Guest Op-Ed: An Oil & Gas State of the Union
By Mark Hinaman
I’m an industry insider. I’ve had the unique opportunity to have a front-row seat to the shale revolution working as a project manager and engineer over the past decade, and 2022 has been a challenging year. The industry is generally being responsible, not growing production for the sake of growing production, and living within cash flows. I hear three talking points repeated on investor calls and in quarterly presentations:
- The world is short oil and gas which is going to drive prices up
- There isn’t nearly enough capital being invested to replace current supplies
- If the industry doesn’t advocate for energy dense fuels which better human lives, then no one else will
But what do they actually mean?
In 2014, as the price of oil was precipitously dropping, I remember looking at the output of an ARIES report and seeing the bottom line PV10 number was NEGATIVE two million dollars. In other words, if we drilled a successful oil well, then we would LOSE two million bucks. Seems like a dumb choice, right? We did it anyway because the mantra in the public markets was grow-at-any-cost. These industry-wide mistakes led to a glut of oil which drove layoffs, bankruptcies, and consolidation throughout most of the late 20-teens. They’re not being repeated in 2022, but unfortunately the pendulum has swung nearly too far the other way:
There is no capital available for oilfield service companies which is severely hampering necessary production growth.
Upstream oil and gas companies currently need to grow production to meet a growing global demand for oil and gas if the world wants lowered oil and gas prices, but even the mega-growth capitalist machine the American industry built over the past decade is starved for supply to do so effectively. Let’s use two anecdotes to call attention to the implications: the disconnect in available drilling rigs and frac fleets, and the volatile supply/demand imbalance in the frac sand market.
Currently, there are approximately three times as many drilling rigs operating in the US as there are frac fleets. You need both a drilling rig and a frac fleet to construct a horizontal shale well. Considering the average cycle time to drill oil and gas wells in the Permian is generally three times longer than the amount of time to frac a well, most would assume this disconnect makes sense – but does it? As drilling efficiencies inevitably improve and frac cycle times don’t keep up, there is a limit to how much the country can frac with the current number of approximately 250 frac fleets. Kimberlite highlights this point well in their recent research report:
Notice how historically drilling rig count and frac spread count have mirrored each other – until 2022. This is a huge problem for the world if we want more oil and gas as it will lead to slower or flat production growth and a flat or growing inventory of DUCs (drilled, but uncompleted wells).
Why hasn’t the frac spread count kept up?
Most of the pressure pumping equipment in the US that’s been built is currently in service. To build a new fleet, a pressure pumping company (think Halliburton, Liberty Energy, ProFrac, etc.) needs to invest approximately $65 million. Until 2022, their margins had been paper-thin or even negative to keep market share, and the truth is most of them simply don’t have the cash to invest. Furthermore, because their earnings have been low or negative over the past several years, the debt and equity markets aren’t available for them to go and invest in more fleets. Put another way: banks don’t trust them to make money, and they can’t issue more shares because the market doesn’t trust them to stay profitable.
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So what’s happening now instead? They’re charging significantly more for their service – think 30% to 40% profit margin instead of 2% to 10%. They understand the supply/demand imbalance present in the industry, and they’re making exploration and production (E&P’s) companies share the profits of inflated commodity prices. This is normal in a rising price environment and generally healthy for the market, but it’s horrendous for consumers and the rest of the economy. As the cost to frac wells increases, E&P’s will slow their growth and drill fewer wells. Why? If the capital cost of your project increases and commodity price remains flat, then the economics of the project worsen, and it becomes prudent to prioritize drilling only the most profitable wells. Even if commodity price increases, increased capital cost can impact the payback period and rate of return. This chart demonstrates the point through two scenarios:
- Scenario 1 - $9 million capital expenditure and $70 per barrel oil
- Scenario 2 - $13 million capital expenditure (44% increase) and $90 per barrel oil (28% increase)
Notice the simple payback period is nearly 8 months longer for the higher capital cost scenario, even though price has increased 28%. This has a real impact on project economics, and the inevitable outcome will be slower growth in the overall American oil and gas supply. Consequently, prices will remain high. In a world already struggling to cope with hyper-inflation, this is a bad recipe for the coming 12 months.
