Bakken Update: Frac Sand Pricing Could Go Parabolic In Q3 2014

| About: U.S. Silica (SLCA)
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Demand continues for frac sand in the United States. In 2013, significant supply hit the market. This decreased average pricing. Current expectations are for a pricing rebound, as demand is increasing. Although we are seeing an overall decrease in the number of rigs drilling in the U.S., frac sand intensity continues to increase. US Silica (NYSE:SLCA) could be the best way to play this. I initially recommended SLCA back in early August. This has worked out well as the stock is up 46%. It is currently expanding production, and may have the best logistics in the business. It has underperformed other players in the industry, but may have more upside. Operators have started to adopt a new completion style. One that uses significantly more sand than any other method. It also outperforms all others, even slickwater fracs. These can cost from $2 to $3 million more. When compared to a standard completion using sliding sleeves, there is only a small increase in costs. The other method is cheap enough that it covers the increased cost of additional sand. SLCA will also benefit from the sale of 100 mesh. This is creating a new revenue stream within its oil and gas business. The very cold winter this year has hurt US Silica's Q4. I believed this was a buying opportunity. It turns out I was right.

There are several variables driving increased frac sand demand. The first is EOG Resources' (NYSE:EOG) new well design. In my opinion, EOG is the best unconventional operator in the United States. It continues to outperform analyst estimates on the top and bottom lines. I believe EOG's well design was responsible. Knowing sand costs would be substantial using this technology, EOG started self sourcing sand. With sand costs in check, EOG was able to keep well costs low. Once this design began yielding huge production numbers, EOG was able to continually beat estimates by a wide margin. Many analysts thought this outperformance was due to geology. This was believed until we were able to compare its results to other competitors in these areas. They didn't understand the benefit EOG was receiving from this sand heavy design. The map below provides EOG's results in the Eagle Ford.

(Source:EOG Resources)

The above IP rates are top notch. Gonzales County has been its best area. Some of its IP rates were above 7000 Boe/d. These results were on a tight choke. Some analysts believed EOG's well results were mostly due to geology. Once able to compare EOG's results to other operators near its acreage, we found its well design was responsible played a greater role. The map below shows the location of EOG's leasehold in the Eagle Ford. It had several reasons for leasing this part of the Eagle Ford.

(Source: EOG Resources)

The majority of EOG's acreage is located in the oil window, but bordering the wet gas. It chose this area because of its higher gas content. The largest oil cuts are seen further from the wet gas window, but there are lower well pressures. The closer the acreage is to the wet gas window, the higher the natural gas cut. Natural gas aids in pushing crude up and out of the well. This provides better IP rates and increases well pressure.


The above map shows the Eagle Ford gets deeper from the southwest to the northeast. It also increases depth from the Oil to the Dry Gas window. The deeper the interval the higher the well pressures. Deeper intervals in concert with a higher natural gas resource mix improve initial recoveries. EOG wanted oil dominated acreage, but still realized the importance of having some natural gas as a resource mix. It also wanted to maximize source rock depth to further increase those pressures. The shallowest areas of the oil window aren't economic, but we are finding Gasfrac's (OTCPK:OTC:GSFVF) LPG completion method does significantly improve recoveries in shallow horizontal wells with a very high percentage of oil as a resource mix.

(Source: Magnum Hunter)

The above picture provides other operators in Gonzales County. Magnum Hunter (MHR) and Penn Virginia (PVA) both operate in the same general area as EOG. When comparing the three operators, EOG stands out. The table below provides IP rates of these operators.

Well IP Oil IP NGL IP Gas
Baker-Deforest Unit 1H 3346 457 2.7
Baker-Deforest Unit 2H 4216 537 3.2
Baker-Deforest Unit 4H 4598 488 2.9
Boothe Unit 1H 5380 625 3.6
Boothe Unit 2H 3810 252 3.0
Burrow Unit 1H 5424 600 3.5
Burrow Unit 2H 6331 713 4.1
Henkhaus Unit 8H 4012 495 3.0
Reilly Unit 1H 3579 483 2.9

(Source: RRC of Texas)

The above results were operated by EOG. It uses between 1,500 and 2,400 pounds of sand per foot of lateral length. This is three to five times other operators. The average choke used by EOG in this area is a 34/64. Some believe EOG is opening up the wellbore to artificially improve short-term IP rates. This is not the case, but it has opened up some from its earlier wells. Well pressures have allowed EOG the use of an average sized choke. The table below provides Magnum's results in Gonzales County.

