Seventy Seven Energy Investor Relations Presentation

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Seventy Seven Energy Investor Relations Presentation
INVESTOR PRESENTATION
MAY 2015
ASSUMPTIONS AND FORWARD-LOOKING STATEMENTS
This presentation contains certain statements and information that may constitute “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical facts that address activities, events or developments that we expect,
believe or anticipate will or may occur in the future are forward-looking statements. The words “anticipate,” “believe,” “ensure,”
“expect,” “if,” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “potential,”
“would,” “may,” “probable,” “likely,” and similar expressions, and the negative thereof, are intended to identify forward-looking
statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically
include statements, estimates and projections regarding our business outlook and plans, future financial position, liquidity and
capital resources, operations, performance, acquisitions, returns, capital expenditure budgets, costs and other guidance
regarding future developments. Forward-looking statements are not assurances of future performance. These forward-looking
statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, and
perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors
believed to be appropriate. Although management believes that the expectations and assumptions reflected in these forwardlooking 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). Moreover, our forward-looking statements are subject to significant
risks and uncertainties, many of which are beyond our control, which may cause actual results to differ materially from our
historical experience and our present expectations or projections which are implied or expressed by the forward-looking
statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements
include, but are not limited to, risks relating to economic conditions; volatility of crude oil and natural gas commodity prices;
delays in or failure of delivery of current or future orders of specialized equipment; the loss of or interruption in operations of one
or more key suppliers or customers; oil and gas market conditions; the effects of government regulation, permitting and other
legal requirements, including new legislation or regulation of hydraulic fracturing; operating risks; the adequacy of our capital
resources and liquidity; weather; litigation; competition in the oil and natural gas industry; and costs and availability of resources.
For additional information regarding known material factors that could cause our actual results to differ from our present
expectations and projected results, please see our filings with the Securities and Exchange Commission (“SEC”), including our
Current Reports on Form 8-K that we file from time to time, Quarterly Reports on Form 10-Q, and Annual Report on Form 10-K
filed with the SEC on March 2, 2015.
Readers are cautioned not to place undue reliance on any forward-looking statement which speaks only as of the date on which
such statement is made. We undertake no obligation to correct, revise or update any forward-looking statement after the date
such statement is made, whether as a result of new information, future events or otherwise, except as required by applicable law.
2
MANAGEMENT TEAM
Jerry Winchester, CEO



Served for thirteen years as the President and CEO of Boots & Coots International Well Control, Inc. which was acquired by Halliburton in
September 2010
Started his career with Halliburton in 1981 as a fracturing equipment operator and served in positions of increasing responsibility, most
recently as Global Manager over Well Control, Coil Tubing and Special Services
Over 30 years of industry experience
Cary D. Baetz, CFO




Served as Senior Vice President and Chief Financial Officer of Atrium Companies, Inc. From November 2010 to December 2011
Served with Mr. Winchester as Chief Financial Officer of Boots & Coots from August 2008 to September 2010
Served as Vice President of Finance, Treasurer, and Assistant Secretary of Chaparral Steel Company from 2005 to 2008
Over 25 years of industry experience
Karl Blanchard, COO



Joined SSE in June 2014
Previously served as Vice President of Production Enhancement of Halliburton Company
Began his career at Halliburton in 1981, also serving as Vice President of Cementing, Vice President of Testing and Subsea, and President
Director of PT Halliburton Indonesia
Jay Minmier, President - Nomac Drilling



President since June 2011
Previously served as Vice President and General Manager for Precision Drilling Corporation
More than 20 years experience with drilling contractors, notably Grey Wolf Inc. and Helmerich & Payne, Inc.
William R. Stanger, President – Performance Technologies (PTL)



President since 2011
Joined in January 2010 as President of Great Plains Oilfield Rentals
A former Vice President of Schlumberger with more than twenty-five years experience in oilfield services
Jerome Loughridge, President – Great Plains Oilfield Rental



President since September 2012
Previously served as President of Black Mesa Energy Services, the oilfield investment arm of private equity firm Ziff Brothers Ventures;
Executive Chairman of completions service provider Legend Energy Services; and Chief Operating Officer of Great White Energy Services
Over eight years of oilfield management experience
3
COMPANY HIGHLIGHTS
Large integrated footprint in some of the best returning basins and close proximity to customers

