DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, LEGAL ENTITY DISCLOSURE AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

7 September 2016 Americas/United States

Equity Research Oil & Gas Equipment & Services

Oilfield Services & Equipment Research Analysts

James Wicklund

214 979 4111

james.wicklund@credit-suisse.com

Jacob Lundberg

212 325 6785

jacob.lundberg@credit-suisse.com

Charles Foote

212 538 8444

charles.foote@credit-suisse.com

THEME

Enter Sandman: A Deep-Dive into the Only

Secular Growth Story in Oilfield Services

■ More Sand. Completion intensity is driving increasing sand use per

well/stage, as higher sand volumes generate higher production volumes

and returns for oil companies. We expect sand volumes to surpass 2014

levels with less than half the rig count by 2018. Sand will be the fastest-

growing sub-segment of the OFS market.

■ Born to Be Wild. Proppant stocks are the end of the oilfield service beta

whip. They have taken the mantle from land drilling contractors as the most

leveraged to an activity recovery. Stock prices dropped over 90% to the

bottom. Most have doubled from there. Like the land drillers of old, price

and volume improvements drive the strongest margin expansion in the

group. We think the move is far from over. There is a scarcity of investable

equity at ~$5B between four public companies in spite of five equity

offerings so far this year. Investor interest is very strong. Our deep-dive

confirms the fundamental positives in the sector.

■ New Focus. SLCA recently acquired a regional sand mine in Tyler, TX

(NBR), and SandBox, a company specializing in last-mile proppant

logistics. These two acquisitions brought investor focus to two new themes

in the industry: (1) regional (aka Tier 2 & 3 or brown) sand and (2) last-mile

logistics. In our view, regional sand will hold market share (currently ~40%)

for the next few quarters and last-mile logistics is the next frontier in the

industry value chain where proppant companies can create a sustained

competitive advantage.

■ Steep Slope. In addition to digging in to the aforementioned issues, we

built an in-depth industry demand and cost curve model. We adjust our

estimates for SLCA and HCLP accordingly and initiate coverage of

FMSA. We estimate proppant demand will be 49.4 M tons / 62.8 M tons in

2017 / 2018, up 48.6% / 27.1% YoY. Furthermore, we estimate industry

capacity currently stands at 110M tons, with 75M tons ready to work. Last,

we think the very steep slope of the industry cost curve gives low-cost

players (SLCA, HCLP, and FMSA) a structural and sustainable competitive

advantage.

■ Bottom Line. The Investment Policy Committee has added SLCA to the

U.S. Focus List. We reiterate our Outperform on HCLP, but are slightly

more cautious on the name until Northern White sand begins taking share.

In addition, we raise our SLCA TP to $49 (from $42) and our HCLP TP to

$17 (from $16). Furthermore, our SLCA 2017/18 EBITDA estimates go to

$163M/$363M from $167M/$278M and our HCLP 2017/18 EBITDA

estimates go to $53M/$146M from $73M/$138M. Last, in a separate report

today, we initiate coverage on FMSA, with a Neutral rating and $7 TP.

If you are interested in a copy of our industry demand/cost curve model,

please contact your CS salesperson or a member of the research team.

7 September 2016

Oilfield Services & Equipment 2

The Great Debate: Northern White v. Regional

SLCA's acquisition of NBR, a regional sand mine located in Tyler, TX, brought new light

on regional sand's rapid rise to its position in the market place today. SLCA projects

regional sand made up 41% of the sand market as of 1Q16. (See Figure 1.) We agree,

based on our conversations with industry participants.

Figure 1: Market Share by Sand Type

Source: SLCA

A few years ago, regional sand made up just 16% of the market. In the downcycle,

operators focused on costs and traded down to regional sand despite the performance

gap vs northern white sand. Concurrent to this trend, operators moved to boost IP rates by

increasing proppant intensity (sand per lateral foot). This drove share gains for regional

sand. In the Permian, regional sand has a $0.01-0.02 cost per pound advantage vs.

northern white, according to our industry contacts. To put that in context, in a well that

uses ~4M tons of sand (our estimate for Q3), this equates to between $40,000 and

$80,000 in cost savings. While this doesn't seem like much at first glance, the mindset of

private operators in the Permian (and elsewhere) is to flip mineral rights quickly. These

operators (often funded by private equity) are paid a multiple on the profitability and/or IP

of the wells. As a result, regional sand is an obvious choice, as costs are lower and there

is little impact on short-term IP rates.

Operators focused on long-term production and/or EUR are more likely to use northern

white sand. The long-term performance of regional sand is unclear, but is likely materially

inferior to that of northern white sand, given the intrinsic properties of the two sand types.

The key question is: which type of sand will deliver the incremental ton, northern white or

regional? We expect regional sand to at least maintain market share over the next two

quarters, as it will take time for the market to tighten. (See Figures 4 and 5.) In addition,

regional sand is more likely to be used in shallower wells (lower pressure, thus less of a

performance inferiority vs northern white sand). This is where many operators are drilling

and completing wells in the Permian today, which is the most active basin in North

America.

7 September 2016

Oilfield Services & Equipment 3

The other questions that are front of mind as it relates to regional sand are: (1) what is

capacity and (2) what is utilization? Some in the industry think regional mines are running

at full capacity, implying all incremental demand must come from northern white sand

(which we think is the consensus view). We disagree. We estimate regional utilization is

73% and that northern white utilization is 37%. (See Figure 3.) As we show in Figure 2,

total industry capacity is 110M tons. Of that, we think 35M tons are idle or shut-in today

(meaning 75M tons are able to work). We assume 25% of shut-in/idle capacity is regional

sand and that 75% of shut-in/idle capacity is northern white sand (based on historical split,

also in Figure 2). This means the regional market is much tighter than the northern white

market; however, it also means there is room-to-run in the regional market as sand

demand climbs from trough and operators remain cost conscious.