Well IP Rate (Boe/d)
Elk Hunter 1H 1303
Elk Hunter 2H 1514
Elk Hunter 3H 1456
Leopard Hunter 1H 1333
Hawg Hunter 1H 2289
Oryx Hunter 2044
Zebra Hunter 1H 2145
Rhino Hunter 1H 2218
Kudu Hunter 1H 1590
Southern Hunter 1321

(Source: RRC of Texas)

As you can see, Magnum's results lag EOG's. The total resource of Magnum wells are less than half just the oil from EOG wells. The table below provides IP rates from Penn Virginia's wells.

Well IP Rate (Boe/d)
Gardner 1H 1247
Hawn Holt 9H 1877
Hawn Holt 2H 986
Fojtik 1H 1209
Othold 1H 1629
Martinsen 1H 1878
Dubose 2H 864

(Source: RRC of Texas)

Penn Virginia uses one of the tightest chokes in the area (16/64). This artificially decreases short-term results. If placed on the same choke as Magnum, I would guess results are comparable. Neither of these two operators have results comparable to EOG's. Both are very good operators, but EOG is that much better. The reason for this outperformance is source rock stimulation. These are plug and perf with a cement casing. The multiple perf clusters per stage provide significantly better fracturing closer to the well bore. More sand is required, and results are better. This isn't just in the Eagle Ford, but also the Bakken.

(Source: EOG Resources)

EOG's core area is in the Parshall Field. This is arguably the best area with respect to the middle Bakken. Some would argue the Antelope Extension is better, as the Three Forks improves significantly. Most of the best middle Bakken wells to date are located in the Parshall Field. To the west Parshall is the Sanish Field.

(Source: Whiting)

Whiting (NYSE:WLL) operates the majority of the Sanish Field much like EOG in Parshall. The geology of both fields compare well, but EOG has had much better success. Whiting's results are below.

Well Lateral Ft. Proppant Lbs. 180-Day IP B/od Proppant/Ft. 180-Day Total Production/Ft.
16092 4994 495197 42 99 1.5
16068 6190 474452 159 77 4.6
16731 7625 1900000 582 249 13.7
16463 9815 1141429 469 116 8.6
17072 9398 1240000 660 132 12.6
16902 9516 1840000 494 193 9.3
17137 9644 1844000 354 191 6.6
16905 8739 1598000 340 183 7.0
17173 9612 1801000 482 187 9.0
17391 9538 1841000 839 193 15.8
17035 9466 1841000 761 194 14.5
17133 8872 1793000 432 202 8.8
17158 9500 1840000 916 194 17.4
17023 9443 1625500 873 172 16.6
17134 8607 1840000 620 214 13.0
16852 9432 1244000 531 132 10.1
17253 9509 1840000 568


17586 9698 1830000 509 189 9.4
16780 7719 1951000 549 253 12.8
17032 9473 1069000 466 113 8.9
17284 9461 1451700 233 153 4.4
16781 8365 2044160 347 244 7.5
16734 8482 1963740 278 232 5.9
17240 9378 1539000 280 164 5.4
17081 9645 1842000 828 191 15.5
17092 9537 1705000 1019 179 19.2

(Source: NDIC)

The Whiting wells above are from 2006 to 2008. These are Whiting's earliest in this field. The Sanish was one of the first developed in North Dakota. As you can see proppant usage has evolved since these fields were initially developed. An average well today uses between 300 and 400 pounds per foot. The table below is a list of EOG's earliest wells in the Parshall Field, from 2006 and 2007. EOG was much busier than Whiting, and had enough data to complete the table a year earlier.

Well Lateral Ft. Proppant Lbs. 180-Day IP Bo/d Proppant/Ft 180-Day Total Production/Ft.
16371 4392 1590000 681 362 27.9
16469 4705 2198291 690 467 17.9
16483 4394 1691400 600 385 24.6
16550 4433 1919090 506 433 20.5
16578 4753 2052859 610 432 16.4
16671 4638 1803224 555 389 21.5
16713 4664 1948307 821 418 31.7
16768 4471 1910795 903 427 36.4
16795 4308 1624300 1038 377 43.4
16457 4250 1091000 623 257 26.4
16467 4292 1789276 437 417 18.3
16497 4472 1738700 614 389 24.7
16532 4840 2039800 595 421 22.1
16543 5082 1538557 522 303 18.5
16635 4569 1752960 385 384 15.2
16637 5293 2182146 557 412 18.9
16776 3458 414000 444 120 23.1

