cjes investor presentation v3.3.2017 1600filecache.investorroom.com/mr5ir_cjenergy/137... · basins...

Investor PresentationMarch 2, 2017

© C&J Energy Services, Inc. 2017 2

This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as

amended (the “Exchange Act”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecast,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “potential,” “would,”

“may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements,

which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things: Our

outlook on the market for our services and products; general business and economic conditions; crude oil and natural gas commodity prices; demand for services in our industry; our plans to deploy our fleets; our

maintenance backlog, expected recovery and future prices and utilization; our outlook with respect to industry growth and market demand; our business strategy and future activity; pricing pressure and competitive factors;

our ability to obtain or renew customer contracts; the market price and availability of materials or equipment; technological developments; financial strategy, liquidity, capital required for our ongoing operations and

acquisitions and our ability to raise additional capital; our ability to obtain permits, approvals and authorizations from governmental and third parties, and the effects of governmental regulation; dividends; future financial

and operating results; and plans, objectives, expectations and intentions.

Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements

are based on our current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on

us, and other factors believed to be appropriate. Although we believe the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that

these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to

predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated

with the following: a decline in demand for our services, including due to declining commodity prices, overcapacity and other competitive factors affecting our industry; the cyclical nature and volatility of the oil and gas

industry, which impacts the level of exploration, production and development activity and spending patterns by exploration and production companies; a decline in, or substantial volatility of, crude oil and gas commodity

prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity; pressure on pricing for our core services, including due to competition and industry

and/or economic conditions, which may impact, among other things, our ability to implement price increases or maintain pricing on our core services; the loss of, or interruption or delay in operations by, one or more

significant customers; the failure to pay amounts when due, or at all, by one or more significant customers; changes in customer requirements in markets or industries we serve; costs, delays, regulatory compliance

requirements and other difficulties in executing our long-term growth strategy, including those related to expansion into new geographic regions and new business lines; the effects of future acquisitions on our business,

including our ability to successfully integrate our operations and the costs incurred in doing so; business growth outpacing the capabilities of our infrastructure; adverse weather conditions in oil or gas producing regions;

the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic

fracturing services; the incurrence of significant costs and liabilities resulting from litigation; the incurrence of significant costs and liabilities resulting from our failure to comply, or our compliance with, new or existing

environmental regulations or an accidental release of hazardous substances into the environment; the loss of, or inability to attract, key management personnel; a shortage of qualified workers; the loss of, or interruption or

delay in operations by, one or more of our key suppliers; operating hazards inherent in our industry, including the significant possibility of accidents resulting in personal injury or death, property damage or environmental

damage; accidental damage to or malfunction of equipment; uncertainty regarding our ability to improve our operating structure, financial results and profitability and to maintain relationships with suppliers, customers,

employees and other third parties following emergence from bankruptcy and other risks and uncertainties related to our emergence from bankruptcy; our ability to maintain sufficient liquidity and/or obtain adequate

financing to allow us to execute our business plan; and our ability to comply with covenants under our new credit facility.

For additional information regarding known material factors that could affect our operating results and performance, please see our most recently filed Annual Report on Form 10-K, subsequent Quarterly Reports on Form

10-Q, recent Current Reports on Form 8-K, which are available at the SEC’s website, http://www.sec.gov. Should one or more of these known material risks occur, or should the underlying assumptions change or prove

incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. All subsequent written or oral forward-looking statements concerning us are expressly qualified in

their entirety by the cautionary statements above. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future

events or otherwise, except as required by law.

All information in this presentation is as of March 2, 2017 unless otherwise indicated.

Non-GAAP Financial Measures: This presentation includes Adjusted EBITDA, a measure not calculated in accordance with generally accepted accounting principles in the U.S. ("U.S. GAAP"). Please see slide 25 for a

reconciliation of Adjusted EBITDA to net income (loss), the nearest measure calculated in accordance with U.S. GAAP.