Based in Oklahoma City operating in close proximity to some of the most active U.S. unconventional resource developers
Comprehensive service offerings with modern, high quality asset base

Multi-well pad capable Tier 1 and Tier 2 rigs represent 76% of fleet including fit-for-purpose PeakeRigs™


16 active PeakeRigs™ with 9 under construction
Hydraulic fracturing assets among the newest in the industry with an average age of 32 months

400,000 HP and two sand transload facilities
Industry-leading contracted backlog providing robust visibility to asset base

Contracts with multiple large, well-capitalized customers with an industry leading three-year backlog of approximately $1.4B1 of
expected future revenue
Experienced and skilled management team

Experience working at highly regarded oilfield services companies including Boots & Coots, Halliburton, Helmerich & Payne,
and Schlumberger. Managed through multiple oilfield services business cycles
Strong liquidity
1

Approximately $204 mm available under our revolving credit facility as of March 31, 2015

No scheduled debt maturity until 2019

Planning to exercise the $100 mm accordion feature under the term loan
See “Backlog and Service Contract Summary” on page 9 of this presentation
4
BUSINESS SEGMENTS AND OUTLOOK
Description
Drilling
 Provides land drilling and drilling-related services,
including directional drilling
 Marketed fleet includes 26 Tier 1 rigs, including
16 fit-for-purpose PeakeRigs™, 57 Tier 2 rigs and
seven Tier 3 rigs
TTM 3/31/15
Adjusted Adjusted
Adjusted
Revenue¹ EBITDA² EBITDA %
758
303
40%
Hydraulic Fracturing
 Provides high-pressure hydraulic fracturing
services
 10 hydraulic fracturing fleets with an aggregate of
400,000 horsepower
886
151
17%
150
50
 Current fleet of 400,000 hp
 Continue customer
diversification and growth
34%
Oilfield Trucking
 Provides drilling rig relocation and logistics
services
 9 new contracted rigs to be
delivered over the next 11
months
 Continue customer
diversification and growth
Oilfield Rentals
 Provides premium rental tools and specialized
services for land-based oil and natural gas drilling,
completion and workover activities
2015 - 2016 Business
Outlook Drivers
153
5
3%
 Continue customer
diversification and growth
Note: $mm, unaudited 2014/2015 numbers
1 “Adjusted Revenue” is a non-GAAP financial measure that we define as Revenue including the pro forma effects of the spin-off; this excludes Geosteering and Crude hauling revenue of $2mm and $10.5mm and
excludes Other Operations revenue of $2mm which is comprised of $41mm less $39mm from compression manufacturing unit that CHK retained in spin-off.
2 “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back impairments and
gain or loss on sale of property and equipment; Total and Nomac Drilling reflects EBITDA net of rig rental expense of $10mm and lease termination cost of $1.3mm. Total SSE EBITDA reflects sum of segment
EBITDA net of Other Segment of ($63mm). See pages 23-28 of this presentation for a reconciliation of GAAP measures to comparable financial measures calculated in accordance with GAAP.
5
SSE IS WELL POSITIONED FOR CURRENT INDUSTRY TRENDS
Current Industry Trend
SSE Positioning
Full scale development
plans of large shale
resources (existing and
emerging)
 Large, integrated footprint in 8 active basins
 Shale development expertise (“it’s in our DNA”)
Increased drilling
efficiencies through
modern equipment and
integrated operations
 Modern, efficient land fleet of 57 contracted rigs
 One of the newest pressure pumping fleet in the industry
 Modern well-maintained tool rental fleet
Trend towards “factory
style” development
 Highly efficient, integrated service model providing single-source drilling and
completion solutions
 Customer base of large acreage holders that are pioneering factory-style
approach
Increasing focus on
safety and regulatory
 Industry leading safety performance
6
AREAS OF OPERATIONS
Marcellus Shale
Niobrara Shale
Utica Shale
Anadarko Basin
Permian Basin
Barnett Shale
Haynesville Shale
Eagle Ford Shale
– Oklahoma City Headquarters
Significant footprint in many of the most economical plays, including Eagle Ford and Niobrara
Shales
As of 3/31/2015
7
CUSTOMER DIVERSIFICATION STRATEGY
Replicate Nomac success in winning other non CHK business
with PTL and Great Plains

