The Flotek Store

The Time Is N W 1. Favorable commodity price environment

2. Over-supply of hydraulic horsepower

3. Two-year direct marketing and educational process

4. Growing frustration of E&P companies regarding technology transfer

5. Differentiation with proprietary CnF® completion chemistries

6. Big data validation with FracMax®

The Flotek Store

IS IN YOUR WELL?

Reaching the Tipping Point. . .

Operators are no longer asked “why” they use CnF® completion chemistries; but those who aren’t

using CnF® are being asked “why not”.

Panel Discussion

Panel Discussion

Yucel Akkutlu, Ph.D. George & Joan Voneiff Career Development Professor & William Keeler

Fellow, Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas

John Ely Founder & Chief Executive Officer, Ely & Associates, Houston, Texas

Daniel Hill, Ph.D.

Noble Chair, Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas

Lanny Schoeling, Ph.D. Vice President of Engineering & Technical Development, Kinder Morgan CO2

Company, L.P., Houston, Texas

Brady Webb Chief Engineer, Velvet Energy, Calgary. Alberta, Canada

Gary Womack

Vice President – Operations, Tall City Exploration, LLC, Midland, Texas

96

Texas A&M University

Daniel Hill, Ph.D. Harold Vance Department of Petroleum Engineering

Harold Vance Department of Petroleum Engineering

TAMU Petroleum Engineering Research Funding

Source of research contract awards for 2013-2014

Our Research in Unconventional Resources

– Hydraulic Fracturing

• Rock/fluid interactions

• Fracture conductivity

• Fracture Mechanics

– Resource Assessment

• Seismic mapping of “sweet spots”

• Basin depositional analysis

• Fracture diagnostics

Our Research in Unconventional Resources

– Reservoir/Well Performance

• Discrete fracture network modeling

• Rate/pressure transient analysis

• Fast marching methods for history matching

– Resource Assessment

• Seismic mapping of “sweet spots”

• Basin depositional analysis

• Fracture diagnostics

Unconventional (Source Rock) Resources

Drilling and hydraulic fracturing are high-tech state-of-the art

Our understanding of the resource in place is early-stage

Performance of over 600 Bakken wells – Extreme variability

Performance by Operator

What is causing this variability in well performance?

• The well length

• The number of fracture stages

• The type and amount of

fracture fluid

• The type and amount of

proppant

Hydraulic Fracturing Fluid Product Component Information Disclosure

Job Start Date:

4/27/2015

Job End Date:

5/14/2015

State: Texas County: Karnes

API Number:

42-255-34058-00-00

Operator Name:

Marathon Oil

Well Name and Number:

Childrens-Weston Unit 6H

Longitude: -98.02134800

Latitude: 28.75423100 Datum: NAD27

Federal/Tribal Well:

NO

True Vertical Depth:

12,020

Total Base Water Volume (gal):

4,776,797

Total Base Non Water Volume:

0

Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number

(CAS #)

Maximum Ingredient

Concentration in Additive

(% by mass)**

Maximum Ingredient

Concentration in HF Fluid

(% by mass)**

Comments

Ingredients shown above are subject to 29 CFR 1910.1200(i) and appear on Material Safety Data Sheets (MSDS). Ingredients shown below are Non-MSDS.

A201, A264, B451, Schlumberger Inhibitor Aid , F112, H036, H075, Corrosion Inhibitor, J218, J353L, J481, Demulsifier, Surfactant J579, J580, J604, , Acid, Breaker, L058, L065, L071, Stabilizing Agent, U028, U042, S012- Additive, Gelling 3050, B352-3050 Agent, Crosslinker,

Iron Control Ag Water (Including Mix Water Supplied by Client)*

NA 86.96093

Quartz, Crystalline silica 14808-60-7 91.36054 11.91256

Guar gum 9000-30-0 2.02522 0.26407

Hydrochloric acid 7647-01-0 1.22029 0.15911

Sodium hydroxide (impurity) 1310-73-2 0.83942 0.10945

Ethylene Glycol 107-21-1 0.77109 0.10054

Polylactide resin 9051-89-2 0.73621 0.09599

Sodium bromate 7789-38-0 0.62200 0.08110

2-hydroxy-N,N,N- trimethylethanaminium chloride

67-48-1 0.54010 0.07042

Sodium thiosulphate 7772-98-7 0.46773 0.06099

Phenolic resin 9003-35-4 0.44626 0.05819

Propan-2-ol 67-63-0 0.16791 0.02189

Trisodium nitrilotriacetate (impurity)