Important Disclaimer

© C&J Energy Services, Inc. 2017

C&J Energy Services

3

Market Data (3/2/2017)

Ticker (NYSE Mkt) (1) CJ

Share Price (2) $40.00

Estimated Fully Diluted Shares

Outstanding (MM)57.5

Market Capitalization ($MM) $2,300

Net Cash Position (3) ($MM) $159

Enterprise Value ($MM) $2,141

(1) The company’s common stock has been approved to be listed on the NYSE MKT and the company expects it to begin

trading on the NYSE MKT on or about 3/6/2017

(2) Share price as of 3/2/2017 as traded on the OTC Grey Market under the ticker “CJJY”

(3) As of emergence on 1/6/2017


C&J Energy Services Snapshot

• Leading Provider of Fracturing, Wireline, Coiled Tubing, Service

Rigs and Fluids Management

• One of the largest integrated providers of completion and

production services with assets deployed across all active onshore

basins in the continental United States and Western Canada

• Diversified portfolio of products and services across the life of a

well, focused on premium customers in all active onshore basins

in the continental United States and Western Canada

• A technology leader, with a state-of-the art Research and

Technology Platform focused on new products, improving margins

and assuring cost-effective supply

Diversified Revenue Across the Spectrum

Expansive Geographic FootprintKey Differentiators

• Hydraulic Fracturing Activity: ~820K HHP fracturing capacity,

11 deployed fleets and 9 fleets available, plans to deploy 1-2

fleets per quarter through 2018

• Other Equipment: 127 wireline trucks, 44 coiled tubing units,

57 pumpdown units, 36 cementing units, 459 well service rigs,

1,121 fluid trucks and support equipment

• Supply: New supply contracts support 80% of future sand

needs at attractive pricing; internal manufacturing and refurb

capabilities

• Technology: Dedicated technology center, 25+ patents; path

to new products, margin expansion and cost effective supply

Key Facts

One of North America’s largest vertically-integrated oilfield services providers with equipment, facilities and

technical expertise distributed across all active onshore basins

Basins / Shale Plays

Business Units Regions

C&J Energy Services Assets

Appalachian BasinUtica & Marcellus

Tuscaloosa-Marine ShaleHaynesville Shale

Eagle Ford Shale

Cana Woodford Shale

Permian Basin

Granite Wash

Mississippian

Niobrara

Los Angeles Basin

San Joaquin Basin

Piceance

Uinta Basin

Denver-Julesburg Basin

Bakken Shale

CardiumMontney

36%

16%

4%

20%

14% 6% 4%

Hydraulic Fracturing

Wireline & Pumping

Other D&C Services

Well Service Rigs

Fluid Services

CT

Other Well Support

Fracturing was

53% of 2014

Revenue and is

expected to

track back

towards this in

coming years

2016 Revenue: $971MM

Service Rigs

Fluids Management

Coiled Tubing


Our Evolution Into Today’s C&J Energy Services

5

1997 – 2011

Co

rpo

rate

De

velo

pm

en

tsP

ort

foli

o G

row

th

2012 – 2014 2015 2016 2017

2012-2014:

2012: Introduced wireline

services with acquisition of

Casedhole Solutions

2013: Acquisition of Tellus

Oilfield directional drilling

technology

2013: Acquisition of MDT™

data acquisition and

controls manufacturing

2014: Acquisition of Tiger

Casedhole Solutions,

expanding wireline services

and geographic footprint

into California

2012-2014

2013: Opened New R&T

Center in Houston, TX

2016

Mar: Josh Comstock

passed away

Jun: New CEO, CFO

and GC appointed

following strategic

management

changes

Jul: Filed for Chapter

11

2015

Mar: Combination

with Nabors’

Completion and

Production

May: Acquisition

of ESP Completion

Technology,

artificial lift

systems business

2017

Jan: Emergence

from Chapter 11

January 6th

2016

Jun: Divested Blue

Ribbon Technology

(started in 2012)

Jul: Exited MENA

Operations

1997-2011

2002: Introduced

coiled tubing services

2007: Introduced

fracturing services

1997-2011

1997: Josh Comstock

founded C&J in

Robstown, TX

2011: Initial Public

Offering on NYSE

2011: Corporate

office moved to

Houston, TX

Mar 2017

Re-introduction of

the New C&J

Energy services

2017

Feb: Divested

Total Equipment

and Services

(acquired in 2011)

Focused Our Operations

on Core Activities


Leading Provider of Products and Services Across the Life of a Well

Strong Footprint in All Active Onshore Basins in the Continental U.S. and Western Canada

Modern, High-Quality Asset Base and Streamlined Cost Structure

Robust Logistics Network Ensures Efficient Operations for Our Customers

Long-Term, Established Relationships with Blue-Chip Customer Base

Recognized Leader in Quality, Safety and Reliability

Capitalized for Growth – No Leverage and Significant Liquidity

1

2

3

4

5

6

7

Experienced Management Team with Deep Operational Expertise9

The Differentiated NAm Oilfield Services Company

Unique Research & Technology Platform

8


Capital Expense Driven Operational Expense Driven

• Lateral Science™

• Diverters• Plugs• SCS• Wireline • Tanks• Fluids

Management

7

Market Leadership Across the Life of the Well

Drilling and

CementingCompletions Solutions Drill / Clean Out Re-Stimulation Well Servicing Decommissions