Nomac revenue from other operators increased to 41% in
Q1 2015 compared to 29% in Q1 2014

Great Plains revenue from other operators increased to
44% in Q1 2015 compared to 10% in Q1 2014
Selected Customers
Business development team continues to educate market and
locate potential long term operator partners in down cycle
Continue to bundle our equipment and services to provide value
to our customers while increasing utilization
8
BACKLOG AND SERVICE CONTRACT SUMMARY
As of March 31, 2015, our contractual backlog¹ was approximately $1.4B,
~13% of which was related to contracts with operators other than CHK

Backlog expected to provide 60% to 70% of revenue in 2015

Total backlog of 36.8, 41.3, and 23.2 rig years for 2015, 2016, and thereafter

Total early termination value related to the drilling backlog was $154.6mm,
$165.9mm, and $85.8mm for 2015, 2016, and thereafter
Contracted Revenues by Business Segment
$1.4B 3 Year Backlog
Backlog includes services contracts entered into with CHK in connection with
the spin-off under which CHK committed to use the services described below,
subject to its rights to terminate the contracts in specified circumstances

As of March 31, 2015 Nomac rig-specific daywork drilling contracts for a remaining
term ranging from 3 months to 2.25 years are set forth below:

3 month term – 10 Rigs

1.25 year term – 5 rigs

2.25 year term – 25 Rigs

Additional PeakeRigs to come online through Q1 2016 on 2 year term
As of March 31, 2015 PTL hydraulic fracturing services agreement that provides CHK
will utilize the lesser of (i) the number of crews set forth below:

3 month term– 7 Crews

1.25 year term – 5 Crews

2.25 year term– 3 Crews
or (ii) percent (50%) of the total number of all pressure pumping crews working for
CHK in all of its operating regions during the respective year
PTL has recently captured term work for other operators (not reflected in
backlog number). GPOR continues to diversify customer base as well
$mm

