Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
The MMEX administrative PBR issuance is devoid of meaning.
I’ve submitted numerous Air 106..352 PBR (“Type O”) applications to TCEQ.
They are fill-in-the-blank on forms, and fill-in-the cell on spreadsheets, or spreadsheet interface tools.
TCEQ provides the supporting tools to complete these PBR’s - they are administrative permits, and can be completed by anyone who can transcribe numbers from a spec sheet, drawing, or table, into the appropriate places on the forms, and supply the check-list elements required by the application.
For those interested, you can go here for the details:
https://www.tceq.texas.gov/permitting/air/permitbyrule/subchapter-o/oil_and_gas.html
PBR processes are intended to streamline environmental permitting. The genesis is at the federal level, via USEPA, and they are implemented at the state level, where there is a USEPA proxy, for example TCEQ in Texas.
Holding an Air 106.352 PBR issued document proves only that the applicant can fill out a form, and follow a check-list. Texas statute requires issuance of the permit if the application is complete, and correct. If you can fill out the forms, and submit the application, you’re golden, provided you can come up with the $100 fee.
I’ve read MMEX’s 153-page application, and reviewed it in detail. There is nothing special, or otherwise remarkable about it. Like hundreds of other applicants, it complies with the TCEQ PBR requirements. Big deal.
Factually, MMEX did not itself do the work - a consultancy, Trinity, prepared, and filed the application on behalf of MMEX - MMEX lacks the internal competence to have even done the trivial completion of the application using its own staff resources.
A permit issued on the basis of a PBR process is of near zero value. It represents an administrative, regulatory compliance action. MMEX is waving this in the face of unsophisticated individuals as if it carries meaning and significance. It is worth $100, and the remainder of the costs MMEX paid for preparing it and submitting it are a waste of other people’s money - the company itself lacks even the most minimal skill set to prepare and file the application.
I know that people like me are a share selling scheme like MMEX’s worst nightmare - the combination of engineering, market, finance and regulatory experience, along with decades of industry experience poke holes in their fantasy gas-bag every time they try to blow it up. MMEX is a bag of gas, the stinkiest kind. If it somehow gets off the ground, it will just auger in. Go MMEX, Go!
I’m planning on attending the groundbreaking, to photograph the team before they get free state-awarded orange jumpsuits. MMEX forever!
Prepare to auger in at Mach speed…
MMEX's S-1 filing is a largely content-free piece of paper, consisting mostly of boilerplate, and poorly constructed narrative, representing an ill-conceived and shoddy "business plan," filled with more holes than a sieve.
There are thousands of individuals with oil & gas sector backgrounds, in engineering, marketing, and finance, with more than sufficient expertise to analyze the empty shell of MMEX's proposal. There are at least a few hundred with investment and finance experience in this sector - none of them would invest even a fraction of a penny in the MMEX fantasy. Refining is a complex, capital intensive business - I emphasize the word business, because MMEX has no idea of actual business requirements for this sector.
LOI's are worth exactly the paper they are printed on - close to zero. They are not legally binding, and do nothing more than express intent - no money is committed, no binding contracts are executed, and these documents carry no teeth or weight. They are as speculative as MMEX's fantasy S-1 filing.
Generating PR and buzz is cheap, especially when it is done with other people’s money.
A worthless piece of land in the Pecos County desert, obtained for $10 “and other consideration” is a non-event. Like MMEX, there are hundreds of individuals who own worthless land in Pecos County.
A $100 PBR from a state regulatory agency does not a business make, and any credible lender would ignore it in due diligence.
On the other hand, the refining sector, and thousands of competent experts have a very good handle on the profitability of refining operations, down to razor-thin margins. No industry expert would stand up on the notion that a topping unit can be a positive margin business. That is simple fact.
There is a reason that there has been no greenfield refinery construction since 1977 - it is not economically viable.
Expansion of an existing unit to increase capacity, or to increase product breadth is viable. MMEX and its supports appear to have failed even the most basic understanding of the economics of refining.
MMEX, by its own admission, has no internal expertise (as an aside, why would anyone finance a company with no expertise, and no track record, at the scale required to execute even the most minimally flawed "Phase I" MMEX plan?).
There are isolated cases where a standalone topping unit might be viable, but never as a cash-flow positive business, let alone an operating unit that could produce sufficient positive cash-flow to fund a Phase II 100,000 bbl "complete" refinery.
Those isolated cases are well-defined - they are in remote markets, like Alaska, which have insufficient infrastructure to deliver conversion products to the market, or where there is a partnership or existing subsidiary relationship with a complete refiner, or specialty conversion unit.
MMEX is none of that.
No sane, rational business, or "multi-year plan" would propose to build a crude topping unit, which could never be cash-flow positive - let alone all the other flaws and misrepresentations inherent in MMEX's "plan.”