In Figures 4 and 5, we frame a scenario in which regional sand receives every pound of

incremental demand and a scenario in which regional sand maintain current share. Using

our demand forecast, each of these scenarios, we estimate regional capacity tops out

around 2Q17 (when utilization of currently able to work capacity rises above 100%). At this

time a rotation back to northern white sand should occur.

Figure 2: Frac Sand Capacity by Grade and Type

Source: PropTester

Figure 3: Utilization by Sand Type

Source: Credit Suisse estimates, PropTester

Sand Type Capacity % of Total Active Capacity Market Share Market Mix Utilization

Northern White 82.5 75.0% 56.50 60% 20.78 36.8%

Regional 27.5 25.0% 18.86 40% 13.85 73.4%

Total 109.99 75.36 34.63 46.0%

CS Projected Q3 Demand Annualized 34.63

7 September 2016

Oilfield Services & Equipment 4

Figure 4: Regional Sand Maximum Share Scenario

(All Figures Annualized)

Figure 5: Regional Sand Maintain Share Scenario

(All Figures Annualized)

Source: Credit Suisse estimates, PropTester Source: Credit Suisse estimates, Pro Logistics Group

It's a Logistics Game In its second recent acquisition, SLCA purchased SandBox, a storage, handling, and

wellsite delivery company focused on the frac sand industry. The acquisition brought the

importance of and innovation in last-mile logistics into the limelight. In our conversations

with industry participants, last-mile logistics are becoming increasingly important, as

effective timing can reduce inefficiencies. As a consequence, this reduces operators'

costs.

Furthermore, operators place a high value on frac sand quality control (i.e., knowing a

delivery of sand is uniformly a particular mesh and quality [because it has been in the

same container since it left the mine] is value-add). At present, last-mile logistics are very

fragmented and dominated by mom-and-pop trucking and logistics companies. The major

pressure pumpers have little desire to enter the asset-heavy, hypercyclical trucking

business, which has created an opportunity for innovation in the fragmented last-mile

logistics space. For these reasons, we believe there is opportunity for sand mining

companies to further vertically integrate into last-mile logistics (as SLCA did earlier in the

quarter). Herein, we detail a few interesting private companies that we think could be

targets for the public companies. Of the companies mentioned, SandBox is the only one to

own significant market share.

■ Solaris Oilfield Infrastructure. The goal of Solaris' system is to save space at the well

site and increase completion times. Solaris uses a rail-to-truck transload system and

mobile sand silo system to reduce truck demurrage, lower costs, and reduce silica dust

on site. The 12-silo system can hold 5M pounds of storage at the well site and can

deliver sand at an average rate of 23,000 pounds per minute. The system also has the

ability to simultaneously load and unload silos. (See Figures 6 and 7.)

3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Market Mix

Northern White 20.78 20.78 20.78 20.78 20.78 20.78

Regional 13.85 16.51 16.20 25.40 34.05 38.76

Total Demand 34.63 37.29 36.98 46.18 54.83 59.53

Check 0.00 0.00 0.00 0.00 0.00 0.00

Incremental Demand 2.664 -0.312 9.201 8.647 4.706

Active Capacity

Northern White 56.50 56.50 56.50 56.50 56.50 56.50

Regional 18.86 18.86 18.86 18.86 18.86 18.86

Total 75.36 75.36 75.36 75.36 75.36 75.36

Utilization

Northern White 36.8% 36.8% 36.8% 36.8% 36.8% 36.8%

Regional 73.4% 87.6% 85.9% 134.7% 180.6% 205.5%

Horizontal Rig Count 356 366 382 463 538 574

Increase from 2Q16 9.5% 12.7% 17.5% 42.7% 65.6% 76.6%

Well Count 2,225 2,278 2,179 2,657 3,096 3,303

Increase from 2Q16 11.2% 13.8% 8.9% 32.8% 54.7% 65.1%

3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Market Mix

Northern White 20.78 22.37 22.19 27.71 32.90 35.72

Regional 13.85 14.92 14.79 18.47 21.93 23.81

Total Demand 34.63 37.29 36.98 46.18 54.83 59.53

Check 0.00 0.00 0.00 0.00 0.00 0.00

Incremental Demand 2.664 -0.312 9.201 8.647 4.706

Active Capacity

Northern White 56.50 56.50 56.50 56.50 56.50 56.50

Regional 18.86 18.86 18.86 18.86 18.86 18.86

Total 75.36 75.36 75.36 75.36 75.36 75.36

Utilization

Northern White 36.8% 39.6% 39.3% 49.0% 58.2% 63.2%

Regional 73.4% 79.1% 78.4% 98.0% 116.3% 126.3%

Horizontal Rig Count 356 366 382 463 538 574

Increase from 2Q16 9.5% 12.7% 17.5% 42.7% 65.6% 76.6%

Well Count 2,225 2,278 2,179 2,657 3,096 3,303

Increase from 2Q16 11.2% 13.8% 8.9% 32.8% 54.7% 65.1%

7 September 2016

Oilfield Services & Equipment 5

Figure 6: Solaris Oilfield Infrastructure Figure 7: Solaris Oilfield Infrastructure

Source: Company data Source: Company data

■ SandCan. Similar to SandBox, SandCan's frac storage system is designed for

simplicity and allows the user to load the SandCan at any loading facility, ship it to the

wellsite, and use the SandCan direct to blender technology to place the sand in the

well. The direct-to-blender technology allows for 1M lbs. of constant frac sand flow

directly to the blender. This reduces wait time for the operator.

