UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 0-22664
Patterson-UTI Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State
or
other
jurisdiction
of
incorporation
or
organization)
10713 W. Sam Houston Pkwy N, Suite 800, Houston, Texas
(Address
of
principal
executive
offices)
75-2504748
(I.R.S.
Employer
Identification
No.)
77064
(Zip
Code)
Registrant’s telephone number, including area code:
(281) 765-7100
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, $0.01 Par Value
Name of Exchange on Which Registered
The Nasdaq Global Select Market
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ or No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ or No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒
No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes ☒ or No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
☒
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial
accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2017, the last business day of the registrant’s
most recently completed second fiscal quarter, was approximately $4.2 billion, calculated by reference to the closing price of $20.19 for the common stock on the Nasdaq Global
Select Market on that date.
As of February 16, 2018, the registrant had outstanding 222,286,372 shares of common stock, $0.01 par value, its only class of common stock.
Documents incorporated by reference:
Portions of the registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of
the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities
Litigation Reform Act of 1995, as amended. These forward-looking statements involve risk and uncertainty. These forward-looking statements include, without
limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of operations; oil and natural gas prices; rig counts; source and
sufficiency of funds required for building new equipment, upgrading existing equipment and additional acquisitions (if opportunities arise); impact of inflation;
demand for our services; competition; equipment availability; government regulation; debt service obligations; and other matters. Our forward-looking statements
can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipate,” “believe,” “budgeted,” “continue,”
“could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “potential,” “project,” “pursue,” “should,” “strategy,” “target,” or “will,” or the negative thereof
and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our
experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the
circumstances.
On April 20, 2017, we completed our merger with Seventy Seven Energy Inc. (“SSE”), pursuant to which a subsidiary of ours was merged with and into SSE,
with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”). On October 11, 2017, we completed our acquisition of
MS Directional, LLC (f/k/a Multi-Shot, LLC) (“MS Directional”). These forward-looking statements include, without limitation, our expectations with respect to:
•
•
•
synergies, costs and other anticipated financial impacts of the SSE merger and the MS Directional acquisition;
future financial and operating results of the combined company; and
the combined company’s plans, objectives, expectations and intentions with respect to future operations and services.
Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will
prove to have been correct. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results,
performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and
uncertainties also include those set forth under “Risk Factors” contained in Item 1A of this Report and in Management’s Discussion and Analysis of Financial
Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the
“SEC”) under the Exchange Act and the Securities Act, as well as, among others, risks and uncertainties relating to:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the diversion of management time on merger-related issues;
the ultimate timing, outcome and results of integrating our operations with those of SSE and MS Directional;
the effects of our business combination with SSE and MS Directional, including the combined company’s future financial condition, results of
operations, strategy and plans;
potential adverse reactions or changes to business relationships resulting from the SSE merger and MS Directional acquisition;
expected benefits from the SSE merger and MS Directional acquisition and our ability to realize those benefits;
the results of merger-related litigation, settlements and investigations;
availability of capital and the ability to repay indebtedness when due;
volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates;
loss of key customers;
utilization, margins and planned capital expenditures;
synergies, costs and financial and operating impacts of acquisitions;
interest rate volatility;
compliance with covenants under our debt agreements;
excess availability of land drilling rigs, pressure pumping and directional drilling equipment, including as a result of reactivation, improvement or
construction;
specialization of methods, equipment and services and new technologies;
1
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
operating hazards attendant to the oil and natural gas business;
failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts);
difficulty in building and deploying new equipment;
expansion and development trends of the oil and natural gas industry;
weather;
shortages, delays in delivery, and interruptions in supply, of equipment and materials;
the ability to retain management and field personnel;
the ability to effectively identify and enter new markets;
the ability to realize backlog;
strength and financial resources of competitors;
environmental risks and ability to satisfy future environmental costs;
global economic conditions;
adverse oil and natural gas industry conditions;
adverse credit and equity market conditions;
operating costs;
competition and demand for our services;
liabilities from operational risks for which we do not have and receive full indemnification or insurance;
governmental regulation;
ability to obtain insurance coverage on commercially reasonable terms;
financial flexibility;
legal proceedings and actions by governmental or other regulatory agencies;
technology-related disputes; and
other financial, operational and legal risks and uncertainties detailed from time to time in our SEC filings.
We caution that the foregoing list of factors is not exhaustive. Additional information concerning these and other risk factors is contained in this Report and
may be contained in our future filings with the SEC. You are cautioned not to place undue reliance on any of our forward-looking statements. The forward-
looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-
looking statements, whether as a result of new information, future events or otherwise. In the event that we update any forward-looking statement, no inference
should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements. All subsequent
written and oral forward-looking statements concerning us or other matters and attributable to us or any person acting on our behalf are expressly qualified in their
entirety by the cautionary statements above.
2
Item 1. Business
Available Information
PART I
This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website ( www.patenergy.com ) as soon as reasonably practicable after
we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make
with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You
may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site ( www.sec.gov
) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
Overview
We are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling
rigs and a large fleet of pressure pumping equipment. We were formed in 1978 and reincorporated in 1993 as a Delaware corporation.
Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North
America. As of December 31, 2017, we had a drilling fleet that consisted of 295 marketed land-based drilling rigs. A drilling rig includes the structure, power
source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. We also have a substantial inventory of drill pipe and
drilling rig components that support our drilling operations.
We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Mid-Continent and Appalachian regions. Pressure pumping
services consist primarily of well stimulation services (such as hydraulic fracturing) and cementing services for completion of new wells and remedial work on
existing wells. As of December 31, 2017, we had approximately 1.6 million fracturing horsepower to provide these services. Our pressure pumping operations are
supported by a fleet of other equipment, including blenders, tractors, manifold trailers and numerous trailers for transportation of materials to and from the worksite
as well as bins for storage of materials at the worksite.
We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States. Our directional
drilling services include directional drilling, downhole performance motors, directional surveying, measurement-while-drilling, and wireline steering tools.
We have other operations where we provide oilfield rental equipment in many of the major producing onshore oil and gas basins in the United States, and we
also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets. In addition, we own
and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
Recent Developments
On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028 (the “2028 Notes”) initially
guaranteed on a senior unsecured basis by certain of our subsidiaries. The net proceeds before offering expenses were approximately $521 million, of which we
used $239 million to repay amounts outstanding under our revolving credit facility. We intend to use the remainder of the net proceeds for general corporate
purposes.
On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional. The aggregate consideration paid by
us consisted of $69.8 million in cash and approximately 8.8 million shares of our common stock. Based on the closing price of our common stock on the closing
date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.
3
On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with SSE. On April 20, 2017, pursuant to the m erger
agreement, a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly - owned subsidiaries. Pursuant
to the terms of the merger agreement, we acquired all of the issued and outstanding shares o f common stock of SSE, in exchange for approximately 46.3 million
shares of our common stock. Concurrent with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing
price of our common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5
billion. On April 20, 2017, following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Sev en Energy LLC (“SSE
LLC”), with SSE LLC continuing as the surviving entity and one of our wholly - owned subsidiaries.
Through the SSE merger, we acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® rigs. Additionally, through the SSE merger, we
acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas. The oilfield rentals business acquired
through the SSE merger has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas
drilling, completion and workover activities.
Operational data in the discussion and analysis in this Report includes the results of operations of the MS Directional business since October 11, 2017 and the
results of operations of the SSE businesses since April 20, 2017.
Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2015, 2016 and 2017 are as follows:
2015:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
2016:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
2017:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
$
$
$
48.54 $
165
33.18 $
71
51.77 $
81
57.85 $
122
45.41 $
55
48.24 $
145
46.42 $
105
44.85 $
60
48.16 $
159
41.96
88
49.15
66
55.37
159
(1) The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
(2) A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of
$26.19 in February 2016. Oil and natural gas prices have modestly recovered from the lows experienced in the first quarter of 2016. Oil prices averaged $55.37
per barrel in the fourth quarter of 2017.
Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has improved since the second quarter of
2016. Our average rig count in the United States was 159 rigs for both the third and fourth quarter of 2017, with the third quarter of 2017 being the first quarter
with a full quarter contribution from the rigs acquired in the SSE merger. Our rig count in the United States at December 31, 2017 was 163 rigs. Term contracts
have supported our operating rig count during the last three years. Based on contracts currently in place, we expect an average of 96 rigs operating under term
contracts during the first quarter of 2018 and an average of 67 rigs operating under term contracts throughout 2018.
Activity levels in our pressure pumping business also improved during 2017, especially in the Permian Basin. We reactivated two frac spreads during the third
quarter and one additional frac spread during the fourth quarter. With the addition of these three frac spreads, we exited 2017 with 23 active frac spreads or
approximately 1.25 million active fracturing horsepower.
Industry Segments
Our revenues, operating income (loss) and identifiable assets are primarily attributable to two industry segments:
•
•
contract drilling services, and
pressure pumping services.
Our contract drilling services industry segment had operating losses in 2017, 2016 and 2015. Our pressure pumping services industry segment had operating
income in 2017 and operating losses in 2016 and 2015. Our third industry segment, directional drilling services, is a new segment for us as a result of the MS
Directional acquisition and accounted for approximately two percent of our 2017 consolidated revenues.
4
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 14 of Notes to Consolidat ed Financial Statements
included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.
Contract Drilling Operations
General — We market our contract drilling services to major, independent and other oil and natural gas operators. As of December 31, 2017, we had
295 marketed land-based drilling rigs based in the following regions:
•
•
•
•
•
•
•
71 in west Texas and southeastern New Mexico,
32 in north central and east Texas and northern Louisiana,
42 in the Rocky Mountain region (Colorado, Wyoming and North Dakota),
40 in south Texas,
55 in western Oklahoma,
48 in the Appalachian region (Pennsylvania, Ohio and West Virginia), and
7 in western Canada.
Our marketed drilling rigs have rated maximum depth capabilities ranging from approximately 13,200 feet to 25,000 feet. All of these drilling rigs are electric
rigs. An electric rig converts the power from its diesel engines into electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig
components, which may be used in the activation of additional drilling rigs or as upgrades or replacement parts for marketed rigs.
Drilling rigs are typically equipped with engines, drawworks, top drives, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other
related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade
and maintain our drilling rigs. We have spent approximately $954 million during the last three years on capital expenditures to (1) build new land drilling rigs and
(2) modify, upgrade and extend the lives of components of our drilling fleet. During fiscal years 2017, 2016 and 2015, we spent approximately $354 million,
$73 million and $527 million, respectively, on these capital expenditures.
Depth and complexity of the well, drill site conditions and the number of wells to be drilled on a pad are the principal factors in determining the specifications
of the rig selected for a particular job.
Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, fuel and other materials and
qualified personnel. Some of these have been in short supply from time to time.
Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our bid for each job depends upon
location, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed
contract. Our drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of
a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently six months to two years) and provide for the use of the
drilling rig to drill multiple wells. During 2017, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down)
was approximately 15 days.
Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our drilling personnel and
necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for an
early termination payment to us in the event that the contract is terminated by the customer.