5064-31-3 0.00020

0.00003

1-Octadecene (C18) 112-88-9 0.00011

0.00001

Oleic acid 112-80-1 0.00006

0.00001

Potassium oleate 143-18-0 0.00007

0.00001

1,4-Dioxane 123-91-1 Acetic acid, potassium salt 127-08-2 0.000

01 C12 fatty alcohol 112-53-8 0.000

03 C13 alcohol ethoxylate 9043-30-5 0.000

01 Oxirane 75-21-8 Propylene oxide 75-56-9 Acetic acid 64-19-7 Formaldehyde 50-00-0 0.000

01 2-bromo-2-nitropropane-1,3-diol 52-51-7

Dionix Bosque Systems, LLC Biocide ClO2 10049-04-4 0.000

00

What’s next for unconventional gas and oil development in the U.S. and

the rest of the world?

Region OGIP (P50), Tcf TRR (P50), Tcf

CBM Tight gas Shale gas Total CBM Tight gas Shale gas Total

AAO 1,348 6,253 2,690 10,291 483 3,783 676 4,942

NAM 1,629 10,784 5,905 18,318 584 6,525 1,505 8,614

CIS 859 28,604 15,880 45,343 308 17,307 3,924 21,539

LAM 13 3,366 3,742 7,122 5 2,037 964 3,006

MET 9 15,447 15,416 30,872 3 9,346 4000 13,349

EUP 176 3,525 2,194 5,895 63 2,133 561 2,757

AFR 18 4,000 3,882 7,901 7 2,420 1007 3,434

World 4,052 71,981 49,709 125,742 1,453 43,551 12,637 57,641

Texas A&M Study Results From Zhenzhen Dong Dissertation – August 2012

• We are not going to run out of oil and gas

• What will limit

unconventional gas and oil development?

• Low prices

Source: ExxonMobil The Outlook For Energy – A View To 2040

Global Energy Mix To 2040

-Nuclear

-Hydro

-Coal

-Biomass

-Gas

-Oil

1800 1850 1900 1950 2000 2040

Qua

drillio

n B

TU

s

Gas & Oil Still ‘Kings’ In 2040 !

Solar + Wind + Biofuel: ~5% Of The Global Energy Mix In 2040

Haldorsen

>6

0%

Questions?

Thank you Dr. Dan Hill

Professor, Department Head –

Petroleum Engineering and Noble

Endowed Chair

Texas A&M University

Yucel Akkutlu, Ph.D. Harold Vance Department of Petroleum Engineering

Future IOR Potential for Shale Oil Propped fracture feeding a well

Inorganic water-wet material

Organic oil-wet material

Technical and Operational Challenges: • How to improve the qualities of the hydraulic fracture wall surfaces?

Oil wet organic material

Oil droplet Spreading over the surface

• How to maximize the fracturing fluid (and chemicals

it carries) penetrating into the tight matrix?

M A T R I X

Y Y Y Y Y

Y Y Y

Y Y

Y Y

Y

Stable Molecular Cluster of Citrus Oil Entangled w/ Surfactant

citrus oil molecular cluster

oil

organic wall

Surfactant: dodecylhepta(oxy-ethylene)ether (C12E7) contains one hydrophobic tail of 12 alkyl groups, and one hydrophilic head of 7 ethylene oxide groups and 1 terminal OH group d-limonene (terpene solvent) time=0 time=3 ns time=10 ns

Effective in Removing Oil Films on the Fracture Wall Surfaces

No citrus oil With citrus oil

Viewing Water Phase (blue) during Displacement

• Water can penetrate and displace only the oil residing in largest pore

• Oil inside all nanopores is displaced

• The smaller the pore, the slower it is being displaced

Pores of oil-wet fracture wall surface Pore of water-wet fracture surface

Viewing the Oil Phase (green) and Water Phase (blue) during Displacement

Pores of oil-wet fracture surface Pore of water-wet fracture surface

• Water can only penetrate and displace oil residing in the largest pore

• Oil in smaller pores are immobile.