Figure 8: SandCan Figure 9: SandCan RT40

Source: Company data Source: Company data

The primary drawback to purchasing last-mile logistics is the price tag. SLCA paid $218M

for SandBox, which raised eyebrows. We don't have any financial data on SandBox, so it

is difficult to obtain a sense of an exact EBITDA multiple. If we use SLCA's estimate that

SandBox has 10% market share and assume sand demand in Q2 was 6.625M tons

(again, the mid-point of SLCA's range), it implies SLCA paid $82.3 per ton of sand, just

under the price per ton SLCA paid for regional capacity NBR. It's too early to tell whether

SLCA over/under paid due to (1) the lack of public precedent transactions and (2) all

synergies are not yet apparent. FMSA's and HCLP's balance sheet issues could make it

difficult to raise the necessary funds needed to make an acquisition of similar size in this

specific space.

The other logistics element to consider in the frac sand industry is access to and

placement along rail lines. In general, transportation costs make up the majority of costs in

the sand value chain. (See Figure 10.) In Figure 12, we display a comprehensive map of

the public companies' rail distribution networks. In our view, the public companies have a

sustained competitive advantage from a rail logistics stand point. The two Class I rail lines

that run to the Permian (the source of most incremental sand volumes) are the UP and

BNSF. SLCA, HCLP, and FMSA all have access to at least one of these lines at mines

7 September 2016

Oilfield Services & Equipment 6

that are operating today. Furthermore, each of the companies have exclusive access to or

ownership of a transload facility in the Permian. Having exclusive access/ownership

means fewer delays in delivery, faster unloading of sand upon delivery, and easier

storage. Similar to sand quality, streamlined logistics are increasingly more important as

costs are squeezed out of the system.

Figure 10: Sources of Frac Sand Cost Figure 11: Required Freight Mileage from Wisconsin

Source: Pro Logistics Group Source: Credit Suisse estimates

7 September 2016

Oilfield Services & Equipment 7

Figure 12: North American Proppant Logistics Map

Source: Company data, Credit Suisse estimates

Costs

The Curve

Another one of the characteristics that makes the sand industry unique is its cost curve. In

our conversations with sand, service, and E&P companies alike, there is a consensus that

the industry has an abnormally steep cost curve at the minegate. As previously discussed,

we estimate total industry active capacity is 75M tons. We estimate about one-half of total

capacity can be extracted for less than $20 per ton (37.5M tons). Much of this sub-$20 per

ton capacity (notably, HCLP's Wyeville [1.9M tons] facility and likely FMSA's Wedron

facility [7.5M tons of frac sand]), can produce at ~$10 per ton and even can drop below

$10 per ton if utilization increases and fixed-cost under-absorption is alleviated. As shown

in our frac sand supply curve (Figure 13), although only one-half of the industry's active

capacity can produce below $20 per ton, the minimum clearing price is lower, as there are

operators in today's stressed environment that continue to produce at a negative margin at

the minegate. Often times because these companies are able to deliver in-basin at a

Hi Crush Distribution/Logistics

Emerge Distribution/Logistics

Emerge Plants

Hi Crush Plants

Fairmount Distribution/Logistics

Fairmount Plants

U.S. Silica Distribution/Logistics

U.S. Silica Plants

7 September 2016

Oilfield Services & Equipment 8

cheap rate due to their physical location or advantaged freight rates and make a profit

through in-basin sales, while losing money on minegate sales.

Only a few mines in the entire industry are currently running near full capacity (Wyeville,

along with some regional sand mines). Therefore, cost per ton by mine/company is a

moving target. As utilization increases across the industry, costs per ton will come down

(improved fixed cost absorption). Nevertheless, we do not model a decrease in minegate

clearing price. As costs per ton fall, the increase in demand should support prices.

Owing to the variation in price per ton (factor of utilization) and to the significant supply

that was introduced to the market during the previous upcycle, it is difficult to know what

the cost curve looked like in 2012-15. As a result, we focused our research efforts on the

cost curve in a normalized environment. We use the cost curve shown in Figure 13 in our

company models.

Figure 13: Frac Sand Industry Cost Curve and Capacity

Source: Credit Suisse estimates

As evidenced by Figure 13, the slope of the curve increases rapidly from a $17.50 clearing

price to $40-plus clearing price. Being able to produce sand at a price below $20 is a

structural competitive advantage in this industry (so long as demand is sufficient to require

higher-cost supply in the market). Companies able to produce at this low cost have a built-

in margin at the minegate, as increased demand in the market pushes up prices. Of the

public sand companies, only HCLP, SLCA, and FMSA have the ability to produce below

$20 per ton (at certain mines). For the sake of our forecast, we assume the cost curve will

remain constant through 2018.

We are often asked: what characteristics make a mine low cost? In our conversations with

industry, we have identified that the key characteristics include: (1) geology of the

reserves, (2) royalty rate, (3) relative location of wet/dry plants, (4) machine types, and (5)

location of mine relative to rail access (perhaps most important). The conclusion here is

that large companies with established mines and know-how are in the best position. As

previously discussed, many of these characteristics influence our view that the industry

has relatively high barriers to entry.