If it ever gets off the ground, beyond a share selling scheme, the only thing MMEX can do is auger in, at Mach speed. It will leave a spectacular hole in the ground, for most that bought a seat on this doomed ride.
Fantasy is not reality. It takes actual competence, credibility, knowledge, and a viable plan to enter the refining business sector. MMEX is devoid of any of the necessary elements for success.
Yep, MMEX, primed to auger in at Mach speed. Go MMEX, go!
Totally correct...
No financing...
Positive cash-flow is a necessary element for investment.
If facts mattered, MMEX would not exist...
Facts matter...
Laughable...
Of the 21 claimed "milestones," all but two are hollow, empty, non-substantive PR, inflated to look like something meaningful.
Certainly, MMEX should get full credit for its $10 plus "other consideration" land purchase of worthless desert real-estate, and its $100 purchase of a TCEQ PBR issuance. What incredible milestones!
Get out while you still can...
Batting a big fat zero is more accurate...
What evidence supports a profitable topping unit in the U.S.?
Please support your claim with fact. Can you point to a single profitable, stand-alone topping unit operating in Texas, or the United States?
There is no substantive evidence that MMEX can execute on this talk.
Look at the source of the press release - same old re-hash.
The federal funds will help (and I emphasize the word help) repair the line, but they do not fully cover the cost. I have personally walked sections of the line south and west of Sulphur Junction, through Pecos, Brewster, and Presidio counties.
I have seen first-hand the conditions of the rail bed, trestles, track, and ties - it is comically deteriorated south-southwest of the Nopal Road crossing in Presidio County.
The "promise" of a train, carrying hazardous liquids on this route is laughable.
MMEX is nothing more than a classic share selling scheme.
It has everything. Let’s examine it, top to bottom:
- it has a shady, sketchy management team, who have no track record of success in the industry
- it has a web site that is misleading, but sufficiently fluffy to appear credible to an uninformed person
- the “financing” is a collection of toxic debt, structured to look like a legitimate security
- the “business plan” is superficial at best, including boilerplate lifted from various internet sources, on-line presentations, knit together with incomplete narrative
- the narrative elements of the “business plan” are non-starters, beginning with a “Phase I” implementation that can never generate positive cash-flow, which in turn leads to a “Phase II” requiring more than 10X the initial capital, with a significantly higher bar to successful entry
- all of this is financed by penny stock, which has never been used to successfully finance a complex, capital intensive business like a refining operation
- there is a single administrative permit in place, one easily obtained by someone minimally skilled in the field, for the filing fee of $100
- there is a sketchy purchase of a worthless piece of land, for $10 “and other consideration” - a special warranty deed executed to provide air cover for the scheme, to lend an appearance of “doing something” for the unsophisticated
- there is a “design” in place, lifted from a textbook, by a consultancy with no track record of delivery in the industry, with an estimated price that exceeds the industry average by 50% for a crude unit that does not represent a complete refining operation
- the MMEX proposed facility is located on a deprecated, barely functional rail line, which does not currently reach its most critical target customer
- using easily available, legitimate industry data, an analyst can implode MMEX’s “business plan” in less than 10-minutes - it is fatally flawed in every single aspect
- it has a network of promotors, attempting to artificially inflate the share price on the basis of false, misleading information
It is not at all difficult...
Circular logic fails to support MMEX as a valid investment opportunity.
MMEX is fundamentally flawed...
I've gone to the trouble to identify for those interested, all of the regional refiners within 300-miles of MMEX's proposed facility.
To enumerate them again, they include WNR/Andeavor in El Paso, Alon in Big Spring, and Holly-Frontier's Navajo unit in Artesia, NM.
All three of these refiners are complete refineries, with their own crude units - they have no need to procure intermediate feedstock from someone else's CDU.
Further, other than by OTR tanker, they have no means of shipping intermediate product from MMEX's proposed facility. Adding the transportation cost to each barrel of intermediate would be a non-starter for either the seller, or the buyer.
MMEX is fundamental flawed.
MMEX is a failed proposal, right out of the gate.
I have the requisite engineering background, and relevant industry experience to understand the refining process, and the business as a whole, beyond a layperson’s perspective.
I’ve read MMEX’s S-1, and all the other available material, including permit applications, press, and other legal filings.
MMEX’s S-1 is little more than a mix of artful fantasy, and boilerplate. This is a quote from the S-1, regarding MMEX’s “business plan,” excerpted directly:
"We intend to implement our current business plan in two phases, First, through our subsidiary, Pecos Refining, we intend to build and commence operation of a 10,000 bpd crude oil Distillation Unit that will produce a non-transportation grade diesel primarily for sale in the local market for drilling frac fluids, along with naptha and heavy fuel oil to be sold to other refiners."
