Proppant Market Overview ERIK NYSTROM VICE PRESIDENT, STRATEGIC MARKETING

Transcription

1 Proppant Market Overview ERIK NYSTROM VICE PRESIDENT, STRATEGIC MARKETING

2 WTI forecasts indicate that pricing will remain flat to down WTI Forwards and Projections $120 Actuals Forwards WTI average Estimates 2018 E 2019 E $100 EIA $66 $62 $80 $60 $40 Deflation and currency deleveraging causing a false start OPEC deal OPEC announce leveraged roll-off of cuts Consensus forecast range Credit Suisse $66 $65 JP Morgan $62 $58 Simmons PJC $68 $65 Current WTI estimates are in a tight band for 2019 between $58 and $65, lower than current traded prices. $20 $- Lifting Iran Sanctions Failed OPEC deal This is due to sentiment that demand growth may not be as robust as forecasted as well as factoring in the leveraged rolloffs of OPEC production cuts during the next year. 10/1/ Source: FactSet, Market Watch, CNBC

3 Capacity of drilling rigs has outpaced completion crews 8,031 Total DUC s across all Shale Plays 48.3 Million tons of Potential Demand Rig and Completion Crew Capacity 1,400 1,300 1,200 1,100 1, Rig capacity Completion Crew Capacity 6 Months of Backlogged Completions Efficiency calculated using demonstrated capabilities of 1.3 wells per month per rig and 3.1 completions per month per crew 400 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 An increase of DUCs is attributed to the industry s ability to drill much faster than to complete and indicates the decoupling seen in oil and gas between rigs and production 10/1/ Source: Internal Estimates, Energent Group, EIA, Baker Hughes

4 Active frac crews by play weighted toward the Permian Bakken 38 Rockies 26 Marcellus Active Frac Crews operating in the US Permian 164 Mid-Con 43 Haynesville 34 14% YTD in 2018 Eagle Ford 53 10/1/ Source: Internal Estimates; current as of April 2018

5 Growth in frac crews expected to pause until late 2019 Active Crew Counts & Projections Crude oil takeaway capacity constraints leading to a pause in growth in the Permian until Q Haynesville Shale Play Tons/mo Per Crew Bakken Rockies Mid Con Marcellus Eagle Ford Permian 18,000 Marcellus 20,000 Eagle Ford 30,000 MidCon 15,000 Rockies 26, Jun-16 Dec-16 Jun-17 Dec-17 Jun-18 Dec-18 Jun-19 Dec-19 Permian Bakken 18,000 Haynesville 15,000 Permian mid-stream constraints are leading to an oversupply of frac crews capping demand at current levels until expansion projects can be completed in late /1/ Source: Internal Estimates

6 Active frac crews declining across four major shale plays Active frac crews by play in Actuals Forecast Permian Play Jan 2018 June 2018 Dec 2018 June to Dec Δ Permian (8%) Eagle Ford % Marcellus (23%) 120 MidCon (22%) 100 Rockies (12%) Bakken % 80 Haynesville % Total US (5%) 60 Eagle Ford Bakken Marcellus Mid Con Haynesville Rockies Crew counts across a number of major shale plays are in decline due to stressed pipeline infrastructure and cash flow conscious E&Ps. 10/1/ Source: Internal Estimates

7 Short term outlook indicates ~105 million tons in 2019 Proppant Consumption Forecast (millions of tons) Shale Play Permian Eagle Ford Marcellus MidCon Rockies Bakken Haynesville Others Canada Total Range Canada Others (US) Haynesville Bakken Rockies MidCon Marcellus Eagle Ford Permian Pipeline constraints in the Permian will likely lead to growth in the Eagle Ford while other plays to remain near 2018 levels 10/1/ Source: Internal Estimates, Energent Group

8 Millions of Tons Proliferation of in-basin tonnage causing oversupply Capacity buildout timeline Permian Demand MidCon Eagle Ford Permian Brady Northern White Supply Demand Eagle Ford Supply Demand 0 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q MidCon Rate of capacity additions from in-basin suppliers is outpacing market growth. In 2019, the Permian, Eagle Ford and MidCon will contain more supply then forecasted demand Supply Demand 10/1/ Source: Internal Estimates, Company specific websites