9.4 28.1 20.0 7.5 5.0 5.0 0.0

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7 September 2016

Oilfield Services & Equipment 9

Demand We estimate total frac sand demand will be 33.2M tons / 49.4 M tons / 62.8 M tons in

2016 / 2017 / 2018, up 48.6% / 27.1% YoY, in 2017 and 2018.

Figure 14 demonstrates our sand demand forecast methodology. Herein, we explain each

step and the rationale behind our assumptions.

Figure 14: Credit Suisse Sand Demand Methodology

Source: Credit Suisse estimates

In June, we published a detailed activity forecast (the full methodology behind this report is

located in the appendix). We use the conclusions of that report as the first step in

projecting sand demand. In our view, the U.S. rig count will average 474 rigs in 2016, 599

rigs in 2017, and 718 rigs in 2018.

In our detailed activity forecast, we divide the US production in two broad buckets: core

and non-core. We explicitly forecast core (defined as the Permian, Bakken, DJ-Niobrara,

Eagle Ford, Marcellus, Utica, and Haynesville) activity (wells and rigs) at the basin-specific

level. To develop a comprehensive well count forecast, we calculate non-core rigs as total

rigs minus core rigs and consequently calculate non-core wells as non-core rigs multiplied

by non-core rig days per well. We assume non-core rig days per well will stay constant at

~14 days (the Q2 average) through 2018. We view this assumption as conservative, as 14

non-core rig days per well was above the average result (13 rig days per well) in our

historical period (back to 2012). To arrive at our total well count, we add core wells and

non-core wells together.

7 September 2016

Oilfield Services & Equipment 10

Figure 15: Credit Suisse Well Count

Source: Credit Suisse estimates, RigData

Using our well count forecast, we proceed to estimate the number of feet drilled per

quarter. To do this, we begin by forecasting the number of feet drilled per well using a

polynomial regression of feet per well regressed against total US wells. We derive a

formula that estimates feet per well based on our well count forecast. Historically, this

polynomial relationship has produced an r-squared value of 0.78, giving us confidence in

our forecast. Upon forecasting feet per well, we multiply by our well count to arrive at total

feet drilled.

Figure 16: Feet Drilled Per Well Figure 17: Total Feet Drilled

Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service Source: Company data, the BLOOMBERG PROFESSIONAL™ service

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7 September 2016

Oilfield Services & Equipment 11

Figure 18: Wells v. Feet Drilled

Source: Credit Suisse estimates, Spears and Associates, RigData

As the final step in forecasting sand demand, we estimate tons of sand used per foot and

multiply by total feet. In our forecast, we grow sand use per foot 2% sequentially from

3Q16 through 2018. At first glance this may seem aggressive, especially when considering

Figure 19 . That said, since the beginning of 2012, tons of sand per foot has grown at a

compound quarterly growth rate of ~6%. Furthermore, there has been a great deal of

commentary from companies (E&P and OFS) on the trend of sand usage per well. In our

forecast, sand usage per well increases mainly as a result of sand per foot increasing,

rather than feet per well increasing. We believe sand per foot is a more likely source of

sand demand growth, as feet per well historically declines as companies drill more wells

(i.e., drilling non-core, smaller wells vs. exclusively focusing on their most prolific, longer

wells). We show graphs of tons of sand per foot, sand per well and total quarterly sand

demand in Figures 19 through 21. As a result, we estimate sand demand to be 33.2 / 49.4

/ 62.8 M tons in 2016 / 2017 / 2018.

Figure 19: Tons of Sand per Foot Figure 20: Sand per Well

Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service Source: Credit Suisse estimates, RigData

y = -5E-05x2 - 0.2399x + 16705

R² = 0.7799

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7 September 2016

Oilfield Services & Equipment 12

Figure 21: Total Quarterly Sand Demand

Source: Credit Suisse estimates

Supply Frac sand industry supply is somewhat of a black box, given the high percentage of

capacity controlled by private companies. We estimate the four public frac sand

companies equate to about one-third of total industry capacity (all types of sand) and

about 40% of northern white capacity. The 800-pound gorilla in the room is Unimin, the

global oil and gas division of Sibelco, a private company headquartered in Antwerp,

Belgium. According to PropTester, Unimin has over 18M tons of potential annual capacity,

well eclipsing FMSA, the second-largest proppant provider by potential annual capacity.

From a cost perspective, we think most of Unimin's capacity (and all of its active capacity)

falls in the $15-20 cost per ton bucket (higher cost than HCLP's Wyeville and FMSA's

Wedron).

Figure 22: Total Frac Sand Capacity Figure 23: Northern White Frac Sand Capacity

Source: PropTester Source: PropTester

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7 September 2016

Oilfield Services & Equipment 13

Because there is so much shut-in/idle capacity, the natural questions to ask are: (1) how

long until this capacity could come back online; and (2) can new capacity come online

quickly if the market begins to tighten? In our view, capacity will be very slow to come back

for the following reasons.

■ Difficult to Find Reserves of Size. Many of the best mines of size (especially those

with advantaged rail access) are already permitted and are operated by players that

have the mining know-how and relationships with rails and customers to produce and

deliver high-quality sand at a low cost.

■ Burdensome Permitting Process. Regulation surrounding frac sand mining has

made the permitting process in Wisconsin (the state with the most northern white frac

sand reserves, by a large margin) onerous. This is not the case in Texas (permitting

can take as little as 90 days), where mineral rights holders take precedence over

surface land holders. That said high-quality/low-cost regional sand reserves are very

difficult to come by.

■ Labor. Most northern white frac sand mines are located in states in which the labor

force is not used to the cyclicality of the oil and gas business. As a result, many frac

sand management teams have expressed concern about hiring workers back to

northern white mines in a timely manner. This acts as a barrier to entry for existing

private players and new entrants.