Our drilling contracts provide for payment on a daywork basis. Under daywork contracts, we provide the drilling rig and crew to the customer. The customer
provides the program for the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often
receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions
beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. All of the wells we drilled in 2017, 2016 and 2015 were
under daywork contracts.
5
From time to time more than five y ears ago, we contracted to drill some wells to a certain depth under specified conditions for a fixed price per foot (on a
footage basis) or for a fixed fee (on a turnkey basis). We generally assume greater operational and economic risk drilling on a turn key basis than on a footage
basis and greater operational and economic risk drilling on a footage basis than on a daywork basis.
Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:
Average rigs operating per day - U.S.(1)
Average rigs operating per day - Canada(1)
Number of rigs operated during the year
Number of wells drilled during the year
Number of operating days
2017
Year Ended December 31,
2016
2015
136
2
179
3,160
50,427
63
2
100
1,470
23,596
120
4
223
2,448
45,142
(1)
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to match the needs of our
customers. While conventional wells remain a source of oil and natural gas, our customers have expanded the development of shale and other unconventional
wells to help supply the long-term demand for oil and natural gas in North America.
To address our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays, we have expanded our areas of operation and
improved the capability of our drilling fleet. We have delivered new APEX ® rigs to the market and have made performance and safety improvements to existing
high capacity rigs. APEX ® rigs are electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other
automated pipe handling equipment. APEX ® rigs that are pad capable are designed to efficiently drill multiple wells from a single pad, by “walking” between the
wellbores without requiring time to lower the mast and lay down the drill pipe. As of December 31, 2017, our marketed land-based drilling fleet was comprised of
the following:
Classification
APEX ® 1500 HP rigs
APEX ® 1000 HP rigs
APEX ® 1200 HP rigs
APEX ® 1400 HP rigs
APEX ® 2000 HP rigs
Other electric rigs
Total
Average horsepower
United States
Number of Rigs
Canada
Total
Percent Pad Capable
164
20
4
5
5
90
288
1
—
—
—
—
6
7
165
20
4
5
5
96
295
1,394
1,171
1,389
86%
100%
100%
100%
60%
49%
75%
The U.S. land rig industry has recently begun referring to certain high specification rigs as “super-spec” rigs. We consider a super-spec rig to be a 1,500
horsepower, AC powered rig that has a 750,000 pound hookload, has a 7,500 psi circulating system and is pad capable. We currently estimate there are
approximately 550 super-spec rigs in the United States, which includes 130 of our APEX® rigs.
We perform repair and/or overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, Colorado, North Dakota,
Pennsylvania and western Canada.
Pressure Pumping Operations
General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (West and South Regions) and the Mid-Continent (Mid-
Con Region) and Appalachian regions (Northeast Region). Pressure pumping services consist of well stimulation services (such as hydraulic fracturing) and
cementing services for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require
well stimulation through hydraulic fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to
fracture the formation. Many wells in conventional plays also receive well stimulation services. The cementing process inserts material between the wall of the
well bore and the casing to support and stabilize the casing.
6
Pressure Pumping Contracts – Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The
term contracts are generally entered into for a specified period of time and may include minimum rev enue, usage or stage requirements. We are compensated
based on a combination of charges for equipment, personnel, materials, mobilization and other items.
Equipment — We have pressure pumping equipment used in providing hydraulic fracturing services as well as nitrogen, cementing and acid pumping services,
with a total of approximately 1.6 million horsepower as of December 31, 2017. Pressure pumping equipment at December 31, 2017 included:
West Texas Region
Number of units
Approximate horsepower
South Texas Region
Number of units
Approximate horsepower
Mid-Con Region
Number of units
Approximate horsepower
Northeast Region
Number of units
Approximate horsepower
Combined:
Number of units
Approximate horsepower
Fracturing
Equipment
Other
Pumping
Equipment
Total
235
537,950
147
361,250
134
305,500
169
353,800
30
30,890
—
—
—
—
95
55,400
265
568,840
147
361,250
134
305,500
264
409,200
685
1,558,500
125
86,290
810
1,644,790
Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, manifold trailers and numerous trailers for
transportation of materials to and from the worksite as well as bins for storage of materials at the worksite.
Materials – Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short
supply, including severe shortages, from time to time. We purchase these materials from various suppliers. These purchases are made in the spot market or
pursuant to other arrangements that do not cover all of our required supply and sometimes require us to purchase the supply or pay liquidated damages if we do not
purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are
unable to reach an agreement with a supplier for delivery of any particular material, or should one of our suppliers fail to timely deliver our materials.
Directional Drilling Operations
General – We generally utilize our own proprietary downhole motors and equipment to provide a comprehensive suite of directional drilling services, including
directional drilling, downhole performance motors, directional surveying, measurement while drilling (“MWD”), and wireline steering tools, in most major onshore
oil and natural gas basins in the United States. We generally design, manufacture and maintain our own fleet of downhole drilling motors and MWD equipment.
We occasionally rent motors and equipment from third parties during periods in which we experience shortages from our vendors, which can occur during periods
of increased industry activity. As a complement to our core directional drilling services, we provide downhole survey services and rent our proprietary drilling
motors to both oil and natural gas operators and other oilfield service companies. Our customers primarily consist of major integrated energy companies and large
North American independent oil and natural gas operators. We believe our customers use our services because of the quality of our specialized, technology-driven
equipment and our well-trained and experienced workforce, which enable us to provide our customers with high-quality, reliable and safe directional drilling
services. We utilize our fleet of directional drilling motors, MWD equipment and survey equipment to provide: (1) directional drilling services, (2) third-party
motor rentals and (3) downhole survey services.
7
Directional Drilling Services – We provide our directional drilling services on a day-rate basis, typically under master service agreements. Revenue from
directional drilling services is recognized as work progresses based on the numbe r of days of work completed. Our day rates and other charges generally vary by
location and depend on the equipment and personnel required for the job and market conditions in the region in which the services are performed. In addition to
rates that are charged during periods of active directional drilling, a stand-by rate is typically agreed upon in advance and charged on a daily basis during periods
when drilling is temporarily suspended while other on-site activity is conducted at the direction of the operator or another service provider.
Third-Party Motor Rental – We rent our drilling motors on an hourly- or day-rate basis to complement our directional drilling services and optimize the
utilization of our asset base. Our third-party motor rental revenue is recognized as work progresses based on the number of days or hours our motors are used or are
on location.
Downhole Survey Services – We provide our downhole survey services on a day-rate, hourly-rate or completed-job basis. Revenue for our downhole survey
services is recognized upon the completion of each day’s work. Our downhole survey services are typically non-contractual. We normally provide a quote to our
customers in advance and then issue an invoice for the downhole survey services provided based on a completed field ticket.
Equipment – We generally design, manufacture, maintain and inspect our own equipment. We occasionally rent motors and equipment from third parties during
periods in which we experience shortages from our vendors, which can occur during periods of increased industry activity. We have developed proprietary
equipment for our drilling motors, mud pulse and electromagnetic data transfer MWD equipment and survey tools. We believe that our vertical integration strategy
allows us to deliver better operational performance and higher equipment reliability to our customers. Vertical integration also allows us to build our tools more
efficiently and at a lower cost than if purchased from third parties. In addition, we have th e ability to upgrade our tools in response to market conditions or our
customers’ job requirements, which allows us to minimize the costs and delays associated with sending equipment to original manufacturers. Our internal
maintenance capability also affords us enhanced control over our supply chain and increases the effective utilization of our assets. As of December 31, 2017, we
had a comprehensive fleet of over 1,600 motors that serve both internal needs and external motor rental requirements. In addition to our motor fleet, we had 112
MWD systems as well as downhole surveying equipment to provide accurate wellbore surveys.
Oilfield Rentals
Our oilfield rentals business has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and
natural gas drilling, completion and workover activities. We offer an extensive line of rental tools, including a full line of tubular products specifically designed for
horizontal drilling and completion, with high-torque, premium-connection drill pipe, drill collars and tubing. Additionally, we offer surface rental equipment
including blowout preventers, frac tanks, mud tanks and environmental containment that encompass all phases of the hydrocarbon extraction and production
process. Our air drilling equipment and services enable extraction in select basins where certain segments of formations preclude the use of drilling fluid,
permitting operators to drill through problematic zones without the risk of fluid absorption and damage to the wellbore. We also provide frac-support services,
including delivery of on-site frac water through a water transfer operation using innovative lay-flat pipe, and monitoring and controlling of production returns. We
offer oilfield rental services in many of the major producing onshore oil and gas basins in the United States. We price our rentals and services based on the type of
equipment being rented and the services being performed. Substantially all rental revenue we earn is based upon a charge for the actual period of time the rental is
provided to our customer on a market-based, fixed per-day or per-hour fee.
Contracts
We believe that our contract drilling, pressure pumping, directional drilling and oilfield rentals contracts generally provide for indemnification rights and
obligations that are customary for the markets in which we conduct those operations. However, each contract contains the actual terms setting forth our rights and
obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer
requirements, applicable law or other factors.
Customers
Our customer base includes major, independent and other oil and natural gas operators. With respect to our consolidated operating revenues in 2017, we
received approximately 43% from our ten largest customers and approximately 29% from our five largest customers. During 2017, no customer accounted for
more than 10% of our consolidated operating revenues. The loss of, or reduction in business from, one or more of our larger customers could have a material
adverse effect on our business, financial condition, cash flows and results of operations.
8
Backlog
Our contract drilling backlog as of December 31, 2017 and 2016 was $544 million and $417 million, respectively. Approximately 19% of the total contract
drilling backlog at December 31, 2017 is reasonably expected to remain after 2018. See “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” included as a part of Item 7 of this Report for information pertaining to backlog.
Competition
The businesses in which we operate are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand,
particularly in an industry downturn, such as the current market environment. The price for our services is a key competitive factor, in part because equipment used
in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical
specifications of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect
that the market for our services will continue to be highly competitive.
Government and Environmental Regulation
All of our operations and facilities are subject to numerous federal, state, foreign, regional and local laws, rules and regulations related to various aspects of our
business, including:
•
•
•
•
•
•
drilling of oil and natural gas wells,
hydraulic fracturing, cementing, nitrogen and acidizing and related well servicing activities,
directional drilling services, third-party motor rentals and downhole survey services,
containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
use of underground storage tanks and injection wells, and
our employees.
To date, applicable environmental laws and regulations in the places in which we operate have not required the expenditure of significant resources outside the
ordinary course of business. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply
with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become
material, and we could incur liability in any instance of noncompliance.
Our business is generally affected by political developments and by federal, state, foreign, regional and local laws, rules and regulations that relate to the oil and
natural gas industry. The adoption of laws, rules and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons
could increase costs relating to drilling, completion and production, and otherwise have an adverse effect on our operations. Federal, state, foreign, regional and
local environmental laws, rules and regulations currently apply to our operations and may become more stringent in the future. Any limitation, suspension or
moratorium of the services we or others provide, whether or not short-term in nature, by a federal, state, foreign, regional or local governmental authority, could
have a material adverse effect on our business, financial condition and results of operations.