9 Millions of Tons WTX capacity hitting its stride, displacing northern white Capacity buildout timeline Worst case scenario displacement from the Permian Basin around 25 million tons *Assumes 100mesh becomes 75% of total demand Total Permian 2019 Demand Permian Mesh Demand Aug-17 Oct-17 Dec-17 Feb-18 Apr-18 Jun-18 Aug-18 Oct-18 Dec-1 Early producers are had significant quality and delivery issues but are now hitting their stride. Coupled with slower demand due to infrastructure constraints these factors are placing significant stress on northern white. 10/1/ Source: Internal Estimates, Infill Thinking

10 Millions of Tons Technical need for northern white remains Reported Pressures of Permian Basin Wells 2.5 6% of Proppant 69% of Proppant 23% of Proppant 3% of Proppant Resin Northern White 40/70 & 100 Mesh West Texas 100 Mesh West Texas 40/ *Completions January 2016 through December 2017 K Psi Midland Delaware A technical need will remain for northern white 40/70 and 100 Mesh giving an advantage to companies with a full suite of product offerings 10/1/ Source: Energent Group

11 73.1 million tons of in-basin capacity coming online Company Play Tons Operational Aequor Permian 3.0 Q Alpine Permian 3.0 Q Black Mountain Permian 5.0 Q High Roller Permian 3.5 Q Preferred Permian 3.3 Q VIsta Permian 3.0 Q Total Greenfield Capacity 20.8 million tons Company Play Tons Operational Atlas Permian 3.0 Q Black Mountain Permian 6.0 Q Emerge (Superior) Eagle Ford 2.4 Q South Texas Frac Eagle Ford 1.0 Q JW Sands Eagle Ford 1.5 Q Total Greenfield Capacity 13.9 million tons Company Play Tons Operational Badger Permian 3.0 Q Covia Permian 3.0 Q Covia Permian 3.0 Q Capital Permian 2.8 Q US Silica Permian 2.6 Q West TX Sand Co Permian 3.0 Q Wisconsin Proppants Permian 3.0 Q Monarch Eagle Ford 4.0 Q Total Greenfield Capacity 24.4 million tons Company Play Tons Operational Atlas Permian 3.0 Q Ultra Fine Silica Eagle Ford 4.0 Q Covia MidCon 4.0 Q Preferred MidCon 3.0 Q Total Greenfield Capacity 14.0 million tons Softening demand in Q3 and Q4 against multiple new capacity additions indicate pricing will be challenged on multiple fronts 10/1/ Source: Internal Estimates, Company specific websites

12 Millions of Tons Colorado dune sands unfit for usage in the DJ Reported Pressures of Denver-Julesburg (DJ) Basin Wells % of Proppant 5% of Proppant Resin Northern White 40/70 & 100 Mesh Local 100 Mesh Local 40/ *Completions January 2016 through December 2017 K Psi DJ Basin Colorado dune sands are not recommended for usage in hydraulic fracturing due to very low silica content in the sands which provide low crush resistance and high acid solubility 10/1/ Source: Internal Estimates, Energent Group

13 Millions of Tons Requirements in the Eagle Ford are higher than most plays Reported Pressure of Eagle Ford Wells Million Tons 24% of Proppant 15 Million Tons 68% of Proppant 2 Million Tons 8% of Proppant Resin Northern White 40/70 & 100 Mesh Local 100 Mesh Local 40/ *Completions January 2016 through December 2017 K Psi Eagle Ford wells begin at 7k with any density. Most operators in the basin range between 7k and 10k for most of their work 10/1/ Source: Internal Estimates, Energent Group

14 MidCon local sands are viable for much of the demand profile Proppant pumped by reported well pressure 300, Million Tons 37% of Proppant 6.8 Million Tons 83% of Proppant 8.3 Million Tons 99% of Proppant 8.4 Million Tons 100% of Proppant 250, , , ,000 Resin Northern White 40/70 & 100 Mesh 50,000 In Basin 100 Mesh In Basin 40/70 STACK SCOOP *Completions January 2016 through December 2017 *Assumes a 0.65 pressure gradient K Psi 10/1/