As explained in other posts, there is no market for any of the intermediate products (raw diesel) as frac fluid. The only other use would be as intermediate feed or blend stock to an actual refiner, like Alon, WNR/Andeavor, or Holly-Fronteir Navajo, hauled out by OTR truck. Unfortunately for MMEX, all three of these regional refiners have complete, working refineries, than can produce intermediates for conversion from their own crude units. They have no need to purchase these intermediates from another source.
As anyone can see from the widely available schematic that makes up part of this board’s header, a CDU is a tiny part of an actual complete refinery. The intermediate products from atmospheric distillation are not directly marketable in any realistic sense - this is why there are no profitable stand-alone CDU’s in the continental U.S. - the Texas market has sufficient refining capacity, both regional and export, to make the addition of another small-scale refiner like MMEX a non-starter, more so if it is only a topping unit.
As anyone with any industry expertise or experience knows, a topping unit is a zero-margin component of a larger refinery - it cannot generate positive cash-flow on its own. That is a function of physics, chemistry, engineering and economics.
Circular logic surrounding a Phase I project that will be negative cash-flow, used to fund a Phase II project that requires greater than 10X the financial investment, along with actual operating and market expertise fails, even in the most basic debate. There is no business here, at least as proposed by MMEX.
All crude oil needs to be separated prior to further refining.
A complete refining operation includes separation, conversion, and blending capability.
Separation by itself (an ADU/CDU/topping unit) has zero margin add. This is why there are few of them in the U.S., and why none of them operate at a profit.
The simplest profitable, complete refineries include a distillation unit, a vacuum unit, a hydroskimmer, and some form of cracking unit.
Phasing for these units is to build them in "trains," in some capacity module matched to feedstock availability over time. A complete train would include input, or feedstock storage, the CDU, side-stripping capability, a vacuum unit, a reformer, and isomerizaton unit, along with infrastructure like de-salination, sulphur removal, output storage, and a blending/treating unit, along with finished goods storage and off-load racking for rail, truck and manifold/header capability for pipeline capability.
As opportunity increased, additional "trains" or streams of equipment would be added to increase throughput and output.
In the MMEX case, there would need to be a customer, or customer for raw diesel, raw/minimally processed naphtha, and resid, along with a means to ship it to that customer. The Sulphur Junction spur doesn't have connectivity to any refiner capable of using MMEX's purported intermediate products - it would have to be hauled OTR to WNR/Andeavor in El Paso, Alon, in Big Spring, or Navajo in Artesia, NM, all of which adds cost, and decreases margin.
A stand-alone topping unit, as proposed by MMEX, cannot possibly generate positive cash-flow under the on-the-ground, real-world circumstances in which it might exist, giving the benefit of doubt that this is other than a fantasy scheme.
The problem is that there are plenty of facts. Of the 30 refineries in Texas, three are CDU/ADU operations with no other capability.
Of those three, one is idle, one is nearing bankruptcy, and one is owned by an entity with additional refining capability.
Those are facts, all public information.
Existence proof would be surfacing an example of an operating CDU/ADU in the United States that is operating at a profit.
The only thing misleading to investors is MMEX's flawed plan, and superficial claims in its filings. Any investor who understands the refining business can immediately see through that charade.
Even at an academic level, it is well-understood that topping units operate at zero margin. A zero margin operation cannot generate any positive cashflow. The investment community understands this - it is taught in "refining 101" seminars and curricula across the U.S.
Refinery profit in part relies on positive crack spread, and a spread that is sufficient to generate a profit. There is no way that a topping unit has sufficient crack spread to generate a profit. That is simple math.
None of this is a matter of opinion, it is established fact, supported by readily available data. If MMEX requires a cash-flow positive business in its "Phase I" plan, in order to get to "Phase II" full operations, it is factually impossible to do so using a topping unit. That is all there is to it - no opinion is involved.
MMEX's two-phase plan is flawed.
Why one anyone invest in a nominal $50-million (over-priced) "Phase I" CDU that could never generate positive cash-flow, which based on MMEX's plan, is required to bridge to "Phase II," an $850-million investment in a full refinery?
What logic would need to be followed, if the "Phase I" element of MMEX's plan is doomed to fail?
There are already three regional refiners, including Alon's Big Spring unit, WNR/Andeavor El Paso, and Holly-Frontier's Navajo unit in Artesia, NM. These refiners have complete systems, including cracking capability, broad-stream processing capability, and established transportation networks.
Real investors know, and understand that. It is all part of the assemblage of real, verifiable facts, which is substantively different than the MMEX non-starter, unsustainable fantasy.
