — clearly, there are more dollars chasing upstream exploration projects around the world than building downstream refining projects, and one limiting factor for biofuels has been the inaccessibility of affordable project finance.

Oil finding & development, lifting, refining costs

According to Ernst & Young in 2014, “A typical unconventional well will cost US$5 million to US$10 million, depending on the specific geology and local conditions,” and E&Y modeled a typical “unconventional production profile” of drilling 10 wells per month for 5 years. Here’s that profile — ranging from a peak of 60,000 barrels per day declining to around 25,000 in year 10 and 20,000 in year 20.


Lifting cost represents a spend of roughly $4.5 billion and the recovery of 210 million barrels of oil-equivalent (boe). Or, around $21/barrel. But the hidden bomb for oil exploration has been the average US upstream “finding & development cost”, which adds nearly $39 per barrel. Not to mention refining operations, which added $6.70/barrel (in 2009, the latest EIA reporting year).


Bottom line? Adding up the figures from E&Y and EIA, they average out to $66 per barrel for refined products such as gasoline or diesel, or $60 per barrel for a raw material input — taking into account the costs and risks of finding and developing below-ground fields.

The Joule equivalent

Joule’s advantage lies in the upstream “finding and development” costs and the elimination of a separate refining cost, since Joule produces the hydrocarbon directly. There’s hardly anything in finding — and, as Joule indicates, around $1.25B in development costs for 100 million barrels, or $12.50 per barrel. At 21,000 gallons per acre, over 20 years, which is a reasonable time-equivalent to oil field economics.

We’ve estimated “lifting costs” — in this case the operating cost of the biorefinery, at around $29.50 per barrel. (Our math? Joule notes it is competitive with $50 oil, and we’ve subtracted out the $12.50 for “F&D”, plus $8 per barrel for the cost of finance, or a roughly 20% return on $42 per barrel representing 30% returns for equity and 8% for debt on a 50/50 basis).

The comparison



The risk

In this case, Joule is an unproven technology at scale, and unconventional techniques such as fracking are now proven — the risk in unconventional F&D is project risk, and already captured in the F&D costs.

Looking at other biorefining projects in the conventional way

It’s a useful comparative concept, even though most biorefineries are simply refinery plays, and base their returns upon the lift in value from raw materials to finished products. It’s the crush spread compared to the crack spread.

In the US, the US Gulf Coast refiners are reported an average crack spread of $19 per barrel. So, at an oil price (then) of around $50 per barrel, there was a 38% return on the raw materials. Subtracting out that $6.70 refining cost, the returns came in at 25%.

By contrast, most “conventional biofuels” plays offer “crush spread” returns in the 12-15% range, according to CARD, which reported a $0.22 margin on a $1.70 net cost of corn. Adding in the operating costs, returns were around 9% for corn ethanol production.

According to refinery economics, it’s not hard to see the lack of enthusiasm for biofuels projects, excepting where there is a “sweetener” in terms of carbon prices — for example, RIN prices or carbon costs associated with California’s Low Carbon Fuel Standard.

Looking at conventional biorefinery projects in the unconventional way

In the case of Joule, and most algae projects, you can see projects in one of two ways. As a traditional refinery play— only, in these cases, the crack spread measures the differential between the value of carbon dioxide and refined products.

Or, as an unconventional upstream play. After all, carbon dioxide and water-based fluids are injected into unconventional oil wells (i.e. EOR, or enhanced oil recovery) and no one sees them as CO2 uplifting projects. So, we might consider these projects as unconventional oil plays that also use CO2 and water.

Let’s look at corn, for ethanol production, in this way. The F&D cost we’ve used is the cash rent cost for cropland, the lifting cost is the operating cost per barrel of oil equivalent, and refining is the amortized operating costs of the biorefinery.

(Costs are per-barrel of oil equivalent)



Notes on assumptions. We’ve used production economics from Iowa State, here. In this case, we’ve used the corn-soy rotation figures.

Iowa State gives us a $273 per acre “cash rent” value, and we’ve taken out 30% of that to represent the value of distillers grains as a co-product of fuel production. We’ve taken into account a 35% lower energy density, and used 180 bushels/acre and 2.9 gallons/bushel for the energy yield, and amortized the F&D cost over 20 years.

In the case of “lifting”, we’ve used the $760 per acre corn-on-corn production figure from Iowa State, here, and taken out the cash rent cost.

Finance: there’s no finance needed for F&D as it is a cash rent cost, and we have used 4% for agricultural finance for refining and lifting.

In the case of “refining” we’ve used CARD’s $0.45 per gallon opex for ethanol plants, and converted that into a barrel of oil equivalent figure).

Looking at unconventional feedstock projects in an unconventional way

Let’s look at MSW as a feedstock for diesel and jet fuel, in this way — and Fulcrum BioEnergy as a model. The F&D and lifting cost is zero, according to Fulcrum’s public disclosures on this topic. The lifting

(Costs are per-barrel of oil equivalent)


Note on cost assumptions. These are the latest available publicly for Fulcrum, but they have evolved rapidly over time and may have well come down.


How do RINs figure into the equation?

In the US, under the Renewable Fuel Standard, roughly 11% of US fuel usage is required to be renewable, and an extra barrel of unconventional oil refined into transport fuel would require the refiner to buy RIN credits as an offset of reducing renewable fuel blending by that one extra barrel. That costs about 68 cents per gallon or about $28.56 per barrel.

(Note: Fulcrums’s published operating costs are “net of renewable energy credits”, so there’s no added differential for a RIN value. for them).

If you wish to add that RIN value for the US market, that’s a fair way to account for the “carbon cost” of unconventional oil, at market prices. In that case, it adds substantially to the value of the Joule case, and roughly zeroes out the differential between corn ethanol and unconventional oil production, which may give you a good idea of why RIN prices are a) where they are and b) may be persistently there unless the EPA radically changes its formula for generating renewable fuel obligation volumes.

The Bottom Line

We can’t emphasize it enough: Joule is not yet proven to work at these economics, and Fulcrum is just now undertaking construction of their first commercial plant.

However, Joule’s is a modular system, with multiple iterations of the same small-scale unit, so “scale-up” does not entail the same risks as scaling up a fermentation technology, for example from 1 liter lab scale to 600,000 liter commercial fermenters. And, in the case of Fulcrum, it’s worth pointing out that they are technology aggregators, not technology originators — they are using technologies on an off-the-shelf basis.

With those caveat, we have to say the economics, as supplied by Joule and Fulcrum in their non-NDA public disclosures, are compelling vs US unconventional projects — and compared to conventional biofuels.

Suggesting that it may well be in the world of biofuels at world-scale, all power will transfer upstream. And that thinking should not focus so much around $50 oil, as much as $65 oil, and $94 oil. At $65, unconventional pays well, based on the economics we’ve seen disclosed.

At $94, unconventional oil can even afford to buy the RIN credits and displace renewable fuel gallons. The given economics of a given oilfield will vary from the average — but these are two benchmarks to watch.

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