Research and

Technology

• Primary Cementing• Remedial

Cementing• Directional Services

Horizontal Vertical • Agitator• Coiled Tubing• Rig Services• Tanks• Fluids

Management• Disposal• Snubbing• Rigs• Flowback

• Re-Con Design• Diverters• Coiled Tubing• Rig Services• SCS• Pump Down (Acid)• Wireline• Fishing Tools• Tanks • Fluids Management• Waste & Water

Disposal • Flowback

• Rig Services• Fluids

Management• Fishing Tools• Tanks• Waste & Water

Disposal • Wireline• Coiled Tubing• Special Services• Squeeze

Cementing

• Rig Services • Fishing Tools• Wireline

(dedicated)• Cementing

(dedicated)• Tanks• Fluids

Management


• Diverters• Plugs• Re-Con Design

• Coiled Tubing (Stdby)

• Pump Down• Tanks• Fluids

Management

We are a

leading provider

in our core

service offerings

Hydraulic Fracturing (1)

Casedhole Wireline & Pumpdown

Coiled Tubing

Rig Services Fluids Management

Top 5 #1 Top 3 #2 #1

Well Construction

Well Completions Well ServicesWell

Abandonment


• Diverters • Plugs• Fracturing• Wireline

• Wireline• Coiled Tubing• TCP• Pump Down• Tanks• Fluids

Management• Tractor

Toe Prep

Stage Frac

C&J Manufactured Products 3rd Party ProductsC&J Core Services

~70% of Total Well Cost; 3 - 6 months

R&T

Note: Rankings based on internal data and industry sources

(1) Based on active fleets as of 1/1/2017

~30% of Total Well Cost; 20+ years


Our Modern, High Quality Asset Base

• 20 hydraulic

fracturing fleets,

~820,000 HHP

• 11 deployed fleets

• Advanced,

proprietary design

with CAT-CAT

configurations

Fracturing

• 127 fit-for-purpose

casedhole wireline

trucks

• 57 pumpdown

units

• Standard in the

market for

reliability and

efficiency

Casedhole Wireline

& Pumpdown

• 36 advanced

cementing units

• Advanced in-house

lab capabilities

• #1 in Customer

Satisfaction, ‘15-16

– EnergyPoint

Survey

Cementing

• 459 workover rigs

• Capability to

support complex,

deep wells with

long laterals

• ~60% have 400 HP

or greater

Rig Services

• 1,121 service

trucks, 4,243 tanks

and 29 captive (C&J

only) salt water

disposal facilities

• Provides customers

with integrated

waste and fluids

solutions

Fluids

Management

• 44 coiled tubing

units

• Over 70% of the

fleet consists of

large diameter coil

(2” or greater)

• Majority of fleet

optimized to

support operating

depths of ~23,000

feet

Coiled Tubing

We have rationalized our fleet of equipment across all service lines, leaving us well-positioned to deliver high quality services to

our customers and attractive returns to our shareholders


Strong Presence in All Active Onshore NAm Basins

C&J is Present in All Active Onshore Basins in the Continental U.S. and Western Canada…

Basins / Shale Plays

Business Units Regions

C&J Energy Services Assets

Tuscaloosa-Marine Shale

Haynesville Shale

Eagle Ford Shale

Cana Woodford Shale

Permian Basin

Granite Wash

Mississippian

Niobrara

Los Angeles Basin

San Joaquin Basin Piceance

Uinta Basin

Denver-Julesburg Basin

Bakken Shale

CardiumMontney

Appalachian BasinUtica & Marcellus

Established Footprint Provides

a Scalable Platform

• Founded in South Texas with a proven

reputation in the Eagle Ford and

Haynesville shales, we expanded our

footprint through organic and

acquisitive growth

‒ Casedhole Solutions: Bakken,

Mid-Con, West Texas, Rockies,

North East

‒ Tiger Casedhole: California

‒ Nabors C&P: US and Western

Canada

• Today, C&J has a strong presence in

all active onshore basins in the

continental US and Western Canada

• Four out of five major service lines are

present in all active US basins, which

avails our diversified offering to all

customers and provides scale benefits

• Also serves as a platform for growth

as we develop new services and

products organically and through bolt-

on acquisitions

… with a Diversified Offering In All Active Onshore NAm Basins

0

1

2

3

4

5

WestTexas

SouthTexas

NorthEast

Mid-Continent

SouthEast

California Bakken /Rockies

Canada

Frac Wireline & Pumping Coil Tubing Rig Services Fluids Mgmt.