We believe we use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of, or
released in or under properties currently or formerly owned or operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater
contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under
federal, state, foreign, regional and local laws, rules and regulations. In addition, some of these properties have been operated by third parties over whom we have
no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials. We could be
required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and
natural gas properties in which we own an interest but are not the operator.
Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does
not cover all environmental laws and regulations that govern our operations.
In the United States, the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as
CERCLA, and comparable state statutes impose strict liability on:
•
•
owners and operators of sites, including prior owners and operators who are no longer active at a site; and
persons who disposed of or arranged for the disposal of “hazardous substances” found at sites.
9
The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and implementing regulations govern the disposal
of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of
exploration and production wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the
future. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) and environmental groups entered into a consent decree to address the
EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from
regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D crite
ria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If changes are made to the classification
of exploration and production wastes under CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including
materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal
or remedial actions to prevent future contamination.
The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, each as amended, and implementing regulations govern:
•
•
the prevention of discharges, including oil and produced water spills, into jurisdictional waters; and
liability for drainage into such waters.
The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into jurisdictional waters from
facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of federal
safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.
The Oil Pollution Act also expands the authority and capability of the federal government to direct and manage oil spill clean-up and operations, and requires
operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or
into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to
civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable under the Oil
Pollution Act are potentially much greater and can include natural resource damages.
The U.S. Occupational Safety and Health Administration (“OSHA”) promulgates and enforces laws and regulations governing the protection of the health and
safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes
require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and
local governments and citizens. Also, OSHA has established a variety of standards related to workplace exposure to hazardous substances and employee health and
safety.
Our activities include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability,
such as shale and other unconventional formations. Due to concerns raised relating to potential impacts of hydraulic fracturing, including on groundwater quality
and seismic activity, legislative and regulatory efforts at the federal level and in some state and local jurisdictions have been initiated to render permitting and
compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas
production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production
customers. See “Item 1A. Risk Factors – Potential Legislation and Regulation Covering Hydraulic Fracturing or Other Aspects of the Oil and Gas Industry Could
Increase Our Costs and Limit or Delay Our Operations.”
In Canada, a variety of federal, provincial and municipal laws, rules and regulations impose, among other things, restrictions, liabilities and obligations in
connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills,
releases and emissions of various substances to the environment. Other jurisdictions where we may conduct operations have similar environmental and regulatory
regimes with which we would be required to comply. These laws, rules and regulations also require that facility sites and other properties associated with our
operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to
existing projects may require the submission and approval of environmental assessments or permit applications. These laws, rules and regulations are subject to
frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.
10
Our operations are also subject to federal, state, foreign, regional and local laws, rules and regulations for the control of air emissions, including those
associated with the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in
the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For more
information, please refer to our discussion under “Item 1A. Risk Factors – Environmental and Occupatio nal Health and Safety Laws and Regulations, Including
Violations Thereof, Could Materially Adversely Affect Our Operating Results.”
We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change
issues. We are also aware of legislation proposed by U.S. lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations
enacted by the EPA and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or
regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where
necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. See “Item
1A. Risk Factors – Legislation and Regulation of Greenhouse Gases Could Adversely Affect Our Business.”
Risks and Insurance
Our operations are subject to many hazards inherent in the businesses in which we operate, including inclement weather, blowouts, well fires, loss of well
control, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other
property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death,
property damage, loss of oil and natural gas production, pollution and other environmental damages.
We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our contracts
typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification
may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers and other third
parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer
these risks to our customers and other third parties by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or
insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.
We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either
because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other
risks of physical loss to our equipment and certain other assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and
insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this
insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, a
substantial portion of our equipment and certain other assets, such insurance does not cover the full replacement cost of such equipment or other assets. We have
also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a
$1.5 million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance
coverage, a $2.0 million per occurrence deductible on our general liability coverage and a $2.0 million per occurrence deductible on our automobile liability
insurance coverage. We also self-insure a number of other risks, including loss of earnings and business interruption and cybersecurity risks, and we do not carry a
significant amount of insurance to cover risks of underground reservoir damage.
Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes
aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There
can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not
rise significantly in the future, so as to make the cost of such insurance prohibitive, or that our coverage will cover a specific loss. Further, we may experience
difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for which we are not
fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.
If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could
have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Item 1A. Risk Factors – Our Operations Are Subject
to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not
Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.”
11
Employees
We had approximately 8,000 full-time employees as of February 16, 2018. The number of employees fluctuates depending on the current and expected demand
for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.
Seasonality
Seasonality has not significantly affected our overall operations. However, our drilling operations in Canada are subject to slow periods of activity during the
annual spring thaw. Additionally, toward the end of some years, we experience slower activity in our pressure pumping operations in connection with the holidays
and as customers’ capital expenditure budgets are depleted. Occasionally, our operations have been negatively impacted by severe weather conditions.
Raw Materials and Subcontractors
We use many suppliers of raw materials and services. Although these materials and services have historically been available, there is no assurance that such
materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.
Item 1A. Risk
Factors.
You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks
and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually
occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the other information set forth in this
Report, including our consolidated financial statements and the related notes.
We
Are
Dependent
on
the
Oil
and
Natural
Gas
Industry
and
Market
Prices
for
Oil
and
Natural
Gas.
Declines
in
Customers’
Operating
and
Capital
Expenditures
and
in
Oil
and
Natural
Gas
Prices
May
Adversely
Affect
Our
Operating
Results.
We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in North
America. When these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing
industry conditions that are influenced by numerous factors over which we have no control, such as:
•
•
•
•
•
the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage,
the prices, and expectations about future prices, of oil and natural gas,
the supply of and demand for drilling, pressure pumping and directional drilling services,
the cost of exploring for, developing, producing and delivering oil and natural gas,
the environmental, tax and other laws and governmental regulations regarding the exploration, development, production and delivery of oil and natural gas,
and in particular, public pressure on, and legislative and regulatory interest within, federal, state, foreign, regional and local governments to stop,
significantly limit or regulate drilling and pressure pumping activities, including hydraulic fracturing, and
• merger and divestiture activity among oil and natural gas producers.
In particular, our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future
prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices, and expectations about future prices, are affected by factors
such as:
• market supply and demand,
•
•
•
•
•
the desire and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production and price targets,
the level of production by OPEC and non-OPEC countries,
domestic and international military, political, economic and weather conditions,
legal and other limitations or restrictions on exportation and/or importation of oil and natural gas,
technical advances affecting energy consumption and production, and
12
•
the price and availability of alternative fuels.
All of these factors are beyond our control. The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of
2014 and reached a twelve-year low of $26.19 in February 2016. As a result of the lower level of oil prices, our industry has experienced a severe decline in both
contract drilling and pressure pumping activity levels. While oil and natural gas prices modestly recovered since the first quarter of 2016, and we have experienced
an increase in the demand for our services since 2016, our average number of rigs operating remains well below the number of our available rigs, and a portion of
our pressure pumping horsepower remains stacked.
We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher
oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future
oil and natural gas prices. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of decreases in oil and natural gas
prices, would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on
our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may
cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our
services.
Global
Economic
Conditions
May
Adversely
Affect
Our
Operating
Results.
Global economic conditions and volatility in commodity prices may cause our customers to reduce or curtail their drilling and well completion programs, which
could result in a decrease in demand for our services. In addition, uncertainty in the capital markets, whether due to global economic conditions, low commodity
prices or otherwise may result in reduced access to, or an inability to obtain, financing by us, our customers and our suppliers and result in reduced demand for our
services. Furthermore, these factors may result in certain of our customers experiencing an inability or unwillingness to pay suppliers, including us. The global
economic environment in the past has experienced significant deterioration in a relatively short period, and there is no assurance that the global economic
environment will not quickly deteriorate again due to one or more factors, including a decline in the price for oil or natural gas. A deterioration in the global
economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Excess
Equipment
and
a
Highly
Competitive
Oil
Service
Industry
May
Adversely
Affect
Our
Utilization
and
Profit
Margins
and
the
Carrying
Value
of
our
Assets.
The North American land drilling and pressure pumping businesses are highly competitive, and at times available land drilling rigs and pressure pumping
equipment exceed the demand for such equipment. A low commodity price environment can result in substantially more drilling rigs and pressure pumping
equipment being available than are needed to meet demand. In addition, in recent years there has been a substantial increase in the construction of new technology
drilling rigs and new pressure pumping equipment and the improvement of existing drilling rigs. Low commodity prices and construction of new equipment and
the improvement of existing drilling rigs can result in excess capacity and substantial competition for a declining number of drilling and pressure pumping
contracts. Even in an environment of high oil and natural gas prices and increased drilling activity, reactivation and improvement of existing drilling rigs and
pressure pumping equipment, construction of new technology drilling rigs and new pressure pumping equipment, and movement of drilling rigs and pressure
pumping equipment from region to region in response to market conditions or otherwise can lead to an excess supply of equipment. In addition, we may be unable
to replace fixed-term contracts that were terminated early, extend expiring contracts or obtain new contracts in the spot market, and the rates and other material
terms under any new or extended contracts may be on substantially less favorable rates and terms. Accordingly, high competition and excess equipment can cause
drilling, pressure pumping and directional drilling contractors to have difficulty maintaining utilization and profit margins and, at times, result in operating
losses. We cannot predict the future level of competition or excess equipment in the oil and natural gas contract drilling, pressure pumping or directional drilling
businesses or the level of demand for our contract drilling, pressure pumping or directional drilling services.
The excess supply of operable land drilling rigs, increasing rig specialization and excess pressure pumping and directional drilling equipment, which has been
exacerbated by a decline in oil and natural gas prices could affect the fair market value of our drilling, pressure pumping and directional drilling equipment, which
in turn could result in additional impairments of our assets. A prolonged period of lower oil and natural gas prices could result in future impairment to our long-
lived assets and goodwill.
13
Our
Operations
Are
Subject
to
a
Number
of
Operational
Risks,
Including
Environmental
and
Weather
Risks,
Which
Could
Expose
Us
to
Significant
Losses
and
Damage
Claims.
We
Are
Not
Fully
Insured
Against
All
of
These
Risks
and
Our
Contractual
Indemnity
Provis
ions
May
Not
Fully
Protect
Us.
Our operations are subject to many hazards inherent in the businesses in which we operate, including inclement weather, blowouts, well fires, loss of well
control, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other
property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death,
property damage, loss of oil and natural gas production, pollution and other environmental damages.
We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our customer
contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to
indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. In addition,
certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly
prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s
indemnification of us.
Our customers and other third parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other
reasons. Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements. Incurring a
liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of
operations.
We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either
because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other
risks of physical loss to our equipment and certain other assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and
insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this
insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, a
substantial portion of our equipment and certain other assets, such insurance does not cover the full replacement cost of such equipment or other assets. We have
also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a
$1.5 million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance
coverage, a $2.0 million per occurrence deductible on our general liability coverage, and a $2.0 million per occurrence deductible on our automobile liability
insurance coverage. We also self-insure a number of other risks, including loss of earnings and business interruption and cyber risks, and we do not carry a
significant amount of insurance to cover risks of underground reservoir damage.
Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes
aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There
can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not
rise significantly in the future, so as to make the cost of such insurance prohibitive, or that our coverage will cover a specific loss. Further, we may experience
difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for which we are not
fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.
On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our
employees. Based on the information we have available as of the date of this Report, we believe that we have adequate insurance to cover any losses, excluding the
applicable insurance deductibles and investigation-related expenses. However, if this accident is not, or another significant accident or other event occurs that is
not, fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial
condition, cash flows and results of operations.
14
Our
Current
Backlog
of
Contract
Drilling
Revenue
May
Decline
and
May
Not
Ultimately
Be
Realized,
as
Fixed-Term
Cont
racts
May
in
Certain
Instances
Be
Terminated
Without
an
Early
Termination
Payment.
Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an early termination payment to us if a contract is
terminated prior to the expiration of the fixed term. However, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a
specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to
us. Additionally, during depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate or
renegotiate or otherwise fail to honor their contractual obligations. In addition, we may not be able to perform under these contracts due to events beyond our
control, and our customers may seek to terminate or renegotiate our contracts for various reasons, including those described above. As a result, we may be unable
to realize all of our current contract drilling backlog. In addition, the termination or renegotiation of fixed-term contracts without the receipt of early termination
payments could have a material adverse effect on our business, financial condition, cash flows and results of operations. As of December 31, 2017, our contract
drilling backlog for future revenues under term contracts, which we define as contracts with a fixed term of six months or more, was approximately
$544 million. Our contract drilling backlog may decline, as fixed-term drilling contract coverage over time may not be offset by new contracts, including as a
result of the decline in the price of oil and natural gas, capital spending reductions by our customers or other factors. For these and other reasons, our contract
drilling backlog may not generate sufficient liquidity for us during periods of reduced demand for our services.
New
Technologies
May
Cause
Our
Operating
Methods,
Equipment
and
Services
to
Become
Less
Competitive,
and
Higher
Levels
of
Capital
Expenditures
May
Be
Necessary
to
Remain
Competitive
in
Our
Industry.
The market for our services is characterized by continual technological and process developments that have resulted in, and will likely continue to result in,
substantial improvements in the functionality and performance of drilling rigs and other equipment. Our customers are increasingly demanding the services of
newer, higher specification drilling rigs and other equipment. Accordingly, a higher level of capital expenditures may be required to maintain and improve existing
rigs and other equipment and purchase and construct newer, higher specification drilling rigs and other equipment to meet the increasingly sophisticated needs of
our customers. In addition, technological changes, process improvements and other factors that increase operational efficiencies could continue to result in oil and
natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days. Technological and process developments in
the pressure pumping and directional drilling businesses could have similar effects.
In recent years, we have added drilling rigs to our fleet through new construction, purchased new pressure pumping equipment and acquired a directional
drilling services company. We have also improved existing drilling rigs and pressure pumping equipment by adding equipment designed to enhance functionality
and performance. Although we take measures to ensure that we use advanced oil and natural gas drilling, pressure pumping and directional drilling technology,
changes in technology, improvements in competitors’ equipment and changes relating to the wells to be drilled and completed could make our equipment less
competitive.
If we are not successful keeping pace with technological advances in a timely and cost-effective manner, demand for our services may decline. If any
technology that we need to successfully compete is not available to us or that we implement in the future does not work as we expect, we may be adversely
affected. Additionally, new technologies, services or standards could render some of our equipment and services obsolete, which could have a material adverse
impact on our business, financial condition, cash flows and results of operation.
Shortages,
Delays
in
Delivery,
and
Interruptions
in
Supply,
of
Equipment
and
Materials
Could
Adversely
Affect
Our
Operating
Results.
During periods of increased demand for oilfield services, the industry has experienced shortages of equipment for upgrades, drill pipe, replacement parts and
other equipment and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of
these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could
result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons:
• weather issues, whether short-term such as a hurricane, or long-term such as a drought,
•
•
transportation and other logistical challenges, and
a shortage in the number of vendors able or willing to provide the necessary equipment and materials, including as a result of commitments of vendors to
other customers or third parties or bankruptcies or consolidation.
These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating
costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to operate, maintain, upgrade and construct our drilling rigs and
pressure pumping and other equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.
15
Loss
of
Key
Personnel
and
Competition
for
Experienced
Personnel
May
Neg
atively
Impact
Our
Financial
Condition
and
Results
of
Operations
.
We greatly depend on the efforts of our key employees to manage our operations. The loss of members of management could have a material adverse effect on
our business. In addition, we utilize highly skilled personnel in operating and supporting our businesses. In times of increasing demand for our services, it may be
difficult to attract and retain qualified personnel, particularly after a prolonged industry downturn. During periods of high demand for our services, wage rates for
operations personnel are also likely to increase, resulting in higher operating costs. During periods of lower demand for our services, we may experience
reductions in force and voluntary departures of key personnel, which could adversely affect our business and make it more it difficult to meet customer demands
when demand for our services improves. In addition, even if it is generally a period of lower demand for our services, if there is a high demand for our services in
certain areas, it may be difficult to attract and retain qualified personnel to perform services in such areas. The loss of key employees, the failure to attract and
retain qualified personnel and the increase in labor costs could have a material adverse effect on our business, financial condition, cash flows and results of
operations.
The
Loss
of
Large
Customers
Could
Have
a
Material
Adverse
Effect
on
Our
Financial
Condition
and
Results
of
Operations.
With respect to our consolidated operating revenues in 2017, we received approximately 43% from our ten largest customers, 29% from our five largest
customers and 8% from our largest customer. The loss of, or reduction in business from, one or more of our larger customers could have a material adverse effect
on our business, financial condition, cash flows and results of operations.
Growth
Through
Acquisitions
or
the
Building
of
New
Rigs
and
Pressure
Pumping
Equipment
Is
Not
Assured.
We have increased our drilling rig fleet and pressure pumping fleet and expanded our business lines in the past through mergers, acquisitions and new
construction. For example, we completed the SSE merger and the MS Directional acquisition during 2017. There can be no assurance that acquisition
opportunities will be available in the future or that we will be able to execute timely or efficiently any plans for building new rigs and pressure pumping
equipment. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved
technology has enhanced the ability to recover oil and natural gas, improved commodity prices may cause contract drillers to continue to build new, high
technology rigs and providers of pressure pumping services to continue to build new, high horsepower equipment.
There can be no assurance that we will:
•
•
•
•
have sufficient capital resources to complete additional acquisitions or build new rigs or pressure pumping equipment,
successfully integrate additional drilling rigs, pressure pumping equipment or other assets or businesses, including SSE and MS Directional,
effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping equipment,
successfully deploy idle, stacked, upgraded or additional rigs and pressure pumping equipment,
• maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment, or
•
successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition or the building of new
drilling rigs and pressure pumping equipment.
Our failure to achieve consolidation savings, to integrate acquired businesses and assets into our existing operations successfully or to minimize any unforeseen
operational difficulties could have a material adverse effect on our business. In addition, we may incur liabilities arising from events prior to any acquisitions or
prior to our establishment of adequate compliance oversight. While we generally seek to obtain indemnities for liabilities for events occurring before such
acquisitions, these are limited in amount and duration, may be held to be unenforceable or the seller may not be able to indemnify us.
We may incur substantial indebtedness to finance future acquisitions, build new drilling rigs or build new pressure pumping equipment, and we also may issue
equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a significant burden
on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also,
continued growth could strain our management, operations, employees and other resources.
16
Environmental
and
Occupational
Health
and
Safety
Laws
and
Regulatio
ns,
Including
Violations
Thereof,
Could
Materially
Adversely
Affect
Our
Operating
Results.
Our business is subject to numerous federal, state, foreign, regional and local laws, rules and regulations governing the discharge of substances into the
environment, protection of the environment and worker health and safety, including, without limitation, laws concerning the containment and disposal of hazardous
substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance
with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to:
•
substantial civil, criminal and/or administrative penalties,
• modification, denial or revocation of permits or other authorizations,
•
•
imposition of limitations on our operations, and
performance of site investigatory, remedial or other corrective actions.
In addition, environmental laws and regulations in the countries in which we operate impose a variety of requirements on “responsible parties” related to the
prevention of spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and pressure pumping equipment, a
manufacturer and servicer of oilfield service equipment and a provider of directional drilling services, we may be deemed to be a responsible party under these laws
and regulations.
Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws,
regulations or enforcement policies could significantly increase compliance costs for us and our customers and have a material adverse effect on our operations or
financial position. For example, on August 16, 2012, the EPA issued final rules that establish new air emission control requirements for natural gas and NGL
production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic
compounds and National Emissions Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas
production and processing activities. In June 2016, the EPA published a final rule that updates and expands the New Source Performance Standards by setting
additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In addition,
the EPA has announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural
gas facilities. The EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil
and gas industry. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural
gas producers who operate on federal and Indian lands. The rules limited routine flaring of natural gas, require the payment of royalties on avoidable gas losses and
require plans or programs relating to gas capture and leak detection and repair. The EPA issued a two-year stay of these requirements in December 2017 and has
indicated that the requirements could be rescinded or significantly revised in the future. These or other initiatives could increase costs to us and our customers or
reduce demand for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Potential
Legislation
and
Regulation
Covering
Hydraulic
Fracturing
or
Other
Aspects
of
the
Oil
and
Gas
Industry
Could
Increase
Our
Costs
and
Limit
or
Delay
Our
Operations.
Members of the U.S. Congress and the EPA are reviewing proposals for more stringent regulation of hydraulic fracturing, a technology employed by our
pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas
production. For example, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. As part of
this study, the EPA sent requests to a number of companies, including our company, for information on hydraulic fracturing practices. We responded to the
inquiry. The EPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some
circumstances, including large volume spills and inadequate mechanical integrity of wells. Further, we conduct drilling, pressure pumping and directional drilling
activities in numerous states. Some parties believe that there is a correlation between hydraulic fracturing and other oilfield related activities and the increased
occurrence of seismic activity. When caused by human activity, such seismic activity is called induced seismicity. The extent of this correlation, if any, is the
subject of studies of both state and federal agencies. In addition, a number of lawsuits have been filed against other industry participants alleging damages and
regulatory violations in connection with such activity. These and other ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing
under the Safe Drinking Water Act (“SDWA”) and other aspects of the oil and gas industry.
17
In addition, legi slation has been proposed, but not enacted, in the U.S. Congress to amend the SDWA to require the disclosure of chemicals used by the oil and
gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydrau lic fracturing process to initiate legal proceedings
based on allegations that specific chemicals used in the fracturing process are impairing ground water or causing other damage. These bills, if enacted, could
establish an additional level of regulation at the federal or state level that could limit or delay operational activities or increase operating costs and could result in
additional regulatory burdens that could make it more difficult to perform or limit hydraulic fracturing and increase our costs of compliance and doing business.