• Oil inside all of the nanopores is displaced

• The smaller the pore, the slower it is being displaced.

Citrus Oil Effective in Penetrating Shale Matrix

• One droplet is adsorbed by the surface of the rock before entering the pore

• The remaining droplet enters the pore but is adsorbed on the surface inside the pore

• One droplet is adsorbed to the oil cluster before entering the pores

• The other droplet deforms and squeeze through the pore. After that, it adsorbs to the oil phase

Pores of oil-wet fracture surface Pore of water-wet fracture surface

Tall City Exploration, LLC

Gary Womack Vice President - Operations

127

Tall City Exploration, LLC

Flotek Presentation

• Tall City Exploration • Completion Optimization CnF Technology

Tall City Exploration LLC 203 West Wall Street, Suite 600 Midland, TX 79701 (432) 218-7816 tallcityexploration.com

128

Historical Track Record Startup May 2012 - Current July 2015

Management Team Biographies

Extensive Prior Industry Experience

• Worked 15 years with Exxon, 7 years with Titan/Pure Resources/Unocal, 2 years with Celero/Whiting in various exploration, development and senior management positions

• Co-founded Piedra Resources in 2007 with private equity partners. Piedra sold to Berry Petroleum in 2011 for >$120MM

129

Mike Oestmann Chief Executive Officer

Formerly Partner and COO of Vintage and former Chief Technical Officer of Parkman Whaling, LP Previously Managing Senior Vice President and a member of the Board of Directors at Ryder Scott Company Began his career at Exxon for a term of 5 years, where he supervised the Corpus Christi District reservoir team

Joe Magoto President

Previously served as Senior Vice President at Ryder Scott Company, L.P. Began his professional career with Tenneco Oil Company, followed by employment at Pogo Producing Company, North Central Oil

Corporation and Texas General Petroleum Corp.

Ed Gibbon Vice President – Res. Eng.

Spent the first 15 years of his career with Gulf Oil Company and Chevron in the Permian Basin Formed Drillmark Consulting, an Engineering and Wellsite consulting firm in 1997 and merged the firm with EPI Consultants Prior to joining Tall City, had been an independent Project Manager/Operator/Partner in several areas of Texas

Dennis Kruse Vice President - Drilling

After three years as a U.S. Army helicopter pilot, spent 6 years at Exxon and 13 years with Southland Royalty Company Later, served as President of M. L. Cass Company and became an independent oil and gas consultant in 1990 In 2008, H. L. Brown, Operating invited him to become their Geo-science advisor

Darryl James Vice President - Exploration

Spent 10 years as a petroleum engineer with Oxy with focus on Permian Basin Left Oxy as an Engineering Advisor in 2002 to join Chi Energy as Operations Manager where his focus included acquisition and

implementation of drilling and producing projects in Texas and New Mexico

Gary Womack Vice President - Operations

Began her legal career at Cotton, Bledsoe, Tighe & Dawson, P.C., in Midland, Texas practicing in litigation Joined three other attorneys and opened a new law firm, where she where she focused on both large oil and gas operators Senior Attorney at Davis, Gerald and Cremer, P.C. and serves as General Counsel to the Permian Basin Petroleum Assoc.

Angela Staples Vice President – Land and Legal

Spent over ten years in investment banking with Greenhill & Co. and Merrill Lynch advising energy clients regarding mergers & acquisitions and debt & equity underwriting transactions

Began career as reservoir and petroleum engineer with BP

Michael Marziani Chief Financial Officer

Yrs. Exp.

16

32

42

47

33

44

24

12

Name/Title Professional Biography

• Founded and funded by Denham Capital in May 2012

• Initial Equity commitment of $200 MM; expanded to $300 MM

• Senior Debt Facility of $500 MM in place with current RBL borrowing base of $115 MM

• Initial Business Plan:

• Acquire 25,000 acre position in Midland Basin

• Drill 33 Vertical wells / 3 Horizontal on 10,000 acre Core

• Shifted Development Plan to 100% horizontal Wolfcamp prior to Capital close

• Executed Plan quickly by Opening doors with 5,400 acres already purchased giving

us a running start

TCE 1 -- Initial Business Plan May 2012

Company Formation and Business Plan

TCE 1 -- Executed Actual Business Plan To-Date -- July 2015

• Acquired 91,000 net acres in Wolfcamp Horizontal Play

• North Position: 77,000 net acres in Howard and Borden Counties, TX

• South Position: 14,000 net acres in Reagan and Crockett Counties, TX

• Well Results

• Advanced petro-physical analysis on over 450 wells essential in high-grading acreage