Number of Segments Served in Each Basin

2016 Revenue by Geography

West

Texas

34%

South

Texas /

South East

18%North East

8%

Rockies /

Bakken

14%

California

13%

Mid-Con

8%

Canada

4%

Corp.

1%


Completions Footprint Poised to Benefit from Cyclical Rebound

147.2

78.0

38.351.5

66.8

0.0

50.0

100.0

150.0

2014A 2015A 2016E 2017E 2018E

Drilling CompletionSource: Coras Oilfield Research

Source: Coras Oilfield Research

U.S. Drilling and Completion Spending is Increasing Key Drivers Point Towards Cyclical Recovery

$Bn

Spending Growth Levered to Completions

$Bn

Rigs

% HZ Rigs

Avg Rig

Efficiency

Well

Count

Stage

Count

Stages Per

Well

Frac HHP

Demand

2014 Peak 2016 Average2018 Estimate

vs 2016

447

(49% y/y)1,875

87%

+4% y/y73%

17.3 HZ Wells

per Rig-Year

14.7 HZ Wells

per Rig-Year

9,124

(51% y/y)37,773

233,521

(27% y/y)489,159

25.6 Stages per

Well +49% y/y

17.7

Stages per Well

7.2MM HHP

(25% y/y)14.7MM HHP

Frac HHP

Utilization

48%

(3% y/y)79%

Dri

ve

rs

Pe

rfo

rma

nce

Me

tric

s

� Increased Spending � Rig Efficiency

� Increased HZ Drilling � More Stages

� Greater Intensity

� Higher Frac Demand

Source: Coras Oilfield Research

13.9

22.3

4.2 4.7 4.86.9

5.7 6.24.6

5.7

0.0

6.0

12.0

18.0

24.0

2016 2017 2016 2017 2016 2017 2016 2017 2016 2017

Drilling CompletionMid-conPermian Bakken Eagle Ford Marcellus /

Utica

(1)

(1) Management estimates based on industry sources

14%70% 58% 10% 22%% ∆ in Completion

Spending


Our Frac Refurbishments Are Targeting Fleet Optimization

Cat-On-Cat• Lowest cost of total ownership

• 30% longer run times and fewer catastrophic failures

• Enables real-time data sharing

• Higher reliability throughout all conditions

Warm Start• Potential 25% fuel savings

• Higher reliability, longer equipment life

Stainless

Fluid Ends

• Higher upfront costs but longer durability

• Requires sophisticated maintenance program

Frac Iron• Internal capabilities save up to 50% on re-cert costs (1)

• Increased reliability, shortened turnaround

Support

Equipment

• Patent pending sand silo system

• Integrated silica dust management

A

D

E

B

C

Standardizing our fleets with upgraded technology will improve operating efficiency and lower cost of ownership

Illustrative Reactivation CostStandardized Fleet Will Increase Efficiency and Lower Costs

A

BC

D

E

Our In-House Manufacturing and Refurb Capabilities Provide Secure Capacity to Service Our Equipment

Rigorous preventative maintenance program

results in less downtime, lower operating costs

and ensures reliable operations

Targeting equipment upgrades, providing a

platform of standardized equipment with truly

differentiated operating capabilities

Internal maintenance and service center

provides reliable access to upgrades /

refurbishment and reduces cost

$5.0 - 6.0MM per

Warm-Stacked Fleet

Refurb & Maintenance: ~35%

($1.8 - 2.1MM)

Standardization: &

Upgrades: ~65%

($3.3 - 3.9MM)

(1) Relative to third party providers and based on internal estimates of re-certification costs


Optimized Logistics & Supply Chain Capabilities

12

Secure supply of critical materials and streamlined processes will provide operating leverage in the recovery

● Streamlined the number of sand and chemical vendors while meeting future volume needs

● Eliminated all take or pay contracts related to sand

● 80% of future sand needs secured at attractive pricing

● San Angelo facility provides internal capacity as third party rebuilders become capacity constrained

● Preferred supply agreement with a premier pump manufacturer for fluid ends and component needs

● Proprietary design, fully automated and tied in with our MDT™ controls (patent pending)