(Source: NDIC)

EOG developed the Parshall Field earlier than Whiting did in the Sanish Field. That is why I had to use 2008 data in the Sanish Field. Even early on, EOG understood that source rock stimulation was the most important variable in completion work. It focused on short laterals, as this gave EOG better control of completion work. More than likely, it believed shorter laterals didn't stress the pump trucks as much. This provided for higher pressures during stimulation, and better overall fracturing of the interval. Because of this, EOG needed to use more proppant per foot. This led to much better production per foot results at 180 days. Even early in the Bakken, EOG understood that good source rock stimulation followed by large volumes of sand would produce better results. It is important to note, EOG in 2006 and 2007 was using as much proppant per foot as an average operator today.

To show how EOG's well design has evolved since 2006, I have provided newer wells in the Parshall Field. Below is a list of those wells.

Well Lateral Proppant IP 180 Proppant/Ft. 180-Day Total Production/Ft.
21378 6475 6867099 784 1061 21.8
22780 8916 9438324 770 1059 15.5
21239 7873 9023010 1082 1146 24.7
22091 10277 10369690 694 1009 12.2
22704 10662 10927550 648 1025 10.9
22703 6810 6972110 639 1024 16.9
20633 9672 10690860 932 1105 17.3
22921 9101 10530567 1186 1157 23.5
21406 10296 13623942 1013 1323 17.7
24281 9901 10178260 1298 1028 23.6
23764 11121 10880259 1241 978 20.1

(Source: NDIC)

As these wells continue to produce we get an idea of how the model is progressing. I had done an earlier article that modeled the production of the best Bakken wells to date. By using physical data, I could estimate how other wells will produce. I used the 90-day IP rate as a starting point, because earlier production could be affected more by the choke size. From day 90 to 360 days of production, the average of the top Bakken wells was 23.4%. Well 21239 using the new design, had a depletion rate of approximately 10%. Total production over that time frame was quite good. 21239 produced almost 360000 barrels of oil in the first year. There are newer wells in Parshall that have produced better, but there wasn't enough data. Well 21239 models as the best well EOG has done over one year of production, and the second best well of all time in North Dakota.

The data above is bullish frac sand pricing. Producers have a good outlook as completions continue to use more proppant per lateral foot. This is why I believe frac sand pricing could go parabolic. It benefits companies like U.S. Silica Holdings . Over the past 2 years, SLCA has grown significantly. In the short term, my expectations were for a better number. The combination of increased sand supply and decreased demand has proven difficult for Silica. This is a buying opportunity.

(Source: US Silica)

U.S. Silica reported a miss on both the top and bottom lines for 4Q13. Its top line number missed by $.72 million. The bottom line number missed by $.02. These results were in line with Silica's pre-announcement. Silica blamed poor weather for these results, as orders were cancelled, due to a difficult winter. January volumes were better, but increased costs continue to compress margins. Cost increases were also seen. In the first quarter of 2012, Silica had margins of $51/ton. The first quarter of last year, margins tightened to $39/ton. 4Q13 margins were $31/ton. This is worrisome, and should be watched closely going forward. Production growth does little if price realizations continue to decrease and costs increase. Some of this is due to product mix changes, such as greater use of 100 mesh sand. 2013 saw an increase of supply, so operators had a better choice of where to buy sand, which also affected the industry. Last year, US Silica allowed its customers to buy more sand than contracted for at the same low price in exchange for contract extensions. Margins could begin to widen this year as 72% to 73% of sand was sold under contract in 2013. Expectations are for a 50%/50% split between that and spot market sales. The biggest moves will be in 2015, as many of the initial contracts will expire and Silica could possibly sell its sand at the current spot price market. Silica maintains it will grant larger customers some leeway with respect to volumes over and above contracts. It seems Silica won't be as forgiving in a tighter market environment for other customers.

Even with the Q4 headwinds, Silica continues to grow the business. Year-over-year, quarterly volumes increased by over 20% to 2.1 million tons. Revenues climbed almost 26% to $149.5 million. Oil and gas volumes totaled 4.1 million tons, up nearly 40% for the year. Revenues for the oil and gas segment were up 44% year over year. Demand for all frac sand grades continued to be strong. Outside of oil and gas, growth was relatively flat. 4Q13 volumes were 1 million tons, which increased 3% on a year-over-year basis. Changes in frac design, continues to drive this growth. Keep in mind we are real early in this frac design. I believe there is significant room for improvement in source rock stimulation. This should continue to increase volumes of sand going forward. There was a lot of sand capacity brought on line in 2013. This seemed to balance supply and demand, but the new well designs could see sand usage double. Silica has increased its capacity with 2 new production facilities. It will have another 3 million pounds of capacity when Silica permits its new facility in Wisconsin.