Data from AFPM, all of the analysts in the industry, and many more sources, which is in the public record, and readily available torpedo MMEX's fantasy.
It is easy, and cheap to create a fantasy paper trail, especially using other people's money. It is much more difficult to finance and build a real, profitable refinery.
A CDU/ADU will never generate cash-flow. It won't even get near break-even.
The data is there - simple math, and due-diligence. As cited, the three similar units in Texas that are in existence are suffering from bankruptcy in one case, idled/shuttered in another, and the third is a specail case, owned by and feeding a partner in the same stream.
MMEX has no business plan. It can't "phase its way in" to the refining business in the claimed manner. It is not economically possible.
The only place MMEX will be flying, is into the ground, at full mil-spec power, on afterburner... it will be a spectacular cork-screw into the desert.
There are no stand-alone ADU/CDU topping units operating at a profit in Texas.
Focusing just on Texas, for a variety of reasons, including transportation infrastructure, feedstock, and location, let’s examine MMEX’s “Phase I” crude topping unit plan.
In Texas, there are nominally 30 refineries, based on APFM data from January 2017. Of those, three are completely shuttered, non-operational facilities. Of the remaining 27 refineries, only 3 are stand-alone CDU/ADU topping units. All the others have cracking and conversion capability.
Of the three topping units, one is nearing bankruptcy - Lazarous/BDCO’s Nixon unit, a 15,000bpd system. One is idle, Magellen’s Corpus Christ unit, a 50,000bpd system. The third is Kinder-Morgan’s Galena Park facility, a 100,000bpd system, that runs at about 80% capacity - in that case, the intermediate products are moved to another Kinder-Morgan affiliate - they are not directly marketed.
There are no isolated, stand-alone CDU/ADU topping units that can operate at a profit in the U.S. - they are zero margin facilities, and cannot generate any cashflow.
Using MMEX’s flawed, and misleading 10-Q filing, for the period ending 31-July-2017, I quote:
"The most significant focus of our current business plan is to build crude oil refining facilities in the Permian Basin in West Texas. Through our wholly owned subsidiary, Pecos Refining & Transport, LLC (“Pecos Refining”), we intend initially to build and commence operation of a 10,000 barrelperday (“bpd”) crude oil distillation unit (the “Distillation Unit”) that will produce a nontransportation grade diesel primarily for sale in the local market for drilling frac fluids, along with naphtha and heavy fuel oil to be sold to other refiners.”
As previously stated, diesel fuel is no longer used by any reputable services company in, or as frac fluid make-up. In Texas it would require a special UIC permit from the Railroad Commission of Texas, and that permit would almost certainly be impossible to use in any location which requires drilling through potable water ground water aquifers - which is pretty much the whole Permian Basin. So there is no market for that stream, at least not in the form of frac fluid.
It might be near break-even to ship naphtha upstream by rail, but not by truck, to other refiners. The naphtha volumes however are likely insufficient to allow the unit as a whole to operate at break-even, let alone profitability. Shipping resid out is a complete non-starter. As MMEX has proposed this “business,” it would be a waste product.
There is no business here. MMEX, if it is serious and could be considered legitimate in intent is doomed to fail. That is reality. Anyone who can support this with evidence of at least one stand-alone topping unit, operating at a profit in Texas simply needs to offer up that evidence.
One useful building block is the Nelson Complexity Index.
Nelson Complexity is a means of assessing the cost and complexity of a refining operation, and assessing its value, and the potential value/margin of the refined products stream it can generate.
The complexity basis is the crude unit (aka atmospheric distillation unit, or topping unit), with a complexity factor of 1.0.
Additional capabilities like a vacuum unit, thermal units, etc., have higher complexity factors, which are additive - the higher the Nelson Index, the more complex and capable in general the refinery will be, and the higher its product stream value will be.
It is not a perfect measure for valuing a refinery, but it is a good start - it also factors in complexity as a measure of complexity/barrel, which is useful in comparing across different refinery operations.
An operation like BDOC's Nixon unit has a complexity index very near, if not 1.0 - it is likely possible to do a rough analysis of the Nixon unit from permit and other public documents to get a more accurate index. That value, combined with the known 15k bbl throughput would be a reasonable metric for BDCO's chances to do something like sell the operation at a profit.
Profitability and valuation of a refinery also relates to the type of operation. In the U.S., it is a tough road for CDU/ADU units, also known as topping or hydroskimming units.
These are not complete refinery systems. BDCO's Nixon unit appears to be a topping unit.
Topping units generate thin, to no margin - they have a tough time breaking even. The only product that is really directly marketable is kerosene, as jet fuel. The remainder, including resid, naphtha, and raw diesel need to be further refined for use. Without the ability to further refine, or "crack" these intermediate products, there is significant feedstock waste.