• Drilled 36 horizontal wells – 30 in North Position and 6 in South Position

• All mechanically successful, none junked or abandoned

• Combined D&C cost at or under cumulative AFE

• All have robust economics well above payout, with IRRs ranging from 20 to 50%

• Production Statistics

• 36 PDP wells, with IPs ranging from 500 – 1,200 Bopd

• Current net production of ~4,000 Boepd from only 30 wells in North Position (South position sold in late 2014)

• 3 rigs ran much of 2014, reduced to 1 rig in 2015 to maintain leases

October 2015 Sale $750 MM

South Position 14,000 net acres

North Position 77,000 net acres

TCE Net Production Plot

8,460

3,954

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We

ll C

ou

nt

Bo

ep

d

Gross Boepd

Net Boepd

Well Count

Sold Reagan to AEP Est. Boepd 4,172 with all Wells on - lowered due to 3 Wells shut-in for Fracing offsets

TCE 1 -- Executed Actual Business Plan To-Date -- July 2015

• Acquired 91,000 net acres in Wolfcamp Horizontal Play

• North Position: 77,000 net acres in Howard and Borden Counties, TX

• South Position: 14,000 net acres in Reagan and Crockett Counties, TX

• Well Results

• Advanced petro-physical analysis on over 450 wells essential in high-grading acreage

• Drilled 36 horizontal wells – 30 in North Position and 6 in South Position

• All mechanically successful, none junked or abandoned

• Combined D&C cost at or under cumulative AFE

• All have robust economics well above payout, with IRRs ranging from 20 to 50%

• Production Statistics

• 36 PDP wells, with IPs ranging from 500 – 1,200 Bopd

• Current net production of ~4,000 Boepd from only 30 wells in North Position (South position sold in late 2014)

• 3 rigs ran much of 2014, reduced to 1 rig in 2015 to maintain leases

• Reserves

• Independently estimated by Ryder Scott as of December 31, 2014 (North Position only)

• 3 horizontal benches (reservoirs) de-risked: Lower Spraberry, Wolfcamp A and Wolfcamp B

• 1,825 total locations (549 Proved, 1,276 Probable)

• Capital

• Expended as of April 1, 2015 (final sale effective date): Equity = $238 MM, Debt = $50 MM

October 2015 Sale $750 MM

South Position 14,000 net acres

North Position 77,000 net acres

• Sale of South Position (November 2014)

• $437 MM to American Energy Partners, LP ($377 MM discounting notes to 60%)

• Sale of Miscellaneous North Position Acreage (Spring 2015)

• $5.7 MM to Rock Oil

• Contracted Sale of Consolidated North Position (October 2015)

Sales Proceeds and Return on Capital (ROI)

October 2015 Sale $750 MM

November 2014 Sale to AEP

$437 MM

Midland Basin Horizontal Development Over Time

The geologic story will fully support the development model and will give buyers

confidence in future drill well performance

Horizontal development in the northeastern part of the basin has been pioneered by Element and Tall City

Overview Horizontal Wolfcamp Development Trends/Phases

Phase I – SE

2010-2012

EOG, PXD, EPE, LPI

Garden City (LPI)

University Lands

Phase II – SW

Early 2012-2013

PXD

Giddings Estate

Phase III – NW

Late 2012-2014

PXD, RSP, FANG

Mabee, Parks Bell

Phase IV – NE

2013-Current

TCE, Element, ATHL, EGN, OXY

Hammer, Tubb

Horizontal development was initiated in the southeastern portion of the basin

One driver was that acreage was available in the Irion and Crockett areas, since vertical production was not as prolific in these areas

Pioneer expanded the play to Upton County in the southwest basin with the Giddings wells

From there, the play moved north with numerous operators working in the northwest basin area where Andrews/Martin/Ector/Midland counties come together

With the opening of Howard County in the northeast by Element/TCE, all quadrants of the basin have now proven commercial for horizontal Wolfcamp and Lower Spraberry Shale

