Even as oil industry conditions spiraled lower last year and into 2016, a growth trend was evident: E&Ps were using increased proppant loading to capture greater production potential from each well. Addition¬ally, wells designed with longer laterals and tighter frack spacing were translating into a ris¬ing near-term need for proppant supplies, with the potential for a step change up in proppant demand if the rig count could sustain a recovery.

Current conditions augur for healthy growth in proppant demand. Can that demand be met by existing supply sources? Or are supplies likely to be stretched to the point of scarcity?

Tudor, Pickering, Holt & Co. (TPH) has been assessing potential demand for frack sand by basin. The energy research specialist has predicted tightening market conditions, potentially reaching scarcity, and has warned that logistical issues may further compound E&P efforts to secure supplies.

“We’re increasingly convinced that proppant loadings per well could grow substantially as operators increase lateral length and push prop¬pant per lateral foot well above current levels,” the firm said in a note to clients. “We believe average per horizontal well proppant loadings could conceivably climb from about 8 million pounds (MMlb) today to 11 MMlb in 2017, with further upside in 2018 and beyond.”

In such a scenario, it said, accessing prop¬pant could prove difficult.

“This level of demand would almost cer¬tainly lead to deliverability/logistical issues across the oil and gas space, as operators struggle to get their hands on enough sand to prosecute their high-intensity, frack-driven field development plans,” the Houston-based firm predicted.

TPH built its bullish proppant-demand thesis in stages.

As it constructed its frack sand model, the firm’s initial findings were positive, largely on the strength of its primary assumptions on drilling efficiencies and a rising rig count in an upcycle. Its conviction as to the robust outlook for proppant only grew as the team layered in further assumptions on increasing levels of proppant loading, according to George O’Leary, vice president, oil service.

For example, early estimates of frack sand consumption for 2018 exceeded the prior peak level of sand consumed in 2014 of 108 billion pounds (Blb). Estimates factored in a relatively conservative 7 to 8 MMlb of frack sand con¬sumed per horizontal well, in line with levels prevailing in fourth-quarter 2015 and first-quarter 2016.

However, ongoing research on E&Ps’ prop¬pant loading plans indicates that the TPH proppant intensity assumptions were overly conservative, and frack sand demand in 2017 and 2018 will “likely materially eclipse prior peak levels faster than we initially thought,” said O’Leary.

TPH’s second iteration of its frack sand model calls for consumption to rise to 111 Blb next year and to increase further to 147 Blb in 2018. These estimates represent a recovery from the 2016 estimate of 62 Blb and are based on 8 MMlb of frack sand consumed per hori¬zontal well.

Its projections could still prove too conserva¬tive, according to the TPH research team.

“Based on recent discussions with our E&P team and macro data we’ve analyzed, we believe proppant loading could be biased materially higher to 11 MMlb per well, which makes the latter assumptions—while still bull¬ish—appear conservative,” it said.

For historical context, the firm’s data showed frack sand consumed per horizontal well to have averaged 3.9 MMlb in 2013 and 5.2 MMlb in 2014. Despite the plunge in oil prices starting in mid-2014, proppant-loading levels per well projected for 2017 are expected to roughly double from 2013 levels. In addi¬tion, average loading continued to increase in every quarter in 2015 and into the first quarter of 2016, despite oil slumping to the mid-$20s earlier this year, said O’Leary.

It’s noteworthy that TPH’s anticipated growth in proppant use is tied to far more modest levels of rig activity than prior periods of peak proppant demand. Compared to 2013 and 2014, when just over 1,700 and 1,800 rigs were running, respectively, TPH is modeling an average rig count of approximately 650 rigs in 2017 and 900 rigs in 2018, up from roughly 400 rigs this year.

But while the rig count largely drives the firm’s estimates of proppant demand, other factors at play can lead to either more restric¬tive or more expansive outcomes. For example, assumptions in TPH’s initial two demand models had yet to incorporate the industry trend to use still longer laterals and larger proppant loading per lateral foot, lending the model a conservative bias.