A topping unit is the "front-end" of a complete refinery. It would be a tough call to invest in an asset sale for a topping unit, because the investment to drive it into a profitable, higher margin operation would be substantial.
I'm posting here in response to a message from '56Chevy', regarding valuation methods for refinery operations.
This is greatly over-simplified, but valuing these operations and assets uses some blended set of techniques, including:
- Replacement Cost New (RCN)
- Complexity/bbl
- pure asset valuation
- market valuation
- income based valuation
Synthesis of these approaches, and comparative measures against similar operations, or a collection of normalized data can provide some insight into the valuation of a particular refinery operation.
RCN approaches require some insight into how one might approach an "equivalent" operation using current technology (modular refining), the cost of environmental permitting, which includes not just the permit/application fee, but the consulting fees, and time-value of money. I don't know much about BDCO's operations, but some of this would be dependent on how long the refinery has been in operation, how much sustaining investment was made, and what upgrades may, or may not be required to keep the unit operating competitively.
Without knowing more about BDCO's operations, it is hard to be more specific.
The sample assay, provided by MMEX without independent verification, falls into the high range for Permian Basin crude, and is in fact very narrow in spec, if broadly available, or even real.
To emphasize, a refining operation is optimized, and tailored to the crude feedstock readily available in the region, over a range. Range being the operative word. Too narrow, it fails. Too broad, it can't operate economically. That is a simple fact rooted in chemistry, physics, engineering, and finance.
I oft, and earlier acceded that Trinity is "real," and is happy to take anyone's money to provide consulting services for assisting with, or preparing a permit application. No debate.
VFuels likewise may be real, and it does seem to exist at least on paper. However, the entity has no traceable record of delivering modular refining products. A schematic on paper, which can easily be copied from a variety of sources, is substantively different than a product delivered by an engineering/product company with a verifiable track record.
I've not delved into the specific background of those at TCEQ responsible for the permit issuance. They may be clerical staff, they may be engineers, they may be a blended team. The central point is that PBR is an administrative task, not an engineering task. If the application meets statutory elements, it must be approved and issued - there is no engineering validation involved. I made no claim as to the veracity, or credentials of the TCEQ staff involved. A PBR is a "must issue," if it meets the check-box requirements.
Ground-breaking is a ceremonial, ritualistic PR event. One can do a variety of superficial things, stick a shovel in the ground, drive a tractor, dozer, etc. over a plot, and viola, we have ground-breaking. Years later, that plot will remain barren, other than the weathered shovel disturbance, because there is a substantive difference between poking a shovel into the dirt, and doing something real, like building a refinery. The latter requires millions of dollars (factually hundreds of millions), permits, environmental work, and actually doing stuff, besides hyping a penny stock or generating PR.
TXDOT may rehab the South Orient rail-bed, and eventually the bridge at the Rio Grande may be re-constructed, and opened for rail traffic. That is truly wonderful. And largely irrelevant.
Factually, on the ground in the Permian region, there are multiple terminals, and operators. Exxon is irrelevant in the discussion of MMEX, and what MMEX may, or may not do, or be capable of.
As previously stated, in detail, an atmospheric crude distillation unit (ADU or CDU) is only one small component, and partial front end in a fully capable refining operation.
One significant flaw in MMEX's postured plan is that an ADU/CDU forms a unit that can generate substantive revenue, and is operable as a "Phase I" stand-alone business.
Real crude oil, from an individual well-head, from a the pads on a group of well-heads, a field, and region varies in API, specific gravity, salinity, acidity, water cut, sulphur content, and metal load. It varies over time.
Real refineries, as opposed to imaginary refineries like MMEX's "Phase I" system have to cope with a feedstock variability that reflects what is actually coming from the well-head, local tankage, or aggregators in the field.
A refining unit operates efficiently within a relatively narrow range of feedstock chemistry. There are often multiple "pipeline" processing elements and front-end components to deal with factors like salinity, sulphur content, light ends, and so on. Otherwise the operation is vulnerable to interruption when the chemistry of its feedstock changes outside those narrow bounds.
An ADU/CDU must either operate inefficiently over a wide range of feedstock make-up, and waste the potential of side-band feedstock, or it must be tailored, along with other front-end elements to deal with the real world.
Where is the evidence in MMEX's TCEQ, or other supporting documents that this is understood, and embedded in the business plan?
WTI is a “synthetic,” benchmark financial product. It is only real in the sense of a blended product at the Cushing hub.
With that, WTI has an API of around 39.6 and specific gravity of about 0.827. It contains about 0.24% sulfur thus is rated as a sweet crude oil (having less than 0.5% sulfur).