For regional sand, the barriers to entry are lower (though still high relative other OFS sub-

sectors). However, if/when the market begins to tighten, we expect the trucking market to

tighten concurrently. As trucking prices increase, the cost of moving regional sand to the

well will also increase disproportionately vs. northern white (trucking is a higher

percentage of regional transport cost). Furthermore, once mines operating today reach

capacity, new mines will likely be further away from the well site, which compounds the

problem of expensive trucking costs.

Material Changes Table Price Price Rating* Target Price Year EPS EPS FY1E EPS FY2E EPS FY3E

Company Ccy 02 Sep 16 Prev Cur Prev Cur End Ccy Prev Cur Prev Cur Prev Cur

Fairmount Santrol Holdings, Inc. (FMSA.K)

US$ 7.84 NA N*[V] 7.00 Dec-15 US$ -.48 -.19 .36

Hi-Crush Partners, LP (HCLP.N)

US$ 15.03 O*[V] 16.00 17.00 Dec-15 US$ -.82 -.98 .66 .34 1.69 1.82

U.S. Silica (SLCA.N) US$ 40.94 O*[V] 42.00 49.00 Dec-15 US$ -.61 -.65 .55 .51 1.88 2.75

*O - Outperform, N - Neutral, U - Underperform, R - Restricted [V]= Stock consider volatile ( see Disclosure Appendix).

Company data, Credit Suisse estimates

7 September 2016

Oilfield Services & Equipment 14

Appendix

Credit Suisse Activity Forecast Detail

The fundamental assumption underlying our rig count projections is the amount of

production the US will need to deliver to global markets to satiate global demand. Our

starting point is the Credit Suisse house view on the call on US shale through 2018. We

smooth annual data out into monthly data so that we are able to marry that dataset with

EIA Drilling Productivity Report production data. We take production from the explicit shale

basins in the EIA dataset (Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian,

and Utica) to be equal to US shale production and assume the delta between the EIA's

total US production figure and explicit production among these seven basins to be equal to

US conventional plus offshore production. We assume a 7% annualized decline in

aggregate conventional and offshore production during the remainder of 2016 and a 6%

annualized decline in 2017 and 2018. We then assume the delta between our total US

production and our US conventional plus offshore production is equal to shale production

from the explicit seven basins in the EIA dataset.

Figure 24: US Production Assumption (kbbl/d)

Source: Credit Suisse estimates, EIA

We then take this implied shale production data and assume a particular distribution

among the seven basins. We (1) assume crude oil production from the Haynesville,

Marcellus, and Utica basins remains flat through year-end 2018; (2) fade the Bakken and

the Eagle Ford from their current 21%/26% of implied US shale production (as of the April

2016 dataset) to 18%/23% by year-end 2018; and (3) assume the balance comes from the

Permian. These assumptions imply that through year-end 2018, the Bakken will deliver

14% of US shale production growth with 19% from the Eagle Ford, 0% from Haynesville,

0% from Marcellus, 8% from Niobrara, 58% from Permian, and 0% from Utica.

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-15

Au

g-1

5

Mar-

16

Oct-

16

May-1

7

Dec-1

7

Jul-

18

US Conventional and Offshore US Shale

7 September 2016

Oilfield Services & Equipment 15

Figure 25: Shale Production Assumptions by Basin

(kbbl/d)

Figure 26: Shale Production Assumptions by Basin

(% of Total)

Source: Credit Suisse estimates, EIA Source: Credit Suisse estimates, EIA

This shale production by basin forecast is the starting point for our basin-specific rig

counts. We first project out decline rates. We illustratively show the Bakken decline curve

(change in legacy production divided by implied legacy production plotted against implied

new production) in Figure 27 with a polynomial curve. We use this curve to project basin-

specific decline rates going forward.

Figure 27: US Shale Decline Rate on Legacy Production vs Implied New

Production

Source: EIA

We then forecast legacy production as the prior month's implied legacy production (i.e.,

total production less implied new production, with implied new production calculated as

average rig count times production per rig) plus the prior month's implied new production

less the change in legacy production.

The last piece on the production side is we subtract implied legacy production from total

basin production to calculate implied new production. In Figure 28 , we plot our calculation

of implied new production (i.e., wholesale new monthly production that must be delivered

by newly completed wells). While at first glance, this would appear to be wildly bullish for

the US rig count, efficiency gains in rig days per well and increases in the productivity of

wells significantly dampen the number of rigs needed to deliver this production growth.

The completion of DUCs is another dampener.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Jan

-07

Ju

l-07

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-08

Ju

l-08

Jan

-09

Ju

l-09

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-10

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l-10

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-11

Ju

l-11

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-12

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l-12

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-13

Ju

l-13

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Ju

l-14

Jan

-15

Ju

l-15

Jan

-16

Ju

l-16

Jan

-17

Ju

l-17

Jan

-18

Ju

l-18

Bakken Eagle Ford Haynesville Marcellus Niobrara Permian Utica

0%

10%

20%

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-07

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-09

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-14

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l-14

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May-1

5

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15

Mar-

16

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g-1

6

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-17

Ju

n-1

7

No

v-1

7

Ap

r-18

Se

p-1

8

Bakken Eagle Ford Haynesville Marcellus

Niobrara Permian Utica

R² = 0.9011

(4%)

(4%)

(3%)

(3%)

(2%)

(2%)

(1%)

(1%)