Tall City’s Wolfcamp Horz Results compared to Industry

Tall City Howard Wells - 30 day IP vs EUR

0

200

400

600

800

1,000

1,200

1,400

0 200 400 600 800 1,000 1,200 1,400

Oil EUR in mbo

Peak

30

day

Oil

Rat

e in

Bop

d

Tall City Wolfcamp ATall City Wolfcamp BTall City_Spraberry LShaleTall City - AEP Reagan CoAEP - EnduringLaredoDiamondback EnergyRSP PermianEnergenParsleyQEP

Individual Well Rate of Return (IRR) Sensitivity to Oil Price

Selection of Tall City / Vendor Team Use of “Shale Logs” in regional acreage evaluation Microseismic CnF Technology FracMax Validation

Optimizing Completions

• Improve penetration into the formation • Increase contacted and stimulated reservoir volume • Used in primary fracture • Used in remedial treatments • Validation

Nano Surfactant Purpose

Well without

CnF

0

50

100

150

200

250

300

350

Pre vs Post Re-Stim with Nano Surfactant

75 days of production before Re-stim

75 days of Total Production after Re-stim

MAINTAIN HEALTHY ECONOMICS OPTIMIZE AND STREAMLINE

Velvet Energy Ltd.

Brady Webb Chief Engineer

Incorporating Advanced Chemistry to Yield Superior Results

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

Certain information with respect to Velvet Energy Ltd. (“Velvet” or the “Company”) contained herein, including expectations, beliefs, plans, goals, objectives, assumptions, information and statements about future events, conditions, results of operations, performance, Velvet’s planned capital expenditure program and the nature of the expenditures, drilling plans, expected drilling and completion costs, expected average production, the expected splits among crude oil, NGLs and natural gas and forecasted commodity prices and factors affecting natural gas prices, forecasted general and administrative expenses, interest expenses, revenue, operating income, operating netbacks, funds from operations and year-end bank debt, management’s assessment of future potential, including numerous years of drilling inventory and expectations with respect to natural gas demand and supply in North America, contain forward-looking statements. These forward-looking statements are based on assumptions and are subject to numerous risks and uncertainties, certain of which are beyond the Company’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations, imprecision of reserve estimates, environmental risks, competition from other explorers, stock market volatility, and ability to access sufficient capital. We caution that the foregoing list of risks and uncertainties is not exhaustive. Statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on current estimates and assumptions that the reserves and resources can be profitably produced in the future. Readers are cautioned that disclosure of any well test results are not necessarily indicative of long-term performance. Velvets actual results, performance or achievement could differ materially from those expressed or implied by, these forward-looking statements and, accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur. As a result, undue reliance should not be placed on forward-looking statements. In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The forward-looking statements contained herein are made as of the date hereof and the Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly required by applicable securities laws. Certain information set out herein may be considered as “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding Velvet’s reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not be appropriate for other purposes.

WHO ARE WE

• Velvet Energy started in 2011 with Private Equity financing, raising $347mm with the concept of exploiting tight gas opportunities in the Deep Basin of Alberta with Horizontal Drilling.

• 2012 Established Core Area west of Edmonton with property acquisition.

• Currently have amassed over 406 net sections of land in the Deep Basin and identified over 550 net drilling locations.

• To date Velvet has drilled and completed over 95 horizontal wells.

• Current production is approximately 13,500 Boe/d.

PRIMARY FOCUS

Velvet’s Primary Focus horizon is the Lower Cretaceous Gething, Ellerslie and Ostracod Formations • Typical pay interval is 30-60 ft, average porosity is 10

percent, water saturations between 25 to 35 percent and permeability between 0.05 to 0.5 mD.

• Reservoirs are slightly under pressured at about .38 psi/ft (typical reservoir pressure 2900 psi)

• Completions are generally Packer/Port Ball Drop systems with inter port spacing of 280 to 330 ft.

• Average well one month IP’s are 2.4 Mmcf/d with liquids averaging 125 Stb/Mmcf.

643 gross, 406 net sections 503 gross, 331 net locations

COMPLETIONS HISTORY

• Initially Velvet relied on our pump service provider to design, recommend and pump our stimulation jobs.