(Source: Wisconsin Center for Investigative Journalism)

Silica expects it will be on line late in 2015. More importantly, transloads are decreasing costs. In 2013, it shipped 44 unit trains. This year it plans 80 to 100 unit trains. Its Utica mine offers margin benefits in getting sand to the Permian. This isn't only due to the sand's destination, but also the logistics of the Union Pacific. Silica estimates margin benefits of several dollars/ton with this form of transport. The frac sand will be received by its new unit train receiving facility in Odessa. This sand was supposed to head to the Bakken and Canada, but demand in the Permian has been so great it is more cost effective to rail it there.

SG&A didn't increase as a percentage of revenue, but it had a one-time charge associated with bad debt. This was $1.4 million charge, from a customer bankruptcy. DD&A increased to $10.1 million from $7.2 million year over year. This was due to increased depletion from additional volumes mined. Interest expense increased year over year due to refinancing of its senior credit facility. 4Q13 was $4.1 million versus $3.2 million a year earlier. Silica reiterated 2014 EBITDA guidance of $180 to $200 million. Capex of $75 to $85 million will be spent this year.

In 2014, growth in demand for frac sand should increase about 10% to 15%. Silica believes this could be a conservative estimate. Demand will begin to overcome supply, with a very tight market after the first half of the year. Most is from newer completion methods using 25% to 30% more sand. It has seen some completions require over 50% more sand this year. 100 mesh has seen more demand than other grades of frac sand. Operators are using this as a lead in proppant. This sand is very fine, and companies have found that if it is put down a hole first, it will prop open the micro fractures. This has aided production grades, but more importantly it is a lower margin product. Demand for 100 mesh was up 83% in 2013 when compared to 2012. This has worked well and I believe will allow for price increases in 2014. The market is already tight for 100 mesh, and there is no reason to believe this will decrease anytime soon. Demand for other grades of frac sand have increased by 33%. Costs were still high in January as the weather is still very cold. The problem could provide an opportunity to get back into the name. The last day of February saw wind chills of 20 below zero. So two-thirds of the quarter is already affected. This doesn't just cause logistical problems, but more importantly in the sand mines up north.

With demand growth between 10% and 15% this year, Silica looks to grow at a much faster rate. Silica believes it will sell roughly 5 million tons this year. This would create an estimated growth rate of 25%. US Silica is also figuring market share gains. Keep in mind, this would not include possible price increases, as it is focused on volumes. Silica entered 2013 with an 8% market share. By year end, this increased to 10%. The company believes it will do the same in 2014. Much of this gain is because of logistics. Operators don't have to wait for sand to be shipped, as this is done ahead of time. Since the sand is already in the basin, companies are seeking Silica's sand. Time is money, and it gets wells completed and the pump trucks off the pad. Some operators have turned over its rail cars, and now logistics are handled solely by Silica. US Silica is beginning to change the way we look at the frac sand business. It now can take control of the entire process. This starts at the mine and finalizes with sand at the pad. Less headache for operators busy managing fluids, equipment and manpower.

Hi-Crush (NYSE:HCLP) has had a better year than Silica with respect to stock price. It currently has a dividend of 5.4%. It reported a 60% increase in sand volumes sold in 2013 versus 2012. It sold 2 million tons, 600000 tons of this was sold in Q4. Hi-Crush's production costs decreased from $16/ton in 2012, to $12.50/ton in 4Q13. In 2Q13, Hi-Crush's average production cost was $13.10/ton. 60% of its sales are under contract. Average selling price was $74/ton. Hi-Crush states 2014 will see a significant ramp in demand for frac sand. 50% of Hi-Crush's sand goes to Texas. This reinforces Silica's statement on Permian demand. Pad development is going to increase the number of wells done. This is because costs are lower on a per well basis. These saved dollars can be employed in additional locations. Also, the Permian has more possible intervals to target than anywhere else in the U.S. These intervals are shallow when compared to other areas like the Bakken. Since pressures increase with added depth, operators can do all sand fracs. The sand will not crush out under the weight of the formation like it would in the Bakken. From the well files I have seen, the Permian sees more volumes per foot on average, than any other U.S. play. Hi-Crush is also seeing very good demand for 100 mesh. It has commented that this used to be a waste product. 100 mesh was less than 10% of its sales. Even with increased sales, 100 mesh hasn't cut into the volumes sold of coarser sands.