These two factors are the main components behind the case for the amount of frack sand consumed per horizontal well growing to 11 MMlb in 2017, rather than the more conser¬vative assumption of 8 MMlb. And post the firm’s basin-by-basin outlook executed along¬side its E&P team, TPH analysts believe these trends will potentially continue propelling ulti¬mate frack sand demand per horizontal well to 11MMlb or higher over time.

To arrive at the projected proppant per well of 11 MMlb in 2017, the firm used some underlying assumptions: first, a 10% to 15% increase in wells’ lateral lengths and, second, a 20% to 25% rise in proppant per lateral foot. Together, these are expected to translate into a 35% to 40% jump in proppant per well from the first-quarter 2016 baseline of 8 MMlb. Additional upside may come from an unexpectedly higher rig count, or a higher mix of horizontal versus vertical wells, among other factors.

What upside numbers could these factors produce in proppant demand?

“We could see 140 to 160 Blb of demand in 2017, and 200-plus Blb of demand in 2018, which would be approximately twice that of the prior peak demand of 108 Blb in 2014,” said O’Leary.

According to Matt Portillo, managing direc¬tor in E&P research at TPH, proppant demand growth varies widely among basins, with the biggest contributors being the Permian, the Anadarko (Cana, Stack and Scoop) and, some-what surprisingly, the Haynesville.

Demand is projected to accelerate most sharply in the Permian, where it is estimated to reach almost 55 Blb in 2017, or, by itself, approximately half that consumed in the peak demand year of 2014. In the Delaware, annual sand demand is forecast to grow to 20.1 Blb, up from 5.6 Blb currently, while in the Mid¬land Basin it is projected to grow to 34.4 Blb, up from 12.8 Blb.

This escalation reflects lateral lengths increasing to 7,000 feet and 8,500 feet, respectively, in the Delaware and Midland basins, with proppant per lateral foot rising to 1,850 lb in both basins. The effect of these advances is to push proppant use per well to 13 MMlb and to 15.7 MMlb, respectively, in 2017.

In the Anadarko Basin, where proppant intensity tended to be weak before the last 12 to 18 months, continued progress in high-intensity com¬pletions is anticipated, with proppant per lateral foot in the Cana, Stack and Scoop rising to 3,000 lb, 2,500-plus lb and 2,000-plus lb, respectively. This compares to recent proppant levels of 1,800 lb, 1,500 lb and 750 bl to 1,000 lb, respectively.

In the Hayneseville, relatively low-intensity completions have until recently been the norm, using proppant per lateral foot of 800 lb to 1,600 lb, said Portillo. Drilling practices could surprise dramatically to the upside going for-ward, he said, with lateral lengths rising from 5,000 feet to 7,500 feet in leading-edge wells, and proppant per lateral foot rising from 1,700 lb to more than 4,500 lb.

“This basin could have the most intensive use of proppant per foot of any of the basins we cover,” Portillo said, forecasting proppant consumed per well of 20 to 30 MMlb.

Current conditions reflect comfortable levels of spare capacity—although the risk of logis¬tical issues remains. How quickly could the industry respond if proppant demand soared to the tune of 150 to 200 Blb?

Sand mines that are idle or shut-in—cur¬rently accounting for 20% to 30% of capac¬ity—would need to be restarted, which could take three to 12 months, depending on the state of the facilities, according to O’Leary. Incremental sand mines and processing facili¬ties would also need to be constructed.

And what would be the likely price impact, given that there is a widely recog¬nized, steep sand production cost curve across the industry?

“This would push sand pricing up the cost curve to the marginal cost of produc¬tion, which we believe runs from $10/ton to $60 to $65/ton. In the last upcycle, we saw sand prices run up to exactly that marginal extraction cost of $60 to $65/ton, which gives us some comfort in that range.”

Observers, including oilfield service provider Halliburton, have questioned to what degree future proppant tightness is likely to stem from a baseline of accelerating demand versus logistical issues. But the fun¬damental factor of sharply rising demand is clearly a critical driver. As with many com¬modities, only time will tell.