15 Direct sourcing is awaiting a full last mile solution Top 100 proppant consuming E&Ps in million tons + 1 million tons + Continental XTO Extraction 500,000 tons + Devon 90% Of proppant consumed by the top 100 E&Ps EOG Pioneer Chesapeake Marathon Anadarko Concho Sanchez Oxy Newfield Conoco Encana Encana SWN CNX 100,000 tons + Hess Vertically integrated (own their own sand mine) Actively self-sourcing, or seeking RFPs Not currently self-sourcing Ascent 48% Of total 2017 demand represented by E&Ps either actively self sourcing or requesting RFPs Full adoption of E&P self sourcing if dependent on effective last mile solutions 10/1/ Source: Internal Estimates, Energent Group

16 Final thoughts on the market It s all about frac crews Rig Count decoupled from frac sand demand Market projected to be 100 million tons this year Nearly doubling the boom of 55 million tons back in 2014 Headwinds are forming due to lack of pipeline infrastructure, capping market growth Well designs still moving toward more intense finer grade designs across the industry The desire of some E&Ps to directly source proppant is changing in many cases how it is sold and delivered to the well site True last mile solutions will be integral to success with this emerging customer requirement Growth of greenfield in-basin capacity Numerous challenges both structural and technical exist and will need to be solved to be successful Labor and trucking shortages will provide challenges specifically in the Permian Basin 10/1/ Source: Covia

17 Proppant Comparison FIT FOR PURPOSE VS. NORTHERN WHITE

18 Findings indicate advantages to using Northern White material Proppant quality matters for production of hydrocarbons If you are holding wells for production beyond initial IP, quality northern white proppants should be considered over other Tier II proppants Conductivity testing shows a significant degradation in performance of West Texas100 mesh material Degradation is due to fines generation and migration Northern White Sand generated 11% fewer fines than regional sand Crushed sand = increased turbulent flow due to increased angularity of the crushed sand, degradation of proppant pack, insufficient flow path to reservoir Northern White 40/70 testing indicated increased performance of wells. Due to increased flow paths from higher roundness and sphericity allowing for better production Sub-angular substrate allows for inferior long-term production. A 2x increase in turbidity between Northern White and West Texas material equates to performance differences as well as operational challenges from a dirtier material Real world performance indicates 16% greater production from Northern White compared to Texas Gold material due to turbidity and other performance issues Up-front Savings from in-basin sands are evaporated within 6 months of production at $60/bbl realized After 24 months, Northern White wells generated $1 million more in oil production than comparable wells completed with Texas Gold material Conditions in the Eagle Ford are more harsh than the technical capabilities of either Texas Gold or in-basin sands 10/1/

19 Conductivity, md-ft Percent Retained 100 Mesh testing indicates a distinct performance advantage 100 Mesh 6k Continuous Hold Conductivity Testing x Greater Northern White conductivity after two weeks of testing Particle size distribution before and after testing 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Northern White West Texas pan 15% fines generation after just two weeks. What happens after two years? West Texas material after 2 Weeks: A 15% fines generation increase caused 57% decline in conductivity performance Day Sand Type Crush Strength (psi) White Sand 11-12k Texas Gold 7-8k WTX Regional 9-10k 10/1/ Source: Covia

20 Conductivity, md-ft Percent Retained 100 Mesh testing indicates a distinct performance advantage Normalized 6k hold conductivity results 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 60% Reduction in initial conductivity seen in West Texas Sands vs. 16% Reduction in initial conductivity seen in Norther White Sands Day Particle size distribution before and after testing 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Northern White West Texas pan 15% fines generation after just two weeks. What happens after two years? West Texas material after 2 Weeks: A 15% fines generation increase caused 57% decline in conductivity performance. Sand Type Crush Strength (psi) White Sand 11-12k Texas Gold 7-8k WTX Regional 9-10k 10/1/ Source: Covia

21 Quality effects productivity, quality sand will produce longer Northern White Before Testing Northern White After Testing 6k psi for two weeks WTX Field Sample Before Testing WTX Field Sample After Testing 6k psi for two weeks 100 mesh Fines generation on from the West Texas sand sample chokes out production after an extended period under pressure due to inferior strength 10/1/ Source: Covia