• In January of 2013 we decided to take control of our stimulation designs • Our first priority was to design a workflow to design, evaluate and quantify our

completions. • We then went out and purchased the tools required to design and evaluate

stimulations

COMPLETIONS WORKFLOW

Formation Evaluation

Determine Reservoir Properties DFIT – Initial Pressure, Closure Pressure,

Zone Stress and Tortuosity Design Stimulation Program - GOHFER

Geochem Testing

Frac Fluid Compatibility with formation fluids

Post Frac Analysis

RTA – Formation Perm & Boundaries 3D simulation – Fracture ½ Length 3D simulation – Drainage Area

Post Frac Review

Compare current completion with database Change Frac Fluid Type Modify Chemical Selection Modify Sand Size 30/50, 20/40, 16/30

INTRODUCTION TO CnF SURFACANT

• After a review of the flow back reports from our first few wells a Consultant in our

completions group recommended using CESI’s CnF surfactant. • Our next several wells were pumped with CnF at between 1-2 gpt and we noted a

significant reduction in time to first HC.

First HC around 4 hours on our first well using CnF. Oil Gas

BACK TO THE LABORATORY TO EXPLAIN RESULTS

• Our preliminary observations were interesting but we didn’t really understand what was happening.

• We initiated a research program to try and better understand the processes involved.

• After several months and about 500 M$ of laboratory testing we came to two conclusions.

1. CnF surfactant improves effective fracture conductivities. 2. CnF enhances near wellbore permeability.

CnF IMPROVES FRACTURE CONDUCTIVITY

In Cuttings/Proppant column drainage tests CnF surfactant demonstrates superior drainage which we believe translates into higher effective fracture conductivities.

This illustration courtesy of CESI Chemicals

CnF IMPROVES FRACTURE CONDUCTIVITY

Effectiveness of 2.0 gpt CnF additives in filtered mixture of 50% formation water and 50 % frac water displaced by centrifuged formation oil from a column packed with 15% 70/140 mesh formation cuttings and 85% 100 mesh Oklahoma sand mixture. Black markers indicate oil breakthrough. (Results courteous of CESI Chemicals)

Note: Rapid breakthrough time

CnF ENHANCES NEAR WELLBORE PERMEABILITY

Corelabs Canada conducted several regained core studies on cores from target horizons.

• In six regained core studies we directly compared frac fluids with and without CnF.

• The results showed that 5 of the 6 samples using CnF had regained perms higher than those measured prior to the introduction of the frac fluid.

• Examination of the results indicated average core water saturations were less than those initially measured.

Introduction of CnF into the pore system reduced the oil/water Inter Facial Tension (IFT) (verified through laboratory measurements). This in turn lowered the capillary pressure which reduced water saturations in the invaded pore space and lead to an improvement in near wellbore permeability.

RESULTS TO DATE

Normalized averaged well results drilled in target horizon post 2013

Operator 1 – (7) Other – (11) Operator 2 – (15) Velvet – (31)

WHERE DO WE GO FROM HERE

Our relationship with CESI Chemicals is excellent and we are now into our third year of collaboration. Here is a short list of some of our current projects and some new ideas • Currently, we are doing a multi well frac fluid study with CESI on our Gething,

Ellerslie/Ostracod play. The study includes:

1. characterization of 4 crude oil types, associated formation waters and drill cuttings to optimize CnF formulation for slick water (completed).

2. a fines flow back evaluation looking at distribution and mineralogy of flowback fines (waiting on results).

3. if we determine a potential clay plugging problem we have lined up CESI to evaluate CESI’s clay stabilization additive to mitigate damage.

• We recently completed a novel dry gas EOR injection scheme with CESI where we injected

dry gas + CnF as a method of Enhanced Oil Recovery. One PV of dry gas with CnF at 2 gpt yielded an incremental 5.1% increase in oil recovery over dry gas only.

• We are in preliminary discussions with CESI to evaluate the potential injecting N2 + CnF into

older wells which we believe over time have built up high water saturations in the sand pack and possibly in the near wellbore. We hypothesize that reintroducing CnF into the sand pack may reduce water saturations and improve productivity.

CONCLUSIONS

• Adoption of a complete Completion Workflow is imperative to improve frac performance.

• Advanced chemistry solutions are reservoir specific. Frac fluid chemistry varies with the type of insitu fluids, their chemical composition and formation rock properties.

• To develop and deploy best in class solutions collaboration of operators, pumping service providers and chemically focused R&D providers like CESI, putting science and engineering first, is required to yield superior results.