586
557
343
258
243
300
2015
2016
269
Drilling
Completion
94
175
2017
Total
¹ We calculate our contract drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. We calculate our hydraulic fracturing
backlog by multiplying the estimated rate per stage, based on the then current contract prices, by the number of guaranteed stages remaining under the contract. Our Services Agreement
for hydraulic fracturing with CHK provides for periodic adjustments of the rates we may charge for our services thereunder, which will be negotiated based on then prevailing market
pricing and in the future may be higher or lower than the current rates we charge.
The backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or
during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, many of our contracts
are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. As a result,
revenues could differ materially from the backlog amounts presented.
9
HISTORICAL U.S. RIG CYCLES COMPARISON
120%
Historical Recent U.S. Rig Cycles - Peak to Trough Analysis
1997-99
2001-02
2008-09
2014-15
100%
80%
Peak
Trough
Δ Rigs
Δ Rigs %
1,293
738
(555)
-43%
60%
Peak
Trough
Δ Rigs
Δ Rigs %
1,929
905
(1,024)
-53%
Peak
Trough
Δ Rigs
Δ Rigs %
1,032
488
(544)
-53%
Peak
Trough
Δ Rigs
Δ Rigs %
2,031
876
(1,155)
-57%
40%
1
3
5
7
9
11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57
Week
Current trajectory suggests 1-3 remaining months to trough based on prior cycles
Source: Baker Hughes 05/01/2015
10
NOMAC DRILLING CURRENT FLEET
Currently the 5th
largest drilling rig
contractor in the U.S.¹
Utica Shale
14 Rigs
Nomac has 57
contracted rigs which
operate across
unconventional plays²
Marcellus Shale
Powder River and DJ
Basins
1 Rigs
4 Rigs
Haynesville Shale
Anadarko Basin
5 Rigs
16 Rigs
Permian Basin
7 Rigs
Eagle Ford Shale
10 Rigs
¹ Based on RigData active rig count as of 4/17/2015
² Rig count as of 5/4/2015 : excludes refurbished, stacked, training and under construction rigs
11
2014 AVG DRILLING DAYS & WELL COUNT FOR HORIZONTAL WELLS
UTICA
Drilling Contractor
Nomac
A
Contractors with one rig
B
C
Avg Total
Avg Days/Well¹
17
19
21
24
31
20
Well Count
219
203
81
78
61
642
Utica: Avg Operated Rigs By Contractor²
15
10
5
0
1Q14
EAGLE FORD
Drilling Contractor
Nomac
A
B
C
D
E
F
Contractors with one rig
G
H
Avg Total
Avg Days/Well¹
13
14
15
16
16
17
18
19
19
21
16
¹Source: RigData - spud to release analysis of all 2014 wells as noted.
²Source: RigData – 23 companies sampled
³Source: RigData – 43 companies sampled
Well Count
400
362
486
141
1,805
195
620
303
125
103
4,540
2Q14
3Q14
4Q14
Eagle Ford: Avg Operated Rigs By Contractor³
40
20
30
15
10
5
0
1Q14
2Q14
3Q14
4Q14
12
NOMAC RIG FLEET COMPARED TO PEERS
Working to convert fleet to meet longterm drilling needs of all customers
Currently 93% of our Tier 1 rigs and
68% of our Tier 2 rigs are multi-well
pad-ready and able to meet the
demands of E&P customers focused on
unconventional resource development
US Land Rig Fleet Mix April 2015¹
91%
61%
58%
47%
45%
35%
26%
77%
37%
61%
40%
25%
36%
33%
37%
19%
Total US Land Active Rig Fleet Mix¹
14%
9%
Tier 2
21%
Tier 3
28%
A
PEERS
¹ Source: RigData Weekly Locations and Operators Report list as of 5/1/2015, internal estimates
2 Nomac rig total based on marketed rigs, excludes cold stacked and rigs held for sale
B
35%
13%
9%
5%
3%
51%
3%
62%
Currently fabricating 9 proprietary
PeakeRigs, 7 of which are expected to
be delivered by the end of 2015 with
the other 2 rigs expected to be
delivered in 2016
Tier 1
18%
C
D
F
E
G
H
Nomac
2015E
Tier 1
Tier 2
Tier 3
13
EVOLUTION OF OUR FLEET
Improving tier mix contributes to higher operating margin, continuing to increase with rig
newbuilds, conversions, and removal of Tier 3 rigs
Based on contracted newbuilds, we expect to own 93 rigs by YE 2015 with 35% Tier 1 rigs

9 PeakeRig newbuilds over the next 11 months
Number of Rigs - Year End
Fleet Evolution and Operating Margin
Operating Margin
42%
160
YTD Q1 2015
40%
120
38%
91
85
80
90
93
26
33
12
20
36%
34%
57
40
57
57
57
32%
22
0
2012
Tier 1
1 Operating
Margin through Q1 2015; marketed rig count as of year end
8
7
3
2013
2014
2015E
Tier 2
Tier 3
30%
Operating Margin1
14
PERFORMANCE TECHNOLOGIES OPERATING AREAS
Utica Shale
3 spreads
Anadarko Basin
3 spreads
Eagle Ford Shale
4 spreads
PTL total fleets as of 3/31/2015
15
PTL OPERATIONS OVERVIEW
Provides high-pressure hydraulic fracturing
services
As of Mar 31, 2015, owned ten hydraulic
fracturing fleets with an aggregate of
400,000 horsepower


Seven fleets contracted by CHK and two
fleets by other operators
Operating throughout the Anadarko Basin,
Eagle Ford, and Utica Shales
North American Horsepower by Capacity
'000s HHP
HAL + BHI
4,625
Other
2,488
Schlumberger
1,900
FTS International
1,696
NBR + CJES PF
1,235
Calfrac Well Services
1,193
Trican Well Services
1,084
Patterson-UTI
1,005
Cudd Pumping (RPC)
Equipment consists of high pressure
rated, premium hydraulic fracturing
equipment specially suited for
unconventional resource plays