Regulatory efforts at the federal level and in many states have been initiated to require or make more stringent the permitting and compliance requirements for
hydraulic fracturing operations. The EPA has asserted federal regulatory authority over hydraulic fracturing using fluids that contain “diesel fuel” under the
SDWA Underground Injection Control Program and has released a revised guidance regarding the process for obtaining a permit for hydraulic fracturing involving
diesel fuel. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic
Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Further, in March 2015, the Bureau of
Land Management (“BLM”) issued a final rule to regulate hydraulic fracturing on Indian land. The rule requires companies to publicly disclose chemicals used in
hydraulic fracturing operations to the BLM. However, these rules were rescinded by rule in December 2017. In June 2016, the EPA published final pretreatment
standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. These regulatory initiatives could each spur further
action toward federal and/or state legislation and regulation of hydraulic fracturing activities. Certain states where we operate have adopted or are considering
disclosure legislation and/or regulations. For example, Colorado, Louisiana, Montana, North Dakota, Texas and Wyoming have adopted a variety of well
construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. Additional
regulation could increase the costs of conducting our business and could materially reduce our business opportunities and revenues if our customers decrease their
levels of activity in response to such regulation.
In addition, in light of concerns about induced seismicity, some state regulatory agencies have modified their regulations or issued orders to address induced
seismicity. For example, the Oklahoma Corporation Commission (“OCC”) has implemented volume reduction plans, and at times required shut-ins, for oil and
natural gas disposal wells injecting wastewater into the Arbuckle formation. The OCC also recently released well completion seismicity guidelines for operators in
the SCOOP and STACK plays that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity.
Finally, some jurisdictions have taken steps to enact hydraulic fracturing bans or moratoria. In June 2015, New York banned high volume fracturing activities
combined with horizontal drilling. Certain communities in Colorado have also enacted bans on hydraulic fracturing. Voters in the city of Denton, Texas approved
a moratorium on hydraulic fracturing in November 2014, though it was later lifted in 2015. These actions have been the subject of legal challenges.
The adoption of any future federal, state, foreign, regional or local laws that impact permitting requirements for, result in reporting obligations on, or otherwise
limit or ban, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing and could increase our costs of compliance and doing
business and reduce demand for our services. Regulation that significantly restricts or prohibits hydraulic fracturing could have a material adverse impact on our
business, financial condition, cash flows and results of operations.
The
Design,
Manufacture,
Sale
and
Servicing
of
Products,
including
Rig
Components,
May
Subject
Us
to
Liability
for
Personal
Injury,
Property
Damage
and
Environmental
Contamination
Should
Such
Equipment
Fail
to
Perform
to
Specifications.
We provide products, including rig components such as top drives, to customers involved in oil and gas exploration, development and production. Because of
applications which use our products and services, a failure of such equipment, or a failure of our customer to maintain or operate the equipment properly, could
cause damage to the equipment, damage to the property of customers and others, personal injury and environmental contamination, leading to claims against us.
Legislation
and
Regulation
of
Greenhouse
Gases
Could
Adversely
Affect
Our
Business
We are aware of the increasing focus of local, state, regional, national and international regulatory bodies on GHG emissions and climate change
issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the
United States and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries to
meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. The EPA
has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis. Further, following a finding by the
EPA that certain GHGs represent an endangerment to human health, the EPA finalized a rule to address permitting of GHG emissions from stationary sources
under the Clean Air Act’s New Source Review Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V
programs to apply to certain stationary sources of GHG
18
emissions in a multi-step process, with the largest sources first subject to permitting. However, in June 2014, the U. S. Supreme Court in UARG v. EPA limited
application of this rule to sources that would otherwise need permits based on emission of conventional pollutants. In April 2015, the D.C. Circuit Court of
Appeals narrowed the rule in accordance with the Supreme C ourt’s decision. In October 2015, the EPA finalized rules that added new sources to the scope of the
GHG monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydrauli
cally fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Also, in November 2016, the
EPA published a final rule adding monitoring methods for detecting leaks from oil and gas equipment and emission factors for leaking equipment to be used to
calculate and report GHG emissions resulting from equipment leaks. In addition, the United States was actively involved in the United Nations Conference on
Climate Change in Paris, which led to the creation of the Paris Agreement. In April 2016, the United States signed the Paris Agreement, which requires countries
to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, ev ery five years. In June 2017,
President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department informed the United
Nations of the United States’ withdrawal in August 2017. However, s everal states and geographic regions in the United States have adopted legislation and
regulations to reduce emissions of GHGs. Additional legislation or regulation by these states and regions, the EPA, and/or any international agreements to which
the Uni ted States may become a party, that control or limit GHG emissions or otherwise seek to address climate change could adversely affect our operations. The
cost of complying with any new law, regulation or treaty will depend on the details of the particular program. We will continue to monitor and assess any new
policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take
appropriate actions, where necessary. Any d irect and indirect costs of meeting these requirements may adversely affect our business, results of operations and
financial condition. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs
and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or
regulations reduce demand for oil and natural gas.
Legal
Proceedings
and
Governmental
Investigations
Could
Have
a
Negative
Impact
on
Our
Business,
Financial
Condition
and
Results
of
Operations.
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. For example, the January 22, 2018
accident at a drilling site in Pittsburg County, Oklahoma is currently under governmental investigation by the EPA, OSHA and the U.S. Chemical Safety and
Hazard Investigation Board. In addition, during periods of depressed market conditions, we may be subject to an increased risk of our customers, vendors, current
and former employees and others initiating legal proceedings against us. Lawsuits or claims against us could have a material adverse effect on our business,
financial condition and results of operations. Any legal proceedings or claims, even if fully indemnified or insured, could negatively affect our reputation among
our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Technology
Disputes
Could
Negatively
Impact
Our
Operations
or
Increase
Our
Costs.
Our services and products use proprietary technology and equipment, which can involve potential infringement of a third party’s rights, including patent
rights. The majority of the intellectual property rights relating to our drilling rigs, pressure pumping equipment and directional drilling services are owned by us or
certain of our supplying vendors. However, in the event that we or one of our supplying vendors becomes involved in a dispute over infringement rights relating to
equipment owned or used by us, services performed by us or products provided by us, we may lose access to important equipment or our ability to provide services
or products, or we could be required to cease use of some equipment or forced to modify our equipment, services or products. We could also be required to pay
license fees or royalties for the use of equipment or provision of services or products. Technology disputes involving us or our supplying vendors could have a
material adverse impact on our business, financial condition and results of operations.
Political,
Economic
and
Social
Instability
Risk
and
Laws
Associated
with
Conducting
International
Operations
Could
Adversely
Affect
Our
Opportunities
and
Future
Business.
We currently conduct operations in Canada, and we have incurred selling, general and administrative expenses related to the evaluation of and preparation for
other international opportunities. Also, we sell products, including rig components, for use in numerous oil and gas producing regions outside of North America.
International operations are subject to certain political, economic and other uncertainties generally not encountered in U.S. operations, including increased risks of
social and political unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving
disputes and enforcing contractual rights, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, changes in taxation
policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and
regulation of the economy and industry in the markets in which we may operate, economic and financial instability of national oil companies, and restrictive
governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.
19
There can be no assurance that there will not be changes in local laws, regulations and administrative requirements, or the interpretation thereof, which could
have a material adverse effe ct on the cost of entry into international markets, the profitability of international operations or the ability to continue those operations
in certain areas. Because of the impact of local laws, any future international operations in certain areas may b e conducted through entities in which local citizens
own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct
operations under contract to local entities. Wh ile we believe that neither operating through such entities nor pursuant to such arrangements would have a material
adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our op erations to conform to local
law (or the administration thereof) on terms we find acceptable.
There can be no assurance that we will:
•
•
•
•
•
•
identify attractive opportunities in international markets,
have sufficient capital resources to pursue and consummate international opportunities,
successfully integrate international drilling rigs, pressure pumping equipment or other assets or businesses,
effectively manage the start-up, development and growth of an international organization and assets,
hire, attract and retain the personnel necessary to successfully conduct international operations, or
receive awards for work and successfully improve our financial condition, results of operations, business or prospects as a result of the entry into one or
more international markets.
In addition, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions generally prohibit companies and their
intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. Some parts of the world where contract
drilling and pressure pumping activities are conducted or where our consumers for the Warrior products are located have experienced governmental corruption to
some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practice and could impact business. Any
failure to comply with the FCPA or other anti-bribery legislation could subject to us to civil, criminal and/or administrative penalties or other sanctions, which
could have a material adverse impact on our business, financial condition and results of operation. We could also face fines, sanctions and other penalties from
authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the
seizure of drilling rigs, pressure pumping equipment or other assets.
We may incur substantial indebtedness to finance an international transaction or operations, and we also may issue equity, convertible or debt securities in
connection with any such transactions or operations. Debt service requirements could represent a significant burden on our results of operations and financial
condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, international expansion could strain our
management, operations, employees and other resources.
The occurrence of one or more events arising from the types of risks described above could have a material adverse impact on our business, financial condition
and results of operations.
Our
Business
Is
Subject
to
Cybersecurity
Risks
and
Threats.
Our operations are increasingly dependent on information technologies and services. Threats to information technology systems associated with cybersecurity
risks and cyber incidents or attacks continue to grow, and include, among other things, storms and natural disasters, terrorist attacks, utility outages, theft, viruses,
malware, design defects, human error, or complications encountered as existing systems are maintained, repaired, replaced, or upgraded. Risks associated with
these threats include, among other things:
•
•
•
•
•
theft or misappropriation of funds;
loss, corruption, or misappropriation of intellectual property, or other proprietary or confidential information (including customer, supplier, or employee
data);
disruption or impairment of our and our customers’ business operations and safety procedures;
loss or damage to our worksite data delivery systems; and
increased costs to prevent, respond to or mitigate cybersecurity events.
20
Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks and other cyber events are evolving and
unpredictable. Moreover, we have no control over the information technology systems of our customers, suppliers, and others with which our systems may connect
and communicate. As a result, the occurrence of a cyber in cident could go unnoticed for a period time. Any such incident could have a material adverse effect on
our business, financial condition and results of operations.
We
Are
Dependent
Upon
Our
Subsidiaries
to
Meet
our
Obligations
Under
Our
Long-Term
Debt.
We have borrowings outstanding under our senior notes and, from time to time, our revolving credit facility. These obligations are guaranteed by each of our
existing U.S. subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends
paid to us by our subsidiaries. If our subsidiaries do not generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal
payment obligations.
Variable
Rate
Indebtedness
Subjects
Us
to
Interest
Rate
Risk,
Which
Could
Cause
Our
Debt
Service
Obligations
to
Increase
Significantly.
We have in place a committed senior unsecured credit facility that includes a revolving credit facility. Interest is paid on the outstanding principal amount of
borrowings under the credit facility at a floating rate based on, at our election, LIBOR or a base rate. The applicable margin on LIBOR rate loans varies from
3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on our excess availability under the credit
facility. As of December 31, 2017, the applicable margin on LIBOR rate loans was 3.50% and the applicable margin on base rate loans was 2.50%. As of
December 31, 2017, we had $268 million outstanding under our revolving credit facility at a weighted average interest rate of 5.71%.