● Effective dust control and accurately measures amount of sand delivered per stage

● Smaller footprint on location

● Internal capacity supports sand supply and logistics, as well as lowers “Last Mile” costs

● In negotiations with key trucking vendors to ensure driver and vehicle support ahead of projected shortages

Sand & Chemicals

Fleet Repair and

Upgrades

C&J Sand

Silo System

Trucking Fleet

Active Supply Chain Initiatives…

“Last Mile” Solution…

C&J Sand Silo System


Maintenance and workover activity lagged through

the downturn due to capex deferrals, but activity is

expected to turn around

Increased prices shorten payback, drive frequency of

well maintenance

An increase in commodity pricing should result in

increasing workover demand for existing vertical well

infrastructure

Well services rigs are also used for frac plug mill-outs

during completions

Proliferation of horizontal wells has created a

significant service backlog – each well comprised of

vertical & horizontal components requiring well

services

13

Well Servicing Presence Provides Long-Term Upside

Deferred

Maintenance

Backlog

Commodity

Recovery

Demand

Normalization

Demand for

Completions

Activity

Aging

Horizontal Oil

Well Backlog

Supply of Older Horizontal Wells is Growing

Source: IHS

0

20,000

40,000

60,000

80,000

100,000

2000 2003 2006 2009 2012 2015

Cumulative HZ Wells >4 Years Old Horizontal Wells

~65,000 HZ

wells to enter

well

maintenance

phase over

next 4 years

Horizontal Wells Cumulative HZ Wells >4 Years Old

Horizontal well maintenance also

includes work related to the vertical

portion of the horizontal well

Multiple Drivers of Growth

� Multiple Sources of Demand Growth

� Limited Capital Needed to Drive Significant Cash Flow

� Historically Profitable in All Market Conditions

Source Source text goes here

Note: WTI prices quoted are monthly averages per Bloomberg

(1) Utilization defined as active rigs as a percent of total rigs (active rigs, available rigs, idle rigs and stacked rigs)

Activity Levels Poised For Mid / Late Cycle Recovery

Active U.S. Workover Rig Count Utilization (1)

2,066

1,826

1,170 1,099

0%

15%

30%

45%

60%

75%

0

500

1,000

1,500

2,000

2,500

Jan-14

WTI: $95

Jan-15

WTI: $47

Jan-16

WTI: $32

Jan-17

WTI: $53

Permian Texas Gulf Coast Rockies

West Coast Mid-Con Arklatex

Eastern US South Louisiana Utilization

Jan 2017 posted the

first significant yoy

increase in rig count in

key regions since 2014

18% yoy

5% yoy

Source: AESC, Bloomberg


~60% of Service Rigs are Class 4 or better

0

60

120

180

Class 1 Class 2 Class 3 Class 4 Class 5

0 200 400 600 800 1,000

14

High Spec Well Servicing Rig Fleet

#

Rig classifications: Class 1: 100-199 HP, Class 2: 200-299 HP, Class 3: 300- 399, Class 4: 400-499 HP, Class 5: 500+ HP

459Total Service

Rigs

275 Capable of HZ Services

Leading Provider of Service RigsA Leading Provider of Service Rigs in the Market

Premium Equipment Optimized For High Spec Services

• 2nd largest well service rig

business in NAm

• ~60% class 4+ rigs

capable of the most

complex jobs

• Top 10 customers are

majors and large

independents

• 300+ customers served in

2016

• Strong operating

presence in California,

Rockies, Permian, South

Texas and Western

Canada

• Attract new customers

due to our culture of

service and safety

• AESC 2016 Gold Safety

Award

Significant

Scale

Diversified

Footprint

Premium

Provider

Loyal

Customers


Long-Term Relationships With Blue-Chip Customers

We Seek Customers Aligned With Our Strengths

● Established E&P companies – significant portion of our revenue generated by IOCs, large independents and well-capitalized companies

● Premium acreage positions in the most active basins –targeting “manufacturing” oriented operators seeking dedicated resources

● Customers who value our technology, scale, diversification and expertise – and the efficiencies C&J can generate for them

● Our strong reputation / track record opens doors for cross-selling opportunities at existing clients – delivering integrated services

Our Relationships Have Spanned the Cycle

● Our customer base has proven to be reliable through market and company changes

● High customer retention driven by safety and superior service quality

● Differentiated capabilities and management focus resulted in our retention of nearly all customers through recent restructuring

– Minimal lost revenue from bankruptcy and now working with nearly all previous customers post emergence