Among the newest in the industry with an
average age of 32 months as of Mar. 31,
2015
Source: Simmons & Company as of February 27, 2015
920
Weatherford
Superior Energy Services
800
660
Sanjel Incorporated
550
Pro Petro Services
500
Pioneer Natural Resources
450
Performance Technologies
400
Basic Energy Services
360
Keane Frac / Ultra Tech
300
U.S. Well Services
288
Go Frac
255
Total North American
Horsepower Capacity
21 MM HHP
16
HYDRAULIC FRACTURING SUPPLY CHAIN INTEGRATION
Access to three strategically positioned sand storage and trans load
Storage and Distribution
Facilities
facilities, one in Oklahoma with storage capacity of 140 million
pounds, one in south Texas with 80 million pound capacity, and one in
Transloading Facilities
Ohio with 30 million pound capacity

South Texas facility accepts multi-unit trains which secures more
favorable rail rates and significantly reduces the number of rail
car leases required to manage inventory
Sandbox
Executed JV with a dedicated hydraulic fracturing sand carrier to
ensure adequate truck transportation services for hauling hydraulic
fracturing sand from regional distribution points to the well site
Long term rail car leases procured for the bulk transportation of
Rail Cars
hydraulic fracturing sand by rail from the mine to regional distribution
hubs
Own mineral mining leases totaling approximately 2,000 acres at
Sand Reserves
multiple sand mining sites in Wisconsin; capable to self source a
majority of sand supply by 2016 helping to mitigate future impact of
sand price volatility
17
GREAT PLAINS ASSET BASE AND SERVICES
Great Plains provides premium rental tools and
specialized services for land-based oil and
natural gas drilling, completion, and workover
activities
Air Package
Tool Rental

Downhole tubular products including high-torque,
premium-connection drill pipe, drill collars, and
tubing

Surface rental equipment including blowout
preventers, frac tanks, mud tanks, and
environmental containment
Tanks
Services

Water transfer services offering lay-flat hose and
leveraging Great Plains’ surface rental asset base

Air drilling services in the Marcellus and Utica

Flowback and pressure control
18
GREAT PLAINS CURRENT AND POTENTIAL SERVICE LINES
SSE has established and is executing a plan to build out the Great Plains organization to
increase utilization
Great Plains equipment utilization remained relatively flat from Q4 2014 to Q1 2015, while
the percentage of revenue generated from non CHK sources increased from 27% to 44%
19
SEVENTY SEVEN TRUCKING ASSETS
Hodges has provided drilling rig relocation
and logistics services for over 80 years