We have in place a reimbursement agreement pursuant to which we are required to reimburse the issuing bank on demand for any amounts that it has disbursed
under any of our letters of credit issued thereunder. We are obligated to pay the issuing bank interest on all amounts not paid by us on the date of demand or when
otherwise due at the LIBOR rate plus 2.25% per annum. As of December 31, 2017, no amounts had been disbursed under any letters of credit.
Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts borrowed.
A
Downgrade
in
Our
Credit
Rating
Could
Negatively
Impact
Our
Cost
of
and
Ability
to
Access
Capital.
Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S.
credit rating agencies. Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels and other
considerations. A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require
us to post letters of credit for certain obligations.
We
May
Not
Be
Able
to
Generate
Sufficient
Cash
to
Service
All
of
Our
Debt,
Including
Our
Senior
Notes
and
Debt
Under
Our
Credit
Agreement,
and
We
May
Be
Forced
to
Take
Other
Actions
to
Satisfy
Our
Obligations
Under
Our
Debt,
which
May
Not
Be
Successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to
prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain
a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
In addition, if our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital
expenditures, sell assets or operations, seek additional capital or restructure or refinance our debt. We cannot assure you that we would be able to take any of these
actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under
the terms of our existing or future debt agreements. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might
be required to dispose of material assets or operations to meet our debt service and other obligations. However, our Credit Agreement and senior notes contain
restrictions on our ability to dispose of assets. We may not be able to consummate those dispositions, and any proceeds may not be adequate to meet any debt
service obligations then due.
21
Anti-takeover
Measures
in
Our
Charter
Documents
and
Under
State
Law
Could
Discourage
an
Acquisition
and
Thereby
Affect
the
Related
Purchase
Price.
We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. Our restated certificate of
incorporation authorizes our Board of Directors to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights),
conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. It also prohibits stockholders from
acting by written consent without the holding of a meeting. In addition, our bylaws impose certain advance notification requirements as to business that can be
brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others,
potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our
securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.
SSE
is
Subject
to
Continuing
Contingent
T
ax
Liabilities
of
Chesapeake
Energy
Corporation
(“CHK”)
F
ollowing
its
Spin-Off
from
CHK.
Under the Internal Revenue Code of 1986, as amended (the “Code”), and the related rules and regulations, each corporation that was a member of CHK’s
consolidated tax reporting group during any taxable period or portion of any taxable period ending on or before June 30, 2014, the effective time of SSE’s spin-off,
is jointly and severally liable for the federal income tax liability of the entire consolidated tax reporting group for that taxable period. SSE has entered into a tax
sharing agreement with CHK that allocates the responsibility for prior year taxes of CHK’s consolidated tax reporting group between SSE and CHK and its
subsidiaries. However, if CHK were unable to pay, SSE nevertheless could be required to pay the entire amount of such taxes.
SSE’s
Tax
Sharing
Agreement
Limits
its
Ability
to
Take
Certain
Actions
and
May
Require
SSE
to
Indemnify
CHK
for
Significant
Tax
Liabilities
Which
Cannot
be
Precisely
Quantified
at
This
Time.
Under the terms of SSE’s tax sharing agreement with CHK, SSE generally is responsible for all taxes attributable to its business, whether accruing before, on or
after the date of the spin-off, and CHK generally is responsible for any taxes arising from the spin-off or certain related transactions that are imposed on SSE, CHK
or its other subsidiaries. Although CHK generally will be responsible for any taxes arising from the spin-off, SSE would be responsible for any such taxes to the
extent such taxes result from certain actions or failures to act by SSE that occur after June 30, 2014, the effective date of the tax sharing agreement. SSE’s liabilities
under the tax sharing agreement could have a material adverse effect on us. At this time, we cannot precisely quantify the amount of liabilities SSE may have under
the tax sharing agreement and there can be no assurances as to their final amounts.
In addition, in the tax sharing agreement SSE covenanted not to take any action, or fail to take any action, after the effective date of the tax sharing agreement,
which action or failure to act is inconsistent with the spin-off qualifying under Sections 355 and 368(a)(1)(D) of the Code. As a result, SSE might determine to
continue to operate certain of its business operations for the foreseeable future even if a sale or discontinuance of such business might otherwise have been
advantageous.
In
Connection
with
SSE’s
Separation
from
CHK,
CHK
Indemnified
SSE
for
Certain
Liabilities.
However,
There
Can
Be
No
Assurance
that
the
Indemnities
Will
be
Sufficient
to
Insure
SSE
Against
the
Full
Amount
of
Such
Liabilities,
or
That
CHK’s
Ability
to
Satisfy
its
Indemnification
Obligation
Will
Not
Be
Impaired
in
the
Future.
Pursuant to the tax sharing agreement, CHK agreed to indemnify SSE for certain liabilities. However, third parties could seek to hold SSE responsible for any
of the liabilities that CHK has agreed to retain, and there can be no assurance that the indemnity from CHK will be sufficient to protect SSE against the full amount
of such liabilities, or that CHK will be able to fully satisfy its indemnification obligations. Moreover, even if SSE ultimately succeeds in recovering from CHK any
amounts for which SSE is held liable, SSE may be temporarily required to bear these losses. In addition, in certain circumstances, SSE will be prohibited from
making an indemnity claim until it first seeks an insurance recovery. If CHK is unable to satisfy its indemnification obligations, the underlying liabilities could
have a material adverse effect on our business, financial condition and results of operations.
22
We
May
Not
Be
Able
to
Utilize
a
Portion
of
SSE’s
or
Our
Net
Operating
Loss
Carryforwards
(“NOLs”)
to
Offset
Future
Taxable
Income
for
U.S.
Federal
Tax
Purposes,
Which
Could
Adversely
Affect
Our
Net
Income
and
Cash
Flows.
As of December 31, 2017, SSE had federal income tax NOLs of approximately $238.0 million, which will expire between 2034 and 2037, and, as of December
31, 2017, we had federal income tax NOLs of approximately $867.1 million, which will expire between 2035 and 2037. Utilization of these NOLs depends on
many factors, including our future taxable income, which cannot be predicted with any accuracy. In addition, Section 382 of the Code generally imposes an annual
limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under
Section 382). Determining the limitations under Section 382 is technical and highly complex. An ownership change generally occurs if one or more shareholders
(or groups of shareholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over
their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred—or were to occur—with respect to a
corporation following its recognition of an NOL, utilization of such NOL would be subject to an annual limitation under Section 382, generally determined by
multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section
382. However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the
ownership change. Any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of the NOL 20 years
after it arose.
SSE underwent an ownership change in 2016 as a result of its emergence from Chapter 11 bankruptcy proceedings, and experienced another ownership change
in 2017 as a result of its acquisition pursuant to the SSE merger, and the corresponding annual limitation associated with either of those changes in ownership could
prevent us from fully utilizing—prior to their expiration—SSE’s NOLs as of the effective time of the SSE merger. While our issuance of stock pursuant to the SSE
merger was, standing alone, insufficient to result in an ownership change with respect to us, we cannot assure you that we will not undergo an ownership change as
a result of the merger taking into account other changes in ownership of our stock occurring within the relevant three-year period described above. If we were to
undergo an ownership change, we may be prevented from fully utilizing our NOLs as of the time of the SSE merger prior to their expiration. Future changes in
stock ownership or future regulatory changes could also limit our ability to utilize SSE’s or our NOLs. To the extent we are not able to offset future taxable income
with SSE’s or our NOLs, our net income and cash flows may be adversely affected.
Item 1B. Unresolved
Staff
Comments.
None.
Item 2. Properties
Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment. We own substantially all of the equipment used in our
businesses.
Our corporate headquarters is in leased office space and is located at 10713 W. Sam Houston Parkway N., Suite 800, Houston, Texas, 77064. Our telephone
number at that address is (281) 765-7100. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000
square feet of office and storage space.
Contract Drilling Operations — Our drilling services are supported by multiple offices and yard facilities located throughout our areas of operations, including
Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada.
Pressure Pumping — Our pressure pumping services are supported by multiple offices and yard facilities located throughout our areas of operations, including
Texas, Oklahoma, Pennsylvania, Ohio and West Virginia.
Directional Drilling — Our directional drilling services are supported by multiple offices and yard facilities located throughout our areas of operations,
including Texas, Oklahoma, Pennsylvania, Colorado and Montana.
Our Oilfield Rental operations are supported by offices and yard facilities located in Texas, Oklahoma and Ohio. Our manufacture, sale and service of pipe
handling components are supported by offices and yard facilities located in western Canada and Texas. Our interests in oil and natural gas properties are primarily
located in Texas and New Mexico.
We own our administrative offices in Snyder, Texas and Oklahoma City, Oklahoma, as well as several other facilities. We also lease a number of facilities, and
we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to
meet our needs.
We incorporate by reference in response to this item the information set forth in Item 1 of this Report and the information set forth in Note 4 of the Notes to
Consolidated Financial Statements included in Item 8 of this Report.
23
Item 3. Legal
Proceedings.
On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our employees.
The EPA, OSHA and the U.S. Chemical Safety and Hazard Investigation Board are currently conducting investigations related to this accident. These
investigations are ongoing, and we are cooperating with the agencies regarding these investigations. The results of these investigations are not known at this time,
and we are unable to determine what finding they might reach, predict what actions these agencies may require or estimate what penalties, if any, they might assess.
While we are not currently party to any claims or lawsuits relating to this accident, based on the information we have available as of the date of this Report, we
believe that we have adequate insurance to cover any losses, excluding the applicable insurance deductibles and investigation-related expenses. However, if this
accident is not, or another significant accident or other event occurs that is not, fully covered by insurance or an enforceable and recoverable indemnity from a third
party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Additionally, we are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings,
either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
Item 4. Mine
Safety
Disclosure.
Not applicable.
24
PART II
Item 5. Market
for
Registrant’s
Common
Equity,
Related
Stockholder
Matters
and
Issuer
Purchases
of
Equity
Securities.
(a)
Market
Information
Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common
stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for
the periods indicated:
2017
First quarter
Second quarter
Third quarter
Fourth quarter
2016
First quarter
Second quarter
Third quarter
Fourth quarter
(b)
Holders
As of February 16, 2018, there were approximately 1,087 holders of record of our common stock.
(c)
Dividends
We paid cash dividends during the years ended December 31, 2017 and 2016 as follows:
2017
Paid on March 22, 2017
Paid on June 22, 2017
Paid on September 21, 2017
Paid on December 21, 2017
Total cash dividends
2016
Paid on March 24, 2016
Paid on June 23, 2016
Paid on September 22, 2016
Paid on December 22, 2016
Total cash dividends
High
Low
29.76 $
25.75
21.74
23.26
18.75 $
22.12
22.66
29.56
22.83
19.06
14.83
17.24
10.94
16.06
17.61
20.79
Per Share
Total
(in thousands)
0.02 $
0.02
0.02
0.02
0.08 $
0.10 $
0.02
0.02
0.02
0.16 $
3,326
4,269
4,271
4,449
16,315
14,712
2,953
2,953
2,961
23,579
$
$
$
$
$
$
On February 7, 2018, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on March 22, 2018 to
holders of record as of March 8, 2018. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and
will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors.