● We maintain a diverse customer base with no individual customer accounting for more than 10% of 2016 revenue

Logos from next few pages

Core Customers with Deep Ties to C&J Energy Services


Our Evolutionary Technology Advantage

Perf. Guns & Switches

• One of the lowest cost

producers of perforating guns

in the industry

• Added new line of proprietary

addressable switches

• At least 20 - 30% savings over

3rd party on switches and

accessories

Lateral Science™

• Engineered solution that

optimizes the frac design and

reduces overall costs

• Over 320 wells analyzed to

date

• Successfully used on frac jobs

for Oasis, Silverback, Virtex,

Covey Park and Energen

• Product improvement and new technologies expand quality service offerings and improve operational execution and safety

• Quality services and tools that cater directly to client’s needs resulting in lower overall costs and greater customer retention

• Allows for more effective competition vs. peers and establishes C&J as the partner of choice

• Initiatives improve margins and help protect market share in current environment, positioning C&J for growth as activity levels improve

• Ensures that we have the best components and a secure supply as market intensity increases

Research & Technology Initiative

Engineering Services

• 3rd party contracts with major

IOC

– Casing w/ burst discs and

stringshot wireline tool to

replace perf cluster

• Sold proprietary Resistivity

Tool technology to a major

OEM

– Ongoing engineering services

MDT™ (1) Frac Controls

• Costs ~50% less than

competing systems

• Total fleet synchronization

improves automation and

efficiency

• Automated blender control

improves job execution

(1) Mobile Data Technologies


R&T Capabilities Provide Product Development Platform

Our Facility Supports and Enhances Our Product Portfolio

• Experienced management team with expertise in the development and manufacturing of oilfield service products

• Experts in perforating, downhole and high-temperature electronics, data acquisition, controls, drilling tools and nuclear measurement

– 25 engineers and 75 technicians dedicated to customers' most difficult well site challenges

– Sizable Patent Portfolio: 25 granted, 40 pending, 30 patent families

Operational

Efficiency

New Business

Perforating Guns & Tools Frac Pump Warm Start

Mobile Data Technologies (MDT™) Pumpdown Tension Tools

Directional Drilling (USBS)

Cost Reduction

Lateral Science™


1.20

0.99 0.95 0.92

1.801.60

1.10

0.50

1.00

1.50

2.00

2013 2014 2015 2016

18

Our Strong Track Record of Safety

Programs That Make a Difference

• Focus on QHSE and Risk

Management is lowering reportable

incidents / accidents and winning us

new customers

• Our customers value safety and

choose us because our record rivals

larger oilfield service majors

Quality, Health, Safety, Environmental (“QHSE”) identifies critical risks and requires our employees to apply a company-wide risk mitigation strategy in everything they do

Partnered with OSHA to adopt the Voluntary Protection Plan including comprehensive safety and health programs that exceed basic compliance; recognized by the program at 6 of our Well Service facilities (C&J has 6 out of 7 of OSHA VPP worksites)

Customized training and development centers that feature intense skill-based learning courses on well control, crane operation, field & hydraulic operations, driver and master driver training

All employees are trained to work within our industry leading initiative featuring “12 Rules to Live By” that promotes a culture where safety is second nature

QHSE OSHA VPP Employee Training Start Safe. Finish Safe

Total Recordable Incident Rate

C&J Energy Services

Industry Average (1)

(1) Industry average based on Bureau of Labor and Statistics


Quality Management System That Rivals the OFS Majors’

Our Quality Management System supports our core values and sets us apart from other companies of our size

Well Control Maintenance Telematics Partnerships

Core Focus Areas of QMS

● Improved visibility of transfers, standardized processes, ability to monitor equipment in real time

● Active employee monitoring and consequence management

● Partnerships with organizations like OSHA strengthen safety and health in the workplace

● Comprehensive training system designed to prevent injury and environmental damage

How it WorksHow it Works Why QMSWhy QMS

• Identify the critical risk

• Systematically and consistently

streamline our work processes

utilizing our best practices

• Focus on pragmatic employee

training and development

• Adopt firm-wide risk mitigation

strategy and management

analytics

• Creates standardization

throughout all facets of our

business

• Allows replication of success and

efficiency across every business

line and location

• Reduces on-the-job incidents

and accidents

• Enhances the reliability and

quality of our products


FINANCIAL REVIEW


2015

21

Summary of Key Business Drivers

Hydraulic Fracturing

Wireline and

Pumpdown

Rig Services

Fluids Management

Coiled Tubing

Product Lines 20162014 4Q 2016

Co

mp

leti

on

Se

rvic

es

We

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Average Active HHP (k) 1,040 840 480 430