MMEX’s application to TCEQ, containing numerous tables, drawings, and so on, states on page 76, the “Crude Oil Whole Properties and Light Ends” tabulation of the input feedstock, a substance known as “Diamond Rogers Blue,” with an assay provided by, wait for it, MMEX. This substance has an "API of 43.7, Specific Gravity 0.8077, with a Sulfur content of 0.03% ."
Where is the independent assay?
MMEX’s application to TCEQ contains numerous boilerplate schematics (not to be confused with actual engineering, or process drawings) that meet TCEQ’s needs, but are otherwise meaningless. A cursory internet search, or cut-and-paste from a basic hydrocarbon refining text could be used to produce these schematics - no actual engineering expertise is required.
A freshman, or marginal undergraduate could produce these “artifacts,” which seem legitimate on the surface.
Even marginal engineering student would rapidly figure out that a process, and refinery engineered for the curious “Diamond Rogers Blue” crude would need to reject the majority of actual Permian Basin crude feedstock.
Challenge MMEX and its representatives to provide verifiable source data on the assayed “Diamond Rogers Blue” crude feedstock, how it is superior to the WTI benchmark, and how they might be entitled to use such a superior feedstock...
Please cite a single, verifiable delivery of a modular unit from VFuels, LLC, or its apparently associated entity, VGas LLC, which resides at the same Houston area location, albeit with different management.
I anxiously await your evidence.
No news here, and absolutely nothing new at all, just the same B.S.
Unfortunately, there are few real journalists left, and this “article” is just one more example of a cut-and-paste jumble of prior PR, a couple of statements from the company’s principle, amounting to “I am not a crook,” and little else.
The special warranty deed used to acquire the nominal 126-acre tract, of essentially worthless land in Pecos County for $10 and “other consideration” are a matter of public record. “Other consideration” usually amounts to warrants on worthless stock - perhaps I am too negative - potentially worthless stock, unless the seller is able to dump the shares before the bottom falls out.
VFuels was established in early 2017, and has no track record of delivering anything in the modular refining market in the U.S. - I’m too lazy to search Nigerian records. There are other established modular refining engineering and production outfits in the U.S., in Texas, who have actual track records. Why didn’t MMEX partner with one of them?
The KPE thing is nothing more than a future promise, like the LOI in place with a mid-market crude supplier - it is immaterial.
The TCEQ ADU/CDU permit, a PBR, is similarly of marginal value - it can be had for the $100 filing fee, and if one is incompetent in the field, paying a consultancy like Trinity a few thousand dollars to fill in the blanks and file the form.
Transportation costs vary - a Texas 407-code compliant tanker can haul about 8,000 gallons safely (200 bbl). Costs range from $3/bbl to $6/bbl, and they are usually split 80/20 between the independent driver/hauler and the transportation company.
Using those figures, and an average speed/distance calculation (based on a claim that the crude source is one hour away from the proposed refinery location), that is about 60-miles, which would put the hauling costs in at about $4.50/bbl.
On a 10,000 bbl unit, you’re looking at a minimum of $45,000/day just in transportation fees - it is actually more than this, because you have to haul in the process required quantity plus a pad. It is also still 50+ trucks - the “B-train” OTR tanker thing is a total fantasy, because they’re not used in Texas due to GVWR limits.
Those hauling, and associated costs persist until someone builds a pipeline or pipeline network to supply the facility. At the current WTI spot, the transportation costs by truck will run between 8% and 10% of a barrel of feedstock.
Since an ADU/CDU can’t produce anything that is directly marketable, the notion that it can generate some positive cash-flow is B.S. - anything, in whatever quantity it manages to produce would have to be hauled out, and refined by an upstream refiner, if there is one willing to take intermediate refined product. There might be a market for naphtha and raw diesel, but it would be thin. There is very little market for resid, at least in the form of purchased feedstock.
Back to first principals: You don’t “phase your way in” to a refining business, at least not in the sense that an ADU/CDU forms the core of a revenue business in stand-alone form. You have to be able to produce marketable refined products, and if you are not cracking, reforming, and performing complete processing, you’re wasting significant quantity of the crude feedstock.
WTI is a market fantasy - oil coming out of a well varies in API, salinity, water cut, and sulphur content. A refinery has to be able to cope with a specific range and volume of crude, and crude content to operate efficiently and profitably. The idealized benchmark WTI doesn’t represent reality at the well-head, or at the crude terminal. Regional production spans an API from about 35 to about 43, with sulphur content all over the map, from sour to sweet.
An ADU/CDU lacking de-sulphuring capability, lacking desalination capability, the means of dealing with waste stream, and so on, is a non-starter. The resid, or bottoms represent valuable resources that couldn’t be processed in the proposed “Phase I” MMEX deal, and would at best have to be sold at a loss, and hauled out for processing.