0%

0 100,000 200,000 300,000 400,000 500,000

Ch

ang

e in L

eg

acy P

rod

uctio

n /

Imp

lied

Leg

acy P

rod

uctio

n

Implied New Production

7 September 2016

Oilfield Services & Equipment 16

Figure 28: US Shale Implied New Production (kbbl/d)

Source: Credit Suisse estimates, EIA

With the amount of new production per month each basin needs to deliver calculated, we

next project out production per well. We assume flat production per well in the Haynesville,

Marcellus, and Utica. In the Niobrara and Permian, we use the Bakken and Eagle Ford as

comps and assume the Permian and Niobrara reach peak production per well growth

about 1.5 years quicker than the Eagle Ford (which itself reached peak production per well

growth about 1.5 years quicker than the Bakken did). This implies a 20% production per

well CAGR for the Permian and the Niobrara through year-end 2018. For the Eagle Ford

and the Bakken, with no historical comp, we assume a continuation of the past two years'

growth trend at 75% of the magnitude, which implies 14% and 18%, respectively,

production per well CAGR through year-end 2018. From this figure, we calculate the

number of wells required to deliver the implied new production growth (implied new

production divided by production per well).

We then project out rig days per well (i.e., rig efficiency). We again assume flat rig

efficiency in the Haynesville, Marcellus, and Utica. For the Niobrara and Permian, we run

the same exercise as described for projecting those basins' production per well growth,

which implies a -5% CAGR in rig days per well for both basins. And for the Bakken and

Eagle Ford, we again assume 75% of the recent trendline growth which implies 11%

efficiency gains in the Bakken and 4% in the Eagle Ford.

Before calculating the number of rigs needed to drill the required number of wells, we bring

DUCs (drilled but uncompleted wells) into the fold. In Figure 29, we detail our assumptions

regarding DUCs. We assume DUCs are completed evenly spaced over either a 12- or 24-

month timeframe. In accordance with our assumed DUC cadence, we subtract our DUC

completion expectations from the number of wells required to deliver on implied new

production to calculated the number of wells that to be drilled. From this number, we

calculate the number of rigs needed to deliver on that number of wells.

Figure 29: Explicitly Modeled DUCs

Source: Credit Suisse estimates, the BLOOMBERG PROFESSIONAL™ service

0

100

200

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-12

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Ju

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Oc

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-13

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-14

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Jan

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Ap

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Oc

t-15

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Ap

r-16

Ju

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Oc

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Jan

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Ap

r-17

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l-17

Oc

t-17

Jan

-18

Ap

r-18

Ju

l-18

Oc

t-18

DUC Bakken Eagle Ford Haynesville Marcellus Niobrara Permian Utica

# of Abnormal 428 430 74 618 408 420 165

Begin to Complete Jul-17 Jul-17 Jul-17 Jul-17 Jul-17 Jul-16 Jul-17

Duration (Months) 12 12 24 24 12 12 24

7 September 2016

Oilfield Services & Equipment 17

Companies Mentioned (Price as of 02-Sep-2016) Fairmount Santrol Holdings, Inc. (FMSA.K, $7.84, NEUTRAL[V], TP $7.0) Halliburton (HAL.N, $43.32) Hi-Crush Partners, LP (HCLP.N, $15.03, OUTPERFORM[V], TP $17.0) Schlumberger (SLB.N, $78.55) U.S. Silica (SLCA.N, $40.94, OUTPERFORM[V], TP $49.0) Union Pacific (UNP.N, $95.28)

Disclosure Appendix

Important Global Disclosures James Wicklund and Jacob Lundberg each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.

3-Year Price and Rating History for Halliburton (HAL.N)

HAL.N Closing Price Target Price

Date (US$) (US$) Rating

04-Sep-13 49.08 58.00 O

22-Oct-13 51.78 63.00

11-Nov-13 55.30 70.00

21-Apr-14 62.92 78.00

23-Jun-14 70.37 79.00

21-Jul-14 71.00 95.00

20-Oct-14 52.92 79.00

10-Nov-14 53.63 70.00

13-Nov-14 53.79 R

02-May-16 42.05 46.00 O

01-Jun-16 42.15 49.00

* Asterisk signifies initiation or assumption of coverage.

O U T PERFO RM

REST RICT ED

3-Year Price and Rating History for Hi-Crush Partners, LP (HCLP.N)

HCLP.N Closing Price Target Price

Date (US$) (US$) Rating

13-Nov-13 30.70 33.00 O

18-Feb-14 38.94 43.00

08-Apr-14 40.33 R

10-Apr-14 38.25 43.00 O

16-May-14 44.96 46.00

08-Jul-14 60.30 65.00

22-Aug-14 61.73 80.00

10-Nov-14 44.03 60.00

08-May-15 31.37 35.00 N

06-Aug-15 17.23 19.00

04-Sep-15 14.44 17.50

27-Oct-15 5.16 4.50

21-Dec-15 5.44 6.00

28-Apr-16 8.14 R

29-Apr-16 7.00 6.00 N

05-May-16 6.51 7.00

01-Jun-16 9.00 12.00 O

14-Jun-16 11.93 R

23-Jun-16 12.16 12.00 O

02-Aug-16 11.34 16.00

10-Aug-16 12.87 R

11-Aug-16 12.87 16.00 O

* Asterisk signifies initiation or assumption of coverage.