Kinder Morgan CO2 Company

Lanny Schoeling, Ph.D. Vice President of Engineering & Technical Development

Kinder Morgan CO2 Asset Map

BRAVO DOME

DOE CANYON

MC ELMO DOME

ST JOHNS

SACROC

KATZ

YATES

GLSAU

CO2 PIPELINE CRUDE PIPELINE CO2 SOURCE FIELD OIL PRODUCTION FIELD

KM is one of the largest oil producers in Texas, producing over 55,000 BOPD. We operate 5 CO2 floods – SACROC, Yates, Goldsmith, Katz, and Tall Cotton

Kelly-Snyder (SACROC) Miscible CO2 Flood

Yates

Immiscible CO2 Flood

Katz Early Stage Miscible CO2 Flood

Goldsmith Landreth San Andres Unit Early Stages of Miscible CO2

Flood Development

Tall Cotton ROZ only Miscible CO2 Flood

Pilot

Kinder Morgan Oil Fields/CO2 Floods

Major Focus is Conformance

CO2 must contact Rock

Possible chemical technologies

needed to improve conformance:

Gel Polymers to plug huge

channels/conduits Foams to plug high permeable

matrix layers Chemical Additives to prevent

formation damage in completions

All of above are a part of Flotek technologies

• Over 35 year Experience in the following EOR Technologies

– Chemical Flooding: Gel Polymers and Surfactants – Early Career – Thermal EOR: Chief Reservoir Eng. For Shell’s IUP for Unconventionals – CO2 Flooding: VP of Engineering and Technology Development at KM

• Field Pilot Leadership Experience

– Surfactant Pilots at Yates – Gel Polymer pilots at SACROC in West Texas and many areas of Kansas – IUP Pilots (Unconventionals) in Colorado – Steam Flood Pilots in Kansas – Foam Pilot at SACROC

• Started Working with Flotek/CESI/EOGA about 7 years ago

– Gel Polymer Treatments at SACROC – CnF® Foams at Katz

Dr. Lanny Schoeling, KM VP Engineering

• Discovered in 1948 • 11th Largest Field in U.S. • >2.8 Billion Barrels OOIP • 3300 psi discovery pressure • 43 Degree API – Light Sweet

Crude • Solution Gas Drive

• Canyon Reef Formation

• KM purchased SACROC in

April 2000 and took the oil production from 8K to 37K BOPD with CO2 Flooding

• This week implementing

the 100th (Flotek/EOGA) Gel polymer treatment at SACROC.

• Chemical cost per incremental barrel of oil is less than $.40/bbl.

• See SPE Paper 169176

Kelly-Snyder (SACROC) – Flotek’s Polymer Gels (Very Successful)

Platform Polymer Work

SPE 169176 • Performance Review of Gel Polymer • James Pipes and Lanny Schoeling

P1: Polymer treatments 29 wells 384,600 bbls gel

P2 Polymer treatments

30 wells 524,482 bbls gel

P3S Polymer treatments

21 wells 235,092 bbls gel

Discovered in 1956 150 MMB OOIP Discovery Pressure 2200 psig 38 deg API gravity crude Solution Gas

Strawn Formation – Sandstone

5 Layers of Sandstone

Purchased April 2006

Currently injecting CO2 and

development is ongoing

Testing CnF® Foams at Katz Injection Profiles look promising,

however to early to tell with oil.

Katz – Testing CnF Foams

0 50 100

Before

After

% of Injection Profile

KSU 164

1

2a

2b

2c

3

• 164 is not perfed in 1st or 2C

• Healthy Communication with Vendor – Professional Champions are needed both at the Vendor and

Operator level

• Agreement on the Strategic Approach

• Successful Field Demonstration of Technology

• Both Companies have to be “Top – Down” in Alignment

• Solutions must match Reservoir Challenges

Requirements for Successful Implementation of Innovative Technologies

Ely & Associates

John Ely Founder & Chief Executive Officer

Ely and Associates Corp.

John W. Ely

Founder & CEO

Quick summary of Ely Corp.

Ninety-one employees—Primary function of the company is the design and supervision of fracture treatments worldwide. In 2013 we supervised more than 60,000 frac stages and did even more in 2014.