Truck Fleet
As of March 31, 2015, we owned a fleet of
263 rig relocation trucks and 67 cranes and
forklifts
Oilfield Trucking Assets
Units
Transportation Trucks
195
Crane & Forklift
67
Rig Up
68
Hodges Crane
Transportation Truck
20
MATURITY AND DEBT SERVICE SCHEDULES
Maturity Schedule
$275
$650
$374
$2
2014
$4
2015
$4
2016
$4
2017
$4
2018
$4
2019
$4
2020
3.567%¹
2021
3.750%³
$500
2022
6.500% 4
6.625%²
Term Loan
Sr. Notes
ABL Credit Facilty
Interest Schedule5
$76
$76
$76
$76
$71
$60
$33
$33
$8
$15
$15
$15
$15
$14
$14
$7
2014
2015
2016
2017
2018
2019
2020
2021
Term Loan
$18
2022
Sr. Notes
¹ 3.75% base rate; 1.50% letter of credit
² 6.625% Senior Notes due 2019; first call price at 103%.313 on 11/15/2015
³ 3.00% + LIBOR with 75bps LIBOR floor
4 6.500% Senior Notes due 2022; first call price at 104.875% on 7/15/2017
5 Assumes Term Loan interest of 3.75% and no early call on Sr. Notes. / The $500 Senior Notes and Term Loan have issue dates as of 6/26/14 and 6/25/2014 respectively.
21
CORPORATE INFORMATION
SSE HEADQUARTERS
77nrg.com
777 NW 63rd St.
Oklahoma City, OK 73116
405-608-7777
CORPORATE CONTACTS
Bob Jarvis
Senior Director – Investor
Relations and Marketing
[email protected]
405-935-2572
22
APPENDIX
APPENDIX: RECONCILIATION OF CONSOLIDATED NET INCOME TO
ADJUSTED EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Net loss
$
(37,601) $
(18,557)
Add:
Interest expense
Income tax benefit
Depreciation and amortization
23,516
14,692
(16,232)
(10,697)
84,975
72,465
Impairments and other
6,272
19,808
Losses on sales of property and equipment, net
4,210
977
Non-cash compensation
18,355
146
Severance-related costs
1,404
167
Rent expense on buildings and real estate transferred from CHK(a)
—
4,106
Rig rent expense(b)
—
9,059
Compression unit manufacturing Adjusted EBITDA
—
6,715
Geosteering Adjusted EBITDA
—
194
Crude hauling Adjusted EBITDA
—
(543)
Less:
Adjusted EBITDA
$
84,899
$
85,800
24
APPENDIX: RECONCILIATION OF OPERATING CASH TO ADJUSTED
EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Cash provided by operating activities
$
27,513
$
54,582
Add:
Changes in operating assets and liabilities
35,102
(1,628)
Interest expense
23,516
14,692
Lease termination costs
—
8,379
Amortization of sale/leaseback gains
—
4,214
Amortization of deferred financing costs
(1,028)
Income (loss) from equity investees
(737)
972
Provision for doubtful accounts
(917)
(2,580)
Current tax expense
Severance-related costs
(83)
—
333
1,404
167
Rent expense on buildings and real estate transferred from CHK
—
4,106
Rig rent expense
—
9,059
—
Other
(1)
Less:
Compression unit manufacturing Adjusted EBITDA
—
Geosteering Adjusted EBITDA
—
194
Crude hauling Adjusted EBITDA
—
(543)
Adjusted EBITDA
$
84,899
6,715
$
85,800
25
APPENDIX: RECONCILIATION OF DRILLING NET INCOME TO
ADJUSTED EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Net income (loss)
$
479
$
(2,359)
Add:
Income tax benefit
207
Depreciation and amortization
(1,329)
49,539
34,903
Impairments and other
3,729
19,601
Losses on sales of property and equipment, net
4,386
1,710
Non-cash compensation
5,326
—
Severance-related costs
344
63
Rent expense on buildings and real estate transferred from CHK
—
880
Rig rent expense
—
9,059
—
194
Less:
Geosteering Adjusted EBITDA
Adjusted EBITDA
$
64,010
$
62,334
26
APPENDIX: RECONCILIATION OF HYDRAULIC FRACTURING NET
INCOME TO ADJUSTED EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Net income
$
6,054
$
595
Add:
Income tax expense
2,613
610
16,277
18,109
Impairments
—
207
Gains on sales of property and equipment, net
(5)
—
Depreciation and amortization
Non-cash compensation
1,238
—
Severance-related costs
81
—
—
Rent expense on buildings and real estate transferred from CHK
Adjusted EBITDA
$
26,258
630
$
20,151
27
APPENDIX: RECONCILIATION OF OILFIELD RENTALS NET INCOME
TO ADJUSTED EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Net loss
$
(3,509) $
(2,136)
Income tax expense (benefit)
(1,515)
(1,237)
Depreciation and amortization
12,172
13,347
Add:
Gains on sales of property and equipment, net
(171)
(742)
Non-cash compensation
861
—
Severance-related costs
(46)
24
—
Rent expense on buildings and real estate transferred from CHK
Adjusted EBITDA
$
7,792
720
$
9,976
28
APPENDIX: RECONCILIATION OF OILFIELD TRUCKING NET
INCOME TO ADJUSTED EBITDA
Three Months Ended March 31,
2015
2014
(In thousands)
Net loss
$
(12,836) $
(3,397)
Add:
Income tax benefit
(5,541)
(1,871)
Depreciation and amortization
5,054
5,929
Impairments
2,543
—
Gains on sales of property and equipment, net
(10)
(8)
Non-cash compensation
1,320
—
Severance-related costs
1,025
5
—
863
—
(543)
Rent expense on buildings and real estate transferred from CHK
Less:
Crude hauling Adjusted EBITDA
Adjusted EBITDA
$
(8,445) $
2,064
29
30

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