O U T PERFO RM

REST RICT ED

N EU T RA L

7 September 2016

Oilfield Services & Equipment 18

3-Year Price and Rating History for Schlumberger (SLB.N)

SLB.N Closing Price Target Price

Date (US$) (US$) Rating

21-Oct-13 93.48 105.00 N

17-Jan-14 90.21 108.00 O

17-Apr-14 99.91 120.00

27-Jun-14 117.80 137.00

21-Jul-14 113.04 142.00

20-Oct-14 94.60 135.00

10-Nov-14 98.29 141.00

03-Dec-14 86.76 100.00

07-Jan-15 81.71 89.00

16-Jan-15 81.33 86.00

17-Jul-15 83.71 89.00

26-Aug-15 70.09 R

04-Apr-16 72.64 80.00 O

01-Jun-16 75.86 87.00

* Asterisk signifies initiation or assumption of coverage.

N EU T RA L

O U T PERFO RM

REST RICT ED

3-Year Price and Rating History for U.S. Silica (SLCA.N)

SLCA.N Closing Price Target Price

Date (US$) (US$) Rating

21-Dec-15 18.20 25.00 O *

24-Feb-16 16.23 22.00

27-Apr-16 26.59 29.00

01-Jun-16 29.02 32.00

20-Jul-16 36.54 40.00

03-Aug-16 36.99 42.00

* Asterisk signifies initiation or assumption of coverage.

O U T PERFO RM

The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities

As of December 10, 2012 Analysts’ stock rating are defined as follows: Outperform (O) : The stock’s total return is expected to outperform the relevant benchmark* over the next 12 months. Neutral (N) : The stock’s total return is expected to be in line with the relevant benchmark* over the next 12 months. Underperform (U) : The stock’s total return is expected to underperform the relevant benchmark* over the next 12 months. *Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractiv e, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As of 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin Ame rican and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiv eness of a stock’s total return potential with in an analyst’s coverage universe. For Australian and New Zealand stocks, the expected total return (ETR) calculation includes 1 2-month rolling dividend yield. An Outperform rating is assigned where an ETR is greater than or equal to 7.5%; Underperform whe re an ETR less than or equal to 5%. A Neutral may be assigned where the ETR is between -5% and 15%. The overlapping rating range allows analysts to assign a rating that puts ETR in the context of associated risks. Prior to 18 May 2015, ETR ranges for Outperform and Underperform ratings did not overlap with Neutral thresholds between 15% and 7.5%, which was in operation from 7 Ju ly 2011. Restricted (R) : In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances. Not Rated (NR) : Credit Suisse Equity Research does not have an investment rating or view on the stock or any other securities related to the company at this time. Not Covered (NC) : Credit Suisse Equity Research does not provide ongoing coverage of the company or offer an investment rating or investment view on the equity security of the company or related products.

7 September 2016

Oilfield Services & Equipment 19

Volatility Indicator [V] : A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.

Analysts’ sector weightings are distinct from analysts’ stock ratings and are based on the analyst’s expectations for the fundamentals and/or valuation of the sector* relative to the group’s historic fundamentals and/or valuation: Overweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is favorable over the next 12 months. Market Weight : The analyst’s expectation for the sector’s fundamentals and/or valuation is neutral over the next 12 months. Underweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is cautious over the next 12 months. *An analyst’s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors.

Credit Suisse's distribution of stock ratings (and banking clients) is:

Global Ratings Distribution

Rating Versus universe (%) Of which banking clients (%) Outperform/Buy* 55% (52% banking clients) Neutral/Hold* 28% (25% banking clients) Underperform/Sell* 17% (53% banking clients) Restricted 0% *For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, an d Underperform most closely correspond to Buy, Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor's decision to buy or sell a security should be based on investment objectives, current holdin gs, and other individual factors.

Credit Suisse’s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or the market that may have a material impact on the research views or opinions stated herein. Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Fairmount Santrol Holdings, Inc. (FMSA.K)

Method: Our 12-month target price for FMSA equates to 10.4x our 2018 EBITDA estimate of $237M. FMSA's historical median multiple is 10.4x, which we use based on our view that 2018 will be a mid-cycle year (keeping in mind that OFS stocks trade at peak multiples on trough earnings and vice versa). Using our WACC of 9.6% and discounting to 12-months from today gives us a target price of $7. We assign 50% weight to this valuation methodology.We also run a DCF valuation. Based on the previously mentioned EBITDA, WACC and our published working capital and capex assumptions, we also arrive at a $7 target price. We weight the two valuation methodologies equally to arrive at our $7 target price. Our Netural rating is based on our positive view of FMSA's opeartions and market exposure and negatvie view the company's balance sheet.

Risk: Risks to our $7 target price and Neutral rating include: (1) if the current trend of increasing proppant use per lateral foot were to halt or reverse, (2) if FMSA's customer base were to aggressively build out its own logistics infrastructure, and (3) if customers continue using lower-quality sand in favor of Northern White frac sand or resin coated proppant. Investment risks for FMSA include the following. Of FMSA's shares, 37.17% are owned by American Securities, a private equity firm; American Securities holds two of ten board seats. FMSA operations are subject to the cyclicality of the end markets that it services. FMSA is significantly exposed to the oil and gas industry and thus particularly exposed to the cyclicality of that industry. FMSA's top ten customers accounted for 43% of its 2015 revenues. The company is subject to extensive environmental, health, and safety regulations that carry significant compliance costs. Inhalation of respirable crystalline silica is associated with the lung disease silicosis; related health issues and litigation could have an adverse effect on the business.

Target Price and Rating Valuation Methodology and Risks: (12 months) for Hi-Crush Partners, LP (HCLP.N)

Method: Our $17 price target is based on a 9.8x our 2018 EBITDA estimate of $146M. Because HCLP currently pays no distrubition, we use a blend of SLCA's and FMSA's mid-cycle multiples on mid-cycle EBITDA. Our Outperform rating is based on HCLP's low cost structure and secular growth trends in the proppant space.