Emerge Energy (NYSE:EMES) has performed better than Silica and Hi-Crush. It also has the largest dividend yield at 8.9%. It isn't a pure sand play, as it has a fuel division. In 3Q13, Emerge reiterated what other sand producers are experiencing. In 2014, we are seeing more wells per rig, more stages per well, and more sand per stage. This is why sand producers will continue to outperform. For every foot of shale stimulated better, more sand will be required. No matter how we look at shale, it will take a certain amount of sand to keep the fracs propped open. So unless a more cost effective option is found, the frac sand business will continue to grow. Emerge states spot prices for coarser frac sands have stabilized after several months of oversupply. Emerge can produce 3 million tons of sand per year. Emerge produces a significant amount of coarse sand. Demand for 16-30 or 20-40 has picked up and been used more by operators.

(Source: Hi-Crush Partners)

Going forward, I expect gross profit margins, revenues, and EPS to improve. Gross profit margin was 42% in 2012. This decreased through 2013, until reaching the low of 31.2% in 4Q13. Over this time frame revenues increased. The table below provides my estimates of those figures in upcoming quarters.

1Q14 2Q14 3Q14 4Q14
Revenues 162 176 188 193
Gross Profit Margin % 35.2 36.1 37.3 38.2
EPS .40 .48 .53 .62
Price Target: $40

We are still in the early innings for the frac sand producers. Over the past year SLCA is up 37%. HCLP has done better with a 103% return. EMES has only been trading for 10 months and is up 177%. When EOG started developing its well design no one knew how it would affect the industry. Not only has it produced some of the best unconventional wells in the United States, but also is reshaping the industry. We know for a fact that this design increases production by at least 30%. Besides EOG, only a few operators have used this design, none of which have used it as its main completion method. Whiting was the first to adopt EOG's design and comment on the results. The new sand heavy frac design improved IP rates 33% in Hidden Bench, 41% in Sanish Field, and 116% in Missouri Breaks. Whiting also found this well design improved 180-day returns by over 10000 Boe. As other operators adopt this well design, we will see even better returns for the frac sand producers.

(Source: Hi-Crush Partners)

The past couple of quarters have been bearish US Silica as it has failed to impress. Revenues and EPS came in around expectations, so there were no downside surprises. Neither was there anything real bullish. Margins tightened significantly, and this could be an issue if Silica cannot stabilize pricing. I believe demand will catch up to supply in the second half of the year and push these names higher. I wouldn't expect 1Q14 to be much different from 4Q13, and I hope we get a pullback. I would look to start a position around $30/share. Margins in Q1 will improve slightly as we see pricing improve in March as weather improves. SLCA has made an important change to how it views customer pricing. While in 2013, SLCA was very accommodative, and at times would sell additional volumes over and above current contracts at lower prices. Now that the market is beginning to tighten, it looks to be taking a different approach. I believe 2014 margins will improve including 100 mesh. Not only will better logistics decrease costs, but also provides an advantage over its competitors. It is able to store sand on site, decreasing wait times for customers. It is important to note that frac sand price increases are inevitable. Operators are seeing big improvements using this sand heavy design. Whiting has seen IP rates double in some cases, while EOG has used this design to model the second best well of all time in the Bakken. When other operators start using cement casings and multiple perf clusters per stage, frac sand pricing could go parabolic.

Disclosure: I am long SLCA. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Additional disclosure: This is not a buy recommendation. The projections or other information regarding the likelihood of various investment outcomes are hypothetical in nature, are not guaranteed for accuracy or completeness, do not reflect actual investment results, do not take into consideration commissions, margin interest and other costs, and are not guarantees of future results. All investments involve risk, losses may exceed the principal invested, and the past performance of a security, industry, sector, market or financial product does not guarantee future results or returns. For more articles like this check out our website at Fracwater Solutions L.L.C. engages in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. It also provides contracting services for all types of construction at well sites. Other services include soil remediation. Please contact me via email if you are interested in working with us. For more of my articles and other pertinent information on the oil and gas sector, go to