Total Stages 29,800 18,649 11,413 2,760

Revenue ($MM) 2,038 960 354 89

Average Active Wireline Trucks 130 115 68 60

Average Active Pumpdown Units 44 56 44 42

Revenue ($MM) 455 306 159 44

Average Active Rigs 342 275 197 190

Rig Hours (k) 967 645 430 113

Revenue ($MM) 592 345 197 51

Average Active Trucks 1,216 1,076 725 640

Truck Hours (k) 3,107 2,215 1,385 302

Revenue ($MM) 357 232 133 29

Average Active CT Units 44 34 27 25

Revenue ($MM) 210 127 56 13

(1) Pro forma for March 2015 Nabors Completion & Production Services transaction

Revenue ($MM) 123 90 38 10Cementing & Other

Revenue ($MM) 85 54 34 9Other Well Support

(1) (1)


Company’s Current Outlook on Market

Hydraulic

Fracturing

Wireline &

Pumpdown

Rig Services

Fluids

Management

Coiled

Tubing

Other Well

Support

Activity Outlook Pricing Expectations

• We expect pricing to increase 30 - 35% from 2016 average

– Pricing to-date is up 15 - 25% versus the Q4’16 average

• Anticipated further improvement in 2018 of between 15 -

25% assuming activity remains strong

• Given current market trends, we anticipate redeploying 160

- 200K HHP of additional upgraded HHP in 2017 and another

160 - 240K HHP in 2018

• Anticipated utilization gains expected to drive stage count

per fleet growth of 15 - 20% in 2017 with sustained

performance through 2018

• We anticipate activating an additional 10 - 20 combined

wireline trucks and pumpdown units by the end of 2017

• An additional 10 - 20 trucks and units would be deployed in

2018 if the rebound continues to show strength

• We expect 2017 average revenue per wireline truck and

pumpdown unit to rise 20 - 25% over the 2016 average as a

result of improving pricing and utilization

• Further improvement of between 10 - 20% is expected in

2018 assuming robust activity levels

• We expect high single digit percentage increases in rig

hours across 2017 and 2018 as a result of improving

utilization and more efficient operations

• Robust demand fundamentals point to a strong mid / late

cycle recovery for well services

• We anticipate pricing remains near Q4 2016 with a modest

rise of less than 5% in 2017 and a 10%+ improvement in

2018

• We estimate low single digit percentage increases in total

truck hours in 2017 improving by 5 - 10% in 2018

• We expect 2017 pricing to remain flat versus 2016 average

and anticipate a modest rise through 2018

• Given current activity, we anticipate operating between 23

- 28 units on average in 2017 and between 25 - 32 units on

average in 2018

• We expect 2017 pricing, utilization and efficiency gains

should result in revenue per unit growth of between 35 -

40% over the 2016 average, with further improvement of

between 10 - 20% anticipated in 2018

• We anticipate annual revenue growth between 5-10% in 2017 and approximately 10 - 20% in 2018

EBITDA Margins

& Capex

• Expect consolidated adjusted EBITDA margins to be in the mid single digits for 2017 and to be in the mid-teens in 2018

– ~65 - 75% of the adjusted EBITDA to be related to our Completion Services line and ~25 - 35% related to our Well Support

Services line

– By 2018 we expect margins to be generally in line with 2014 PF margin, which included select underperforming assets

• Total capital expenditures expected to range between ~$140 - $160 million in 2017 and ~$180 - $220 million in 2018

Cementing

& Other

• We expect annual revenue growth between 20 - 25% in 2017 and approximately 40 - 50% in 2018

– Majority of the growth driven by our cementing service line

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Conservative Capital Structure

Key Highlights

• As of emergence, C&J had ~$224MM in total

liquidity comprised of $159MM of cash and

additional liquidity provided by its $100MM

credit facility

– Initial ABL availability is limited to $80MM

and subject to any outstanding letters of

credit

–At time of emergence, outstanding letters of

credit totaled ~$15MM

–We do not anticipate the need to draw on our

ABL facility in the near term

• At emergence, C&J had no outstanding long

term debt or any off-balance sheet

arrangements

Clean Balance Sheet and Strong Liquidity

Note: All metrics as of emergence on 1/6/2017

$MM At Emergence

1/6/2017

Total Debt -

Liquidity

Total Cash 159

ABL Availability 80

Letters of Credit (15)