While the pressure pumping market is illustrative for large macro trends, the frac sand (aka proppant) market is a parallel example of how micro commodity markets can swing rapidly.
At the onset of the shale revolution, everyone knew you had to use solid media in all frac jobs which had a crush strength higher than the mechanical stress exerted by the reservoir. This solid media (most often, but not always, sand) was pumped during completion jobs and colloquially earned the name proppant because of its supporting role in the frac’ing process: it literally “props” open the fractures in the rock. Millions of dollars were poured into specialty proppants, identifying the theoretical characteristics which would optimize the granular material’s ability to effectively maintain permeability in the reservoir. New sand mines were opened throughout America to feed the growing demand for the ideal product with perfect roundness, excellent sphericity, and extremely high crush strength (yes, those are all real, technical characteristics).
Resin coating companies materialized out of university labs, specialty ceramics were studied and invented, and coveted Wisconsin All White Sand premium afforded the establishment and flourishing of long rail and trucking logistics businesses. During the boom's peak, prices approaching $100 per ton of raw material weren’t uncommon. To put this in perspective: a current frac job often consumes over 10,000 tons (or upwards of $1 million) of proppant. It was a bang-up business, but when forced to make something cheaper, petroleum engineers across the country contemplated, theorized, and innovated.
Did the premium characteristics of proppant really matter? Did every grain have to be perfectly round? How impactful was the variability in grain size? And was the crush strength truly critical to making good wells?
The Permian Basin was an ideal location for a proppant market disruption to materialize. As it turns out, there’s A LOT of sand literally just lying on the ground in west Texas and New Mexico. As the price of Wisconsin All White Sand skyrocketed, engineers and business entrepreneurs did what money-motivated enterprises in America do best: they took a chance and experimented. What if you used the sand lying on the ground in West Texas instead of shipping thousands of tons in hundreds of rail cars from Wisconsin? Sure, the sand isn’t quite as round, its turbidity is a bit higher, and the crush strength is about 1,000 psi less, but what if it still worked? Nobody’s using it, so it’s virtually free in comparison.
Enter Black Mountain Sand, Atlas Sand, and a myriad of other players who built sand mines all over the Permian basin. E&P companies came to realize the real relationship between proppant and production wasn’t the quality of proppant but the quantity. In other words, pump more proppant to produce more oil.
This paradigm shift was implosive. It drove down the price of proppant from over $100 per ton in 2012 to less than $10 per ton in 2019. Tragically for the proppant producers, when the bottom fell out of the market in 2020, many mines were basically giving away their product to meet bank covenants and make payroll.
That all turned around when the world’s voracious appetite for oil returned in 2021, and the effects were compounded in 2022. In the short span of just two years, proppant prices in the Permian basin and throughout the US exploded from less than $10 per ton to over $65 per ton. The reason was two-fold: the rate E&Ps returned to drilling and completing wells outpaced the supply the local sand market could support (even at pre-pandemic levels). The effect of the supply shortage was compounded because many mines skimped on maintenance to save cash during the pandemic which ultimately lowered their total output capacity. When the industry ramped up again, the dueling demands of required maintenance and maximizing production came to a head. Total industry capacity has remained depressed. Consequently, price has skyrocketed.
High proppant prices may be wonderful for a select few mining companies, but it ultimately increases the cost of drilling and completing wells. This subsequently lowers the profitability of domestic oil and gas development, which will slow the growth of domestic production. Again, in a world already starved for energy, this is detrimental for every other sector of the economy.
I despise highlighting problems but not offering solutions, so here’s an optimistic view on how this will play out: oilfield service companies will demonstrate several quarters of profitability, financiers will trust them again and invest in more frac fleets, sand mines will ramp up production, the United States will continue being a leader in global oil and gas production and technology development (potentially even exporting these systems to friendly countries), and prosperity will return to humans everywhere.
Finally, if we really want to slam on the gas (pun intended), then we’ll loosen regulations around the most energy dense fuel sources – especially nuclear – to make them even more investable by developers.
Mark Hinaman is a licensed professional engineer currently working as the Director of Engineering & Innovation at Franklin Mountain Energy. He also serves as the Executive Director of Denver’s Young Professionals in Energy chapter and is the Principal and Founder of the nuclear energy focused think-tank, Fire2Fission.