It is trivially easy to look “real” on the surface, especially using other people’s money. A few bucks on a permit, a “land deal,” opening an office in Ft. Stockton (check lease prices there), and making PR by rehashing the same old B.S. is largely free. It is a long way between making noise, and building an actual refinery that can operate profitably in today’s market. This is true even if you think you can move product to Mexico.
This whole MMEX thing reeks of fantasy to anyone who’s come from, or is in the industry in any legitimate way.
Facts matter.
A “B-train” OTR truck/trailer system is essentially a railroad replacement system, used in places like Australia where there are limited rail lines, and limited length/weight restrictions. They are in limited use in the United States, and whether, and in what form, they are road-legal is based on individual state DOT regulations.
In Texas, “B-train” tankers are scarce - this is because TXDOT/DPS limits the GVWR to 80,000 lbs., and certain axle limitations. There is no value, and no means of loading a B-train tanker - at the quoted 200-bbl, at a nominal 6.8 lb/gal. for WTI-like crude, a fully loaded B-train tanker would come in at at GVWR exceeding 117,600 lbs., overweight by at least 37,600 lbs.
Oilfield hauling in Texas, for the most part, is by contract, using tankers with an 11,000 gal. topped off capacity. They are typically filled to less than maximum capacity, because of the GVWR and axle loading limitation. Crude terminals at bulk storage are equipped to handle a single-tank semi, and crude tank batteries need a truck with off-road capability, not a highway rig.
An LOI is worth only the paper it is printed on. At present, crude is in surplus in the Permian, and based on its assay may sell at, or below the WTI price depending on where it is sourced. As mentioned, WTI is a benchmark - not every barrel of oil coming out of the ground is the same, so the crude in the region ranges from API’s in the mid to high thirties, to the low forties. Sulphur content varies as well, ranging from sour to sweet crude. The crude supply is not the biggest issue - its transportation cost is, at least for the time being.
A crude unit (ADU/CDU) in isolation is not a business, and would not generate sufficient cash flow or profit to offset its investment and operating cost in this market. You don’t “phase your way in” to the refining business in this manner.
VFuel is another comedy - they are virtually unknown in the modular refining business, and got their start in Feb. of 2017 - fewer than 5 employees, no manufacturing presence, no track record. Pretty sketchy, almost as sketchy as MMEX. Trinity is real, but they’ll take anyone’s money. Again, they fill out forms to support PBR. No rocket science there.
Legitimate refining projects do not historically obtain their start as OTC-traded penny stocks.
These operations require scale to be profitable, and must be complete refineries, not simple atmospheric crude distillation units. A refinery is not built in phases, by starting with a front-end, at the scale of an in-field processing unit. Refineries in developing regions are modular, but in addition to ADU (crude, or topping units), also have vacuum units, reformers, cracking capability, de-sulphering capability, and so on.
Refineries also require well-developed infrastructure, including pipelines for feedstocks, fuel gas, electricity, and take-away capability, that includes rail, truck/bulk loading terminal, and pipeline connectivity to the markets they serve.
Using the crude feedstock as a starting point, without pipelines, how does the raw crude feed arrive? A standard barrel is 42 U.S. gallons. An over-the-road (OTR) tanker can carry about 10,000 gallons of crude, or about 238 bbl. To provide 10,000 bbl of input would require hauling in, likely by OTR, 42 OTR tankers per day, and placing it into storage, in some quantity greater than the 10,000 bbl throughput of the CDU/ADU. That presents a logistics and cost/margin issue in and of itself. To make the math easy, that is off-loading two tankers an hour, 24-hours a day. That could change, if there was a crude pipeline put in place, but that costs money, and it has to be a pipeline network, unless there is a single consolidated crude supplier who will guarantee that capacity.
In this case, there is a single rail connection on the Texas-Pacifico leased TXDOT South Orient line, which is marginal south of the facility to MMEX’s target market. Yes, there is a federal grant associated with rehabilitating more than 70-miles of road bed south of Alpine, and reconstructing the bridge near Presidio. So what. There is a big gap between the promise, and delivery of anything material on that single aspect of this project.
The rail line is largely useless as a crude feedstock source - the suppliers/producers are west of the spur. As it is, the spur is useless as take-away capacity, as there are no refiners south of the junction.
Setting all that aside, that region of the Permian produces a range of crude largely known as WTI. All WTI is not necessarily created as equal, some is sweeter, some is more sour. WTI is a proxy, based on a chemical make-up and spec. Its API varies, its sulphur content varies, its salt content varies, its water content varies. All crude oil is not created equal. The current “surplus” is generated by non-conventional means, and has high variability, depending on what region/structure it was produced from, and how it was (or was not) processed in the field.