22 Conductivity, md-ft Percent Retained 40/70 shows consistent, pronounced conductivity differences 40/70 Mesh 6k Continuous Hold Conductivity Testing Northern White West Texas 67% average performance difference of northern white over West Texas Day Particle size distribution before and after testing 40% 35% 30% 25% 20% 15% 10% 5% 0% -5% Northern White West Texas Pan Similar particle size distributions between sand types before and after testing still yielded an advantage to Northern White due to more ideal roundness and sphericity Sand Type Sphericity Roundness White Sand Texas Gold >0.6 >0.6 WTX Regional >0.6 >0.6 10/1/ Source: Covia

23 Conductivity, md-ft Percent Retained 40/70 shows consistent, pronounced conductivity differences 40/70 Mesh 6k Continuous Hold Conductivity Testing 100% 95% 90% 85% 80% 75% 70% 65% 60% 55% 50% 31% Reduction in initial conductivity seen in West Texas Sands vs. 14% Reduction in initial conductivity seen in Norther White Sands Day Particle size distribution before and after testing 40% 35% 30% 25% 20% 15% 10% 5% 0% -5% Northern White West Texas Pan Similar particle size distributions between sand types before and after testing still yielded an advantage to Northern White due to more ideal roundness and sphericity Sand Type Sphericity Roundness White Sand Texas Gold >0.6 >0.6 WTX Regional >0.6 >0.6 10/1/ Source: Covia

24 Performance differences also stem from turbidity of product Sand Type Turbidity (FTU) Acid Solubility White Sand <50 <0.6% Texas Gold <75 <2.0% WTX Regional 100 <3.0% Impurities dissolve in acid meaning that to place 7,500 tons of proppant, 7,735 tons must be pumped or an additional 235 tons of material must be purchased. Northern White Silt and clay stuck to sand grains Northern White Range West Texas Range West Texas Northern White sands are generally cleaner with less silt or clay material attached to each grain. These impurities cause break free down hole where the clays swell and choke off production. 10/1/ Source: Covia

25 Barrels per lateral foot Production Barrels per lateral foot Production Real world performance impacted by proppant quality Northern white wells peak longer providing uplift Northern White Outperform Underperform Majority of wells are in the outperform range Brown sand wells peak at the same level but fall off quicker Texas Gold Outperform Underperform Most wells are in the underperform range Significantly more interventions required across multiple wells Mixed Outperform Underperform Virtually all wells are in the underperform range Using Texas Gold as a proxy for in-basin sands, observations in well performance indicate wells completed with higher quality proppants generally outperform their peers due to the proppant pack's ability to keep fractures open while maintaining conductivity. 10/1/ Source: Internal Estimates, Energent Group

26 Barrels per lateral foot Production Barrels per lateral foot Production Well averages showcase performance differences IP is an ineffective comparison as wells peak at similar levels Characteristic effects seen in well cohort averages Northern White Texas Gold Mixed 16% Northern white production advantage over brown sands 16% 21% - - When performance is averaged, characteristic decline curves indicative of the quality of proppant used become clear. Northern white wells peak at the same level but maintain higher production longer due to better sand performance 10/1/ Source: Internal Estimates, Energent Group

27 Up-front savings of cheaper proppant quickly wiped out Northern White After 6k Testing Production Month Northern White Texas Brown Mixed Month 1 $320,716 $173,595 $357,064 Up-front savings lost Month 3 $1,403,706 $1,079,851 $1,407,310 Month 6 $2,898,257 $2,219,514 $2,423,634 Brown Sand Sample After 6k Testing Month 12 $4,674,795 $3,829,757 $3,524,935 Month 18 $6,046,384 $5,017,743 $4,375,911 $1M difference in production Month 24 $7,051,444 $6,012,815 $5,027,012 Assumes normalized production from a 7,500 foot well and $60 WTI realized Assuming a savings of $50/ton on 7,500 tons, the up-front advantage from cheaper locally available sands wiped out within three months of production 10/1/ Source: Internal Estimates