Risk: Risks to our $17 target price and Outperform rating for HCLP are a decline in the demand for frac sand as the rig count falls, increased supply of frac sand may negatively impact spot market pricing, the general partner's ability to develop additional mines may impact the partnership's growth, frac sand price volatility, increased regulation and changes to the tax status of MLPs.

Target Price and Rating Valuation Methodology and Risks: (12 months) for U.S. Silica (SLCA.N)

Method: Our $49 target price for SLCA is derived from our DCF anaysis which employs a 9.2% WACC and a 1.0% terminal growth rate. Our Outperform rating is based on upside to our price target and our relatively positive view of the frac sand market.

7 September 2016

Oilfield Services & Equipment 20

Risk: Risks to our $49 price target and Outperform rating include: (1) if SLCA's customer base were to aggressively build out their own logistics infrastructure, and (2) if the current trend of increasing proppant use per lateral foot were to halt or reverse. Investment risks for SLCA include the following. SLCA operations are subject to the cyclicality of the end markets that it services. SLCA is significantly exposed to the oil and gas industry and thus particularly exposed to the cyclicality of that industry. Frac sand could fall out of favor as a proppant in the hydraulic fracturing process in favor of alternatives such as ceramic proppant. SLCA's top ten customers accounted for 52% of its 2013 revenues. The company is subject to extensive environmental, health, and safety regulations that carry significant compliance costs. Inhalation of respirable crystalline silica is associated with the lung disease silicosis; related health issues and litigation could have an adverse effect on the business. During the shale revolution, SLCA has derived a significant portion of its profits from the delivery of sand to the wellsite. SLCA's customers are increasingly building out their own logistics infrastructure (unit cars and transloads), eating into SLCA's historical margin. To the degree this trend continues, SLCA may be unable to show the same level of profitability in the future as over the past few years prior to the current downcycle.

Please refer to the firm's disclosure website at https://rave.credit-suisse.com/disclosures for the definitions of abbreviations typically used in the target price method and risk sections.

See the Companies Mentioned section for full company names The subject company (HCLP.N, SLCA.N, FMSA.K, HAL.N, SLB.N) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse. Credit Suisse provided investment banking services to the subject company (HCLP.N, FMSA.K, HAL.N, SLB.N) within the past 12 months. Credit Suisse has managed or co-managed a public offering of securities for the subject company (HCLP.N, HAL.N) within the past 12 months. Credit Suisse has received investment banking related compensation from the subject company (HCLP.N, FMSA.K, HAL.N, SLB.N) within the past 12 months Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (HCLP.N, FMSA.K, HAL.N, SLB.N) within the next 3 months. As of the date of this report, Credit Suisse makes a market in the following subject companies (SLCA.N, HAL.N, SLB.N). As of the end of the preceding month, Credit Suisse beneficially own 1% or more of a class of common equity securities of (HCLP.N). Credit Suisse beneficially holds >0.5% long position of the total issued share capital of the subject company (HCLP.N). Credit Suisse has a material conflict of interest with the subject company (SLB.N) . Credit Suisse is acting as financial advisor to Cameron International (CAM) on its announced acquisition by Schlumberger (SLB).

For a history of recommendations for the subject company(ies) featured in this report, disseminated within the past 12 months, please refer to https://rave.credit-suisse.com/disclosures/view/report?i=244921&v=1nk85eczpy8arh43mm00xm4ws .

Important Regional Disclosures Singapore recipients should contact Credit Suisse AG, Singapore Branch for any matters arising from this research report. The analyst(s) involved in the preparation of this report may participate in events hosted by the subject company, including site visits. Credit Suisse does not accept or permit analysts to accept payment or reimbursement for travel expenses associated with these events. Restrictions on certain Canadian securities are indicated by the following abbreviations: NVS--Non-Voting shares; RVS--Restricted Voting Shares; SVS--Subordinate Voting Shares. Individuals receiving this report from a Canadian investment dealer that is not affiliated with Credit Suisse should be advised that this report may not contain regulatory disclosures the non-affiliated Canadian investment dealer would be required to make if this were its own report. For Credit Suisse Securities (Canada), Inc.'s policies and procedures regarding the dissemination of equity research, please visit https://www.credit-suisse.com/sites/disclaimers-ib/en/canada-research-policy.html. Credit Suisse has acted as lead manager or syndicate member in a public offering of securities for the subject company (HCLP.N, HAL.N) within the past 3 years. Principal is not guaranteed in the case of equities because equity prices are variable. Commission is the commission rate or the amount agreed with a customer when setting up an account or at any time after that. This research report is authored by: Credit Suisse Securities (USA) LLC ........................ James Wicklund ; Jacob Lundberg ; Charles Foote ; John Edwards, CFA ; Bhavesh Lodaya

For Credit Suisse disclosure information on other companies mentioned in this report, please visit the website at https://rave.credit-suisse.com/disclosures or call +1 (877) 291-2683.

7 September 2016

Oilfield Services & Equipment 21

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Investment principal on bonds can be eroded depending on sale price or market price. In addition, there are bonds on which investment principal can be eroded due to changes in redemption amounts. Care is required when investing in such instruments. When you purchase non-listed Japanese fixed income securities (Japanese government bonds, Japanese municipal bonds, Japanese government guaranteed bonds, Japanese corporate bonds) from CS as a seller, you will be requested to pay the purchase price only.