We have a unique perspective on what is working in stimulation and have been in the forefront of slick water and small sand design and implementation.

I teach hydraulic fracturing and do also serve as an expert witness in cases typically defending the oil field service companies.

Summary of my experience

• 15 years with Halliburton in research and field operations both domestic and in the Middle East.

• 5 years as Engineering Manager for Nowsco Well Services.

• 6 years as Vice President Stimulation for Holditch & Associates.

• Started Ely Corp. May 1991

I have more than 80 publications including multiple patents and 2 books and contributions to others.

Relationship with Flotek

• Long relationship with John Chisholm

• Flotek hired me to look at the tremendous amount of data accumulated with their CnF product relating to nano chemistry.

• I have also met with their research personnel in the Woodlands to further understand the product.

Thoughts on the CnF product

• The massive amount of data collected using Frac Focus data proves without a doubt that the product is dramatically increasing production in oil and gas wells.

• I am known throughout the industry as someone who does everything possible to minimize cost and maximize profit for our customers. We, for instance, have pushed for the removal of conventional surfactants from most fracture treatments.

• For our company to recommend any product it must meet very strict criteria relating to long term production and cost effectiveness.

Way forward for Ely Corp.

• Based on the data I have seen we plan on recommending the CnF product, where applicable, and also have another project relating to re-stimulation in which we plan to incorporate the product.

• Our industry has suffered for many years with the lack of something new and exciting on the chemical side which would prove to be a game changer. I believe that now we have such a product.

Key drivers for successful completions

• For the multitude of very low permeability reservoirs which are dominating the fracturing market the use of high volume slick water combined with small proppant have literally changed our industry.

• The addition of the nano surfactant will add to this explosion in production and move our country to oil and gas independence.

Where is the industry going?

• Anyone who conclusively says what is going to happen with oil and gas prices is either wrong or has divine guidance.

• What is occurring is that we are working very hard to reduce costs and or utilizing design processes and chemicals which will allow for more cost effective production of oil and gas.

Financial Discussion

Rob Schmitz Chief Financial Officer

Financial Overview

In the most challenging market environment in memory, we achieved breakeven earnings…

$- $10.0 $20.0 $30.0 $40.0 $50.0 $60.0

1H14 12.31.2014 1H15

Net Debt

$-

$10.0

$20.0

$30.0

$40.0

1H14 1H15

Operating Income (excl. Impairment)

$-

$5.0

$10.0

$15.0

$20.0

1H14 1H15

Operating Cash Flow

$- $2.0 $4.0 $6.0 $8.0

$10.0 $12.0 $14.0

1H14 1H15

Shares Repurchased

…retained strong cash flow, maintained strong debt position and accomplished a substantial increase in share repurchases

Resilient CnF® Pricing & Recovering Margins

Q1 - 14 Q2 - 14 Q3 - 14 Q4 - 14 Q1-15 Q2 - 15 Q3 - 15e

Range of Prices for Major CnF® Products

Highest CnF Price Lowest CnF Price Fcst Fcst

Product reformulations and strategic relationships resulted in lower prices in Q1, but prices have stabilized in 2015.

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%

Q1 - 14 Q2 - 14 Q3 - 14 Q4 - 14 Q1 - 15 Q2 - 15 Q3 - 15e

ECT Gross Margin Trends

Stable to increasing margins enabled by strategic position in terpene inventory and technology reformulations.

CAPEX Outlook

$-

$2

$4

$6

$8

$10

$12

Q1-15 Q2 - 15 Q3 - 15e Q4 - 15e

Base CAPEX Global R&I Facility Expansion Opportunities

Total 2015 CAPEX expected between $25 – 30 Mil Potential expansion opportunities are associated with expanded

R&I Facilities, ECT Logistics and Production Technologies

Second Half 2015 Outlook

Continued Strong Balance Sheet Positioned for Strategic Opportunities If They Arise. No Debt Compliance Concerns.

Continued Market Share Growth in ECT

Expect Strong 3Q Sequential Revenue Growth. Stable to Increasing Margins.

Restructured Drilling Segment

Build Market Share During the Downturn. Creating Upside Opportunities in Recovery.

Making A Difference

For More Information: Christopher S. Edmonds

Senior Director – Corporate Finance & Strategy 713-726-5376

cedmonds@flotekind.com