Total Liquidity 224


Historical Financial Summary

Select Historical Financial Information


(2) Please see slide 25 for a reconciliation of Adjusted EBITDA to net income (loss), the nearest measure

calculated in accordance with U.S. GAAP

$MM; unless otherwise stated

2013 2014 2015 2016

Full Year Pro Forma (1)

Q1'16 Q2'16 Q3'16 Q4'16 Full Year

Revenue

Completion Services 1,933 2,597 1,327 152 124 128 140 544

Well Support Services 1,202 1,244 759 116 99 103 102 420

Other & Corporate 12 20 28 2 2 2 2 8

Total Revenue 3,147 3,861 2,115 270 225 233 244 971

Gross Profit

Total Gross Profit 842 846 240 8 (5) 16 5 24

% Margin 27% 22% 11% 3% (2%) 7% 2% 2%

Net Income / (Loss) 96 (244) (879) (428) (291) (106) (118) (944)

Adjusted EBITDA (2)

Completion Services 381 384 36 (18) (17) (6) 1 (39)

Well Support Services 249 255 100 6 2 6 4 17

Other & Corporate (66) (84) (82) (20) (17) (19) (17) (73)

Total Adjusted EBITDA 564 555 53 (32) (33) (18) (12) (95)

% Margin 18% 14% 3% (12%) (15%) (8%) (5%) (10%)


Non-GAAP Reconciliation

Adjusted EBITDA Reconciliation*


(2) FY 2014 and FY 2015 pro forma net income (loss) is net of acquisition related costs of $20MM and $43MM, respectively, as

disclosed in the 2015 10K filing

* We present Adjusted EBITDA, because management believes that the disclosure of Adjusted EBITDA as a measure of the Company’s operating performance allows investors to

make a direct comparison to competitors, without regard to differences in capital and financing structure and the incurrence of other charges that impact comparability of our

results of operations to those of our competitors. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall

profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To

compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income (loss)

and net income (loss), to evaluate performance. As required under Regulation G and Item 10(e) of Regulation S-K, the table above provides a reconciliation of Adjusted EBITDA, a

non-GAAP financial measure, to net income (loss), which is the nearest comparable U.S. GAAP financial measure for the years ended December 31, 2016, 2015, 2014 and 2013. We

generally define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation and amortization, other income (expense), gain or loss on the disposal of

assets and other items that our management considers to be extraordinary, such as impairment expenses, acquisition-related costs, costs and charges associated with severance,

facility closures, write-offs of bad debts and similar charges. Additionally, for the year ended December 31, 2016, we have deducted in calculating Adjusted EBITDA several categories

of expenses and charges incurred in connection with our Chapter 11 proceedings which are detailed in the table above. For the years ended December 31, 2013, 2014 and 2015, we

are presenting Adjusted EBITDA and net income on a pro forma basis for the March 2015 Nabors completion and production services transaction. For a discussion of the adjustments

made in preparing the pro forma information, please see the pro forma financial statements included in our Registration Statement on Form S-4/A, Current Report on Form 8-K/A

and Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 12, 2015, March 24, 2015 and March 2, 2017, respectively. A reconciliation of

2017 and 2018 Adjusted EBITDA cannot be provided without unreasonable efforts due to the uncertainty in identifying the categories and amounts of items that will impact net

income in those periods.

$MM

2013 2014 2015 2016

Full Year Pro Forma (1)

Q1'16 Q2'16 Q3'16 Q4'16 Full Year

Net Income / (Loss) (2) 96 (244) (879) (428) (291) (106) (118) (944)

Interest Expense 94 98 99 25 122 8 2 157

Income Tax / (Benefit) 56 56 (330) (94) (11) (21) (2) (129)

Depreciation and Amortization 261 246 310 59 54 51 53 217

Other (Income) / Expense (0) 33 10 (3) (2) (7) 3 (10)

(Gain) / Loss on Disposal of Assets 9 2 (1) 3 2 (1) (1) 3

Impairment Expense 20 364 792 382 49 - 6 436

Debt Restructuring & Reorganization Costs - - - - 15 49 21 86

Inventory Write-down - - 31 1 12 0 22 35

Acquisition-Related Costs - - - 4 3 1 2 11

Severance, Facility Closures and Other 27 0 21 19 14 7 2 42

Adjusted EBITDA 564 555 53 (32) (33) (18) (12) (95)

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