25
(d)
Issuer
Purchases
of
Equity
Securities
The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2017.
Period Covered
October 2017
November 2017
December 2017 (2)
Total
Total Number of
Shares Purchased
Average Price
Paid per Share
—
—
21.98
— $
— $
26,640 $
26,640
Total Number of
Shares (or Units)
Purchased as Part
of Publicly
Announced Plans
or Programs
Approximate
Dollar Value of
Shares That May
Yet Be Purchased
Under the Plans or
Programs (in
thousands)(1)
— $
— $
— $
— $
186,544
186,544
186,544
186,544
(1)
On September 9, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our
common stock in open market or privately negotiated transactions. All purchases executed to date have been through open market transactions. Purchases
under the program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any
time without prior notice. Shares of stock purchased under the plan are held as treasury shares. There is no expiration date associated with the buyback
program.
(2) We withheld 26,640 shares in December 2017 with respect to exercises of stock options by directors. These shares were acquired at fair market value
pursuant to the terms of the 2014 Plan and not pursuant to the stock buyback program.
(e)
Performance
Graph
The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2012 through December 31, 2017,
with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group
determined by us. We changed our peer group in 2017 to align with the peer group used by the compensation committee of our board of directors. Our new peer
group consisted of Basic Energy Services, Inc., Diamond Offshore Drilling Inc., Ensco plc., Forum Energy Technologies, Inc., Halliburton Company, Helmerich &
Payne, Inc., Nabors Industries, Ltd., National Oilwell Varco, Inc., Noble Corporation plc., Oceaneering International, Oil States International Inc., Precision
Drilling Corporation, Rowan Companies plc., Superior Energy Services, Inc., TechnipFMC plc, Transocean Ltd., Unit Corp. and Weatherford International plc.
Our old peer group consisted of Atwood Oceanics Inc., Basic Energy Services, Inc., Diamond Offshore Drilling Inc., Ensco plc., Forum Energy Technologies, Inc.,
TechnipFMC plc, Helmerich & Payne, Inc., Nabors Industries, Ltd., Noble Corp., Oceaneering International, Oil States International Inc., Precision Drilling
Corporation, Parker Drilling Company, Rowan Companies Inc., Superior Energy Services, Inc., Transocean Ltd., Unit Corp. and Weatherford International Ltd.
26
The graph assumes investment of $100 on December 31, 2012 and reinvestment of all dividends.
Company/Index
Patterson-UTI Energy, Inc.
S&P 500 Stock Index
S&P MidCap Index
Oilfield Service Index
New Peer Group Index
Old Peer Group Index
Fiscal Year Ended December 31,
2012
($)
100.00
100.00
100.00
100.00
100.00
100.00
2013
($)
137.15
132.39
133.50
129.58
124.21
118.73
2014
($)
2015
($)
91.31
150.51
146.54
99.08
92.02
79.07
85.02
152.59
143.35
75.91
63.43
51.77
2016
($)
153.04
170.84
173.08
90.32
80.98
57.42
2017
($)
131.30
208.14
201.20
74.78
68.81
43.52
The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting
material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act.
27
Item 6. Selected
Financial
Data.
Our selected consolidated financial data as of December 31, 2017, 2016, 2015, 2014 and 2013, and for each of the five years in the period ended December 31,
2017, should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated
Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. The table below includes the results of operations of SSE
since the merger date of April 20, 2017 and the results of operations of MS Directional since the acquisition date of October 11, 2017.
Statement of Operations Data:
Operating revenues:
Contract drilling
Pressure pumping
Directional drilling
Other
Total
Operating costs and expenses:
Contract drilling
Pressure pumping
Directional drilling
Other
Depreciation, depletion, amortization and impairment
Impairment of goodwill
Selling, general and administrative
Merger and integration expenses
Other operating (income) expense, net
Total
Operating income (loss)
Other expense
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Cash dividends per common share
Weighted average number of common shares outstanding:
Basic
Diluted
Balance Sheet Data:
Total assets
Borrowings under line of credit
Other long-term debt
Stockholders’ equity
Working capital
$
$
$
$
$
$
2017
1,040,033 $
1,200,311
45,580
70,760
2,356,684
667,105
966,835
32,172
51,428
783,341
—
105,847
74,451
(31,957)
2,649,222
(292,538)
(35,263)
(327,801)
(333,711)
5,910 $
2016
Year Ended December 31,
2015
(In thousands, except per share amounts)
2014
543,663 $
354,070
—
18,133
915,866
1,153,892 $
712,454
—
24,931
1,891,277
1,838,830 $
1,293,265
—
50,196
3,182,291
305,804
334,588
—
8,384
668,434
—
69,205
—
(14,323)
1,372,092
(456,226)
(39,970)
(496,196)
(177,562)
(318,634) $
608,848
612,021
—
11,500
864,759
124,561
74,913
—
1,647
2,298,249
(406,972)
(35,477)
(442,449)
(147,963)
(294,486) $
1,066,659
1,036,310
—
13,102
718,730
—
80,145
—
(15,781)
2,899,165
283,126
(28,843)
254,283
91,619
162,664 $
0.03 $
0.03 $
(2.18) $
(2.18) $
(2.00) $
(2.00) $
1.12 $
1.11 $
0.08 $
0.16 $
0.40 $
0.40 $
2013
1,679,611
979,166
—
57,257
2,716,034
968,754
744,243
—
12,909
597,469
—
73,852
—
(3,384)
2,393,843
322,191
(25,750)
296,441
108,432
188,009
1.29
1.28
0.20
198,447
199,882
146,178
146,178
145,416
145,416
144,066
145,376
144,356
145,303
5,758,856 $
268,000
598,783
3,982,493
200,605
3,772,291 $
—
598,437
2,248,724
(17,933)
4,465,048 $
—
787,900
2,561,131
178,887
5,353,837 $
303,000
667,029
2,905,810
340,816
4,650,423
—
678,873
2,755,997
454,498
28
Item 7. Management’s
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations
Recent Developments — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028
initially guaranteed on a senior unsecured basis by certain of our subsidiaries. We used $239 million of the net proceeds from the sale to repay amounts
outstanding under our revolving credit facility. We intend to use the remainder of the net proceeds for general corporate purposes.
On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional. The aggregate consideration paid by
us consisted of $69.8 million in cash and approximately 8.8 million shares of our common stock. Based on the closing price of our common stock on the closing
date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.
MS Directional is a leading directional drilling services company in the United States, with operations in most major producing onshore oil and gas basins. MS
Directional provides a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying,
measurement while drilling, and wireline steering tools. Operational and financial data in the discussion and analysis below includes the results of operations of the
MS Directional business since October 11, 2017.
On December 12, 2016, we entered into the merger agreement with SSE. On April 20, 2017, pursuant to the merger agreement, a subsidiary of ours was
merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly-owned subsidiaries. Pursuant to the terms of the merger agreement,
we acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of our common stock. Concurrent
with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of our common stock on April 20,
2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following the SSE
merger, SSE was merged with and into our newly-formed subsidiary SSE LLC, with SSE LLC continuing as the surviving entity and one of our wholly-owned
subsidiaries.
Through the SSE merger, we acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® rigs. Additionally, through the SSE merger, we
acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas. The oilfield rentals business acquired
through the SSE merger has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas
drilling, completion and workover activities. Operational and financial data in the discussion and analysis below includes the results of operations of the SSE
businesses since April 20, 2017.
Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2015, 2016 and 2017 are as follows:
2015:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
2016:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
2017:
Average oil price per Bbl (1)
Average rigs operating per day - U.S. (2)
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
$
$
$
48.54 $
165
33.18 $
71
51.77 $
81
57.85 $
122
45.41 $
55
48.24 $
145
46.42 $
105
44.85 $
60
48.16 $
159
41.96
88
49.15
66
55.37
159
(1)
(2)
The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.
The closing price of oil was as high as $107.95 per barrel in June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of
$26.19 in February 2016. Oil and natural gas prices have modestly recovered from the lows experienced in the first quarter of 2016. Oil prices averaged $55.37
per barrel in the fourth quarter of 2017.
Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has improved since the second quarter of
2016. Our average rig count in the United States was 159 rigs for both the third and fourth quarter of 2017, with the third quarter of 2017 being the first quarter
with a full quarter contribution from the rigs acquired in the SSE merger. Our rig count in the United States at December 31, 2017 was 163 rigs. Term contracts
have supported our operating rig count during the last three years. Based on contracts currently in place, we expect an average of 96 rigs operating under term
contracts during the first quarter of 2018 and an average of 67 rigs operating under term contracts throughout 2018.
29
Activity levels in our pressure pumping business also improved during 2017, especially in the Permian Basin. We reactivated two frac spreads during the third
quarter, and one additional frac spread during the fourth quarter. With the addition of these three frac spreads, we exited 2017 with 23 active frac spreads or
approximately 1.25 million active fracturing horsepower.
Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest
fleets of land-based drilling rigs and a large fleet of pressure pumping equipment. Our contract drilling business operates in the continental United States and
western Canada, and we are pursuing contract drilling opportunities outside of North America. Our pressure pumping business operates primarily in Texas and the
Mid-Continent and Appalachian regions. We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas
basins in the United States. We have other operations through which we provide oilfield rental tools in select markets in the United States, and we also
manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets. In addition, we own and
invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by expanding our areas of operation and
improving the capabilities of our drilling fleet during the last several years. As of December 31, 2017, our rig fleet included 199 APEX ® rigs.
In connection with the development of horizontal shale and other unconventional resource plays, in the last five years we have added equipment to perform
service intensive fracturing jobs. As of December 31, 2017, we had approximately 1.6 million horsepower in our pressure pumping fleet. In recent years, the
industry-wide addition of new pressure pumping equipment to the marketplace and lower oil and natural gas prices have led to an excess supply of pressure
pumping equipment in North America.
We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or
more. Our contract drilling backlog as of December 31, 2017 and 2016 was $544 million and $417 million, respectively. Approximately 19% of the total contract
drilling backlog at December 31, 2017 is reasonably expected to remain after 2018. We generally calculate our backlog by multiplying the dayrate under our term
drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization,
demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving
or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, our term drilling contracts are generally 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. For
contracts that we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period we
expect to receive the lower rate. See “Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Continue to Decline and May Not
Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.”
Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices,
the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods
when these commodity prices deteriorate, the demand for our services generally weakens, and we experience downward pressure on pricing for our services. We
are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather and various other factors that could materially
adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report.
For the three years ended December 31, 2017, our operating revenues consisted of the following (dollars in thousands):
Contract drilling
Pressure pumping
Directional drilling
Other
2017
1,040,033
1,200,311
45,580
70,760
2,356,684
$
$
44.1% $
50.9%
1.9%
3.1%
100.0% $
2016
543,663
354,070
—
18,133
915,866
59.4% $
38.7%
—%
1.9%
100.0% $
2015
1,153,892
712,454
—
24,931
1,891,277
61.0%
37.7%
—%
1.3%
100.0%
Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average
revenue per operating day. During 2017, our average number of rigs operating was 136 in the United States and two in Canada, compared to 63 in the United
States and two in Canada in 2016, and 120 in the United States and four in Canada in 2015. Our average rig revenue per operating day was $20,620 in 2017,
compared to $23,040 in 2016 and $25,560 in 2015.