Assuming a feed consistent with WTI, with an API in the high thirties, the stream yield on the percentage basis is about 2.00% flare/gas, 26.50% naphtha, 8.00% kerosene/jet, 31.50% raw diesel, and 31.50% resid/heavy oil (needs to be processed in vacuum).
A 10,000 bbl throughput unit, assuming no down-time, and steady-state processing would generate 2,650 bbl of raw naphtha, 800 bbl of kerosene, 3,150 bbl of raw diesel, and 3,150 bbl of resid. That neglects the water cut, which varies, but on average is about 1%. You can do the math on how profitable that would be, given that all three of the directly useable cuts require transport out of the facility, and further refining to be generally marketable. The resid and waste stream fractions are problematic, and their processing (or disposal) likely negates any profit on the usable cut from an ADU. This is why ADU is not a stand-alone means of generating profit.
All of that “product” must be moved out of the facility, either by OTR truck/tanker, rail, or pipeline. For the near-term, rail is a non-starter. For the near-term, pipelines are non-starters. That leaves OTR truck/tanker. That take-away for intermediate refined product is a huge margin hit.
If the feedstock changes to something outside the spec for WTI, for example sulphur content about 0.5%, or has a high salinity, the margins are further reduced, and the processing complexity/cost goes up.
If there were an actual business here, established refiners, like Andeavor, Alon, or Sunoco would be in the business already, ahead of a speculative venture like MMEX. MMEX assumes fantasy scenarios that can’t be realized. The S-1 contains no actual engineering or technical data, other than what was lifted from public sources ranging from Wikipedia, and plagiarized from industry publications circa 2000 - 2014, poorly pasted into the document without accreditation to the source.
The MMEX “jobs created” claim is also specious. For comparative purposes, a full-scale refinery operation like Endeavor’s WRU in El Paso, a 135,000 bbl system, employs fewer than 500 people. A modular, 10,000 bbl ADU/CDU unit can be started in a half-day by two people, and normally runs in an automated fashion, monitored by a single person. There might be a gate guard there… the basis used to sell this to the community and region is wholly false - there is no significant job creation.
Generating an illusion is cheap, and easy. Anyone can go out, contact a vendor, and get a quote on a CDU/ADU unit. Anyone can spend chump change on a consultant, or even a manufacturer to generate a PBR application to a state regulatory agency, spend the $100-bucks on the filing, and get a permit. Anyone can file an S-1 for change, using plagiarized material. Anyone can go out and buy rights to worthless land, for $10.00 and “other consideration,” and anyone can spend a few bucks generating PR. Spending a few thousand, or even a few hundred thousand of other people’s money to generate hype is trivial in this age. On the Internet, no one knows you’re a dog.
Some due diligence to consider:
On the surface MMEX and its Pecos County Refinery look like opportunity. Issuance of a TCEQ permit, a land purchase, news about the rail bridge at the Presidio Port, etc. all look like "good news.” Here are more fully-developed facts:
- the Pecos County land purchase of 126-acres, for $10 "and other consideration” - the Special Warranty Deed is a matter of public record, on file in Pecos County. “Other consideration” was likely warrants or some such - for those who’ve never visited Pecos County, near Sulphur Junction, land prices are rock bottom - the land has no agricultural use, most of the groundwater is brackish, and it is in a largely population-free part of West Texas.
- the $100 Permit By Regulation TCEQ for a 10,000bbl Crude Unit, which is obtained by filling in numbers on a form. The PBR process, and the permit are matters of public record, and on file with TCEQ. There is almost zero investment or effort involved in filing the PBR for a facility of this nature - it requires no engineering or analytic skills, and can be done by transcribing numbers from a spec sheet into the application.
- there is no legitimate financing behind this project.
- the fact that a crude distillation unit by itself is virtually useless, and does not form a complete refining operation.
- the fact that the Texas-Pacifico rail way (leased by Grupo Mexico from TXDOT) is virtually impassible south of Tinaja in Presidio County, TX, and that no rail bridge exists at the border crossing near the Port of Presidio as of this time.
For comparable data, using regional operations, the Alon Big Spring unit is a 73,000bbl throughput system, with a complete refining operation. The Andeavor/Western Refinery unit in El Paso is a 135,000bbl system, with a refined products pipeline into Mexico. In contrast, the "Phase 1" MMEX project is a 10,000bbl crude, or "topping" unit. It couldn't make any product, other than low quality diesel, which can't be sold for OTR use in either Mexico or the U.S. - a topping unit is the "front end" only of a refinery - one needs a vacuum unit, cracking units, desulphuring units, isomerization units, and blending units to have a system that can produce marketable products. A 50,000bbl throughput system is on the margin in terms of profitable operation, and requires huge investment to produce even a partial suite of refined products ready for market.