30
Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide
proppant and other materials ) of those jobs , which is reflected in our average revenue per fracturing job. We completed 622 fracturing jobs during 2017 compared
to 352 fracturing jobs in 2016 and 610 fracturing jobs in 2015. Our average revenue per fracturing job was $1.894 million in 2017 compared to $982,560 in 2016
and $1.118 million in 2015.
For the three years ended December 31, 2017, our operating income (loss) consisted of the following (dollars in thousands):
Contract drilling
Pressure pumping
Directional drilling
Other
Corporate
2017
$ (171,897)
21,028
(21)
(20,813)
(120,835)
$ (292,538)
2016
58.8% $ (235,858)
(176,628)
(7.2)%
—%
—
(3,391)
7.1%
41.3%
(40,349)
100.0% $ (456,226)
51.7% $
38.7%
—%
0.7%
8.9%
2015
(78,970)
(254,998)
—
(14,269)
(58,735)
100.0% $ (406,972)
19.4%
62.7%
—%
3.5%
14.4%
100.0%
Discussion of our operating income (loss) follows in the “Results of Operations” section of Management’s Discussion and Analysis of Financial Condition and
Results of Operations.
On December 22, 2017, significant U.S. tax law changes were enacted (“tax reform”). Tax reform reduces the U.S. federal corporate tax rate from 35% to 21%
beginning in 2018, requires companies to pay a one-time transition tax on foreign earnings that were previously tax deferred, creates new taxes on future foreign
earnings, places a limitation on the tax deductibility of interest expense, accelerates the expensing of certain business assets, and reduces the amount of executive
pay that will be tax deductible, among other changes. At December 31, 2017, we had not completed our accounting for the tax effects of the tax reform, however,
in certain cases, we have made a reasonable estimate of the effects on our existing deferred tax balances and the one-time transition tax. For the items for which we
were able to determine a reasonable estimate, we recognized a provisional amount in accordance with Staff Accounting Bulletin (SAB) 118 of approximately $219
million of tax benefit as a result of tax reform, which is included as a component of income tax expense from continuing operations. See Note 12 of Notes to
Consolidated Financial Statements contained in this Report for additional information related to the impact of tax reform.
The improvement in demand for our services and the income tax rate change resulted in consolidated net income of $5.9 million for 2017 compared to a
consolidated net loss of $319 million for 2016 and a consolidated net loss of $294 million for 2015.
Results of Operations
Comparison
of
the
years
ended
December
31,
2017
and
2016
The following tables summarize results of operations by business segment for the years ended December 31, 2017 and 2016:
Contract Drilling
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, amortization and impairment
Operating loss
Operating days
Average revenue per operating day
Average direct operating costs per operating day
Average margin per operating day (1)
Average rigs operating
Capital expenditures
2017
Year Ended December 31,
2016
(Dollars in thousands)
% Change
$
$
$
$
$
$
1,040,033 $
667,105
372,928
5,934
538,891
(171,897) $
50,427
20.62 $
13.23 $
7.40 $
138.2
354,425 $
543,663
305,804
237,859
5,743
467,974
(235,858)
23,596
23.04
12.96
10.08
64.5
72,508
91.3%
118.1%
56.8%
3.3%
15.2%
(27.1)%
113.7%
(10.5)%
2.1%
(26.6)%
114.3%
388.8%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative
expenses. Average margin per operating day is defined as margin divided by operating days.
31
The demand for our contract drilling services is impacted by the market price of oil and natural gas. The average market price of oil and natural gas for each of
the fiscal quarters and full year in 2017 and 2016 follows:
2017:
Average oil price per Bbl (1)
Average natural gas price per Mcf (2)
2016:
Average oil price per Bbl (1)
Average natural gas price per Mcf (2)
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
Year
$
$
$
$
51.77 $
3.01 $
33.18 $
2.00 $
48.24 $
3.08 $
45.41 $
2.14 $
48.16 $
2.95 $
44.85 $
2.88 $
55.37 $
2.90 $
49.15 $
3.04 $
50.88
2.99
43.15
2.51
(1)
(2)
The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration.
Revenues and direct operating costs increased primarily due to an increase in operating days. Operating days and average rigs operating increased due to a
recovery in the oil and natural gas industry and the rigs acquired in the SSE merger. Depreciation, amortization and impairment increased due to the additional
SSE assets and due to a $29.0 million impairment from the write-down of drilling equipment with no continuing utility as a result of the upgrade of certain rigs to
super-spec capability. There was no similar charge in 2016. Average revenue per operating day decreased during 2017 due to a reduction in early termination
revenue and the expiration of higher day rate, legacy long-term rig contracts. Early termination revenue in 2017 was $4.9 million, compared to $24.6 million in
2016. Average direct operating costs per operating day increased as a result of a reduction in the proportion of rigs on standby and an increase in rig reactivation
expenses. Capital expenditures increased due to upgrading rigs to super-spec capability, building a new rig, higher maintenance capital expenditures and other
general property and equipment upgrades.
Pressure Pumping
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, amortization and impairment
Operating income (loss)
Fracturing jobs
Other jobs
Total jobs
Average revenue per fracturing job
Average revenue per other job
Average revenue per total job
Average direct operating costs per total job
Average margin per total job (1)
Margin as a percentage of revenues (1)
Capital expenditures
$
$
$
$
$
$
$
$
2017
1,200,311
966,835
233,476
14,442
198,006
21,028
622
1,262
1,884
1,894.40
17.43
637.11
513.18
123.93
$
Year Ended December 31,
2016
(Dollars in thousands)
354,070
334,588
19,482
11,238
184,872
(176,628)
$
352
799
1,151
982.56
10.28
307.62
290.69
16.93
$
$
$
$
$
19.5%
171,436
$
5.5%
39,584
% Change
239.0%
189.0%
1,098.4%
28.5%
7.1%
NA
76.7%
57.9%
63.7%
92.8%
69.6%
107.1%
76.5%
632.0%
254.5%
333.1%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative
expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by
revenues.
32
Revenues and direct operating costs in creased in 201 7 primarily due to a n in crease in the number and size of fracturing jobs. T he total number of jobs in
creased as a result of the SSE merger and a recovery in the oil and natural gas industry. Average revenue per job increased due to improved pricing and an
increase in the size of the jobs. Average direct operating costs per total job increased primarily due to the increase in the size of the jo bs. Selling, general and
administrative expenses increased due to the increase in organizational size and activity as a result of the SSE merger . The increase in capital expenditures was
primarily due to higher maintenance capital expenditures as a result of higher activity and investments to reactivate frac spreads.
Directional Drilling
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation and amortization
Operating loss
Capital expenditures
2017
$
$
$
Year Ended December 31,
2016
(Dollars in thousands)
—
—
—
—
—
—
45,580 $
32,172
13,408
4,082
9,347
(21) $
7,795 $
—
% Change
NA
NA
NA
NA
NA
NA
NA
(1) Margin is defined as revenues less direct operating costs and excludes depreciation and amortization and selling, general and administrative expenses.
Our directional drilling segment originated with the October 11, 2017 acquisition of MS Directional, and consequently we have no results for the prior year in
this segment.
Other Operations
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, depletion and impairment
Operating loss
Capital expenditures
2017
Year Ended December 31,
2016
(Dollars in thousands)
% Change
$
$
$
70,760 $
51,428
19,332
10,743
29,402
(20,813) $
31,547 $
18,133
8,384
9,749
3,026
10,114
(3,391)
6,116
290.2%
513.4%
98.3%
255.0%
190.7%
513.8%
415.8%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, depletion and impairment and selling, general and administrative
expenses.
Revenues, direct operating costs, selling, general and administrative expense and depreciation expense from other operations increased primarily as a result of
the inclusion of our oilfield rental business acquired in the SSE merger on April 20, 2017 and our pipe handling components and related technology business
acquired in September 2016. The increase in capital expenditures was primarily due to investments in the oilfield rental business and in oil and natural gas working
interests.
Corporate
Selling, general and administrative
Merger and integration expenses
Depreciation
Other operating (income) expense, net
Net gain on asset disposals
Other, including legal settlements, net of insurance reimbursements
Other operating income, net
Interest income
Interest expense
Other income
Capital expenditures
2017
Year Ended December 31,
2016
(Dollars in thousands)
% Change
$
$
$
$
$
$
$
$
$
70,646 $
74,451 $
7,695 $
(33,510) $
1,553
(31,957) $
1,866 $
37,472 $
343 $
1,884 $
49,198
—
5,474
(14,771)
448
(14,323)
327
40,366
69
1,591
43.6%
NA
40.6%
126.9%
246.7%
123.1%
470.6%
(7.2)%
397.1%
18.4%
33
Selling, general and administration expense increased in 2017 primarily due to the personnel added as a result of the SSE merger . The merger and integration
expenses incurred in 2017 are related to the SSE merger and MS Directional acquisition . Other operating income includes net gains associated with the disposal
of assets. Accordingly, the re lated gains or losses have been excluded from th e results of specific segments. The 2017 period includes a gain of $11.2 million
related to the sale of real estate and $8.4 million from the sale of certain oil and gas properties . Interest income increased due to our investment of the proceeds
from our stock offering in the first quarter of 2017 prior to utilizing those proceeds to repay SSE indebtedness . Interest expense decreased primarily due to lower
debt outstanding during 2017 compared to 2016 .
Comparison
of
the
years
ended
December
31,
2016
and
2015
The following tables summarize results of operations by business segment for the years ended December 31, 2016 and 2015:
Contract Drilling
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, amortization and impairment
Operating loss
Operating days
Average revenue per operating day
Average direct operating costs per operating day
Average margin per operating day (1)
Average rigs operating
Capital expenditures
2016
Year Ended December 31,
2015
(Dollars in thousands)
% Change
$
$
$
$
$
$
$
543,663 $
305,804
237,859
5,743
467,974
(235,858) $
23,596
23.04 $
12.96 $
10.08 $
64.5 $
72,508 $
1,153,892
608,848
545,044
5,580
618,434
(78,970)
45,142
25.56
13.49
12.07
123.7
527,054
(52.9)%
(49.8)%
(56.4)%
2.9%
(24.3)%
198.7%
(47.7)%
(9.9)%
(3.9)%
(16.5)%
(47.9)%
(86.2)%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative
expenses. Average margin per operating day is defined as margin divided by operating days.
The demand for our contract drilling services is impacted by the market price of oil and natural gas. The reactivation and construction of new land drilling rigs
in the United States in recent years contributed to an excess capacity of land drilling rigs compared to demand. Customer demand shifted away from mechanically
powered drilling rigs to electric powered drilling rigs, reducing the utilization rates of our mechanically powered drilling rigs. The average market price of oil and
natural gas for each of the fiscal quarters and full year in 2016 and 2015 follows:
2016:
Average oil price per Bbl (1)
Average natural gas price per Mcf (2)
2015
Average oil price per Bbl (1)
Average natural gas price per Mcf (2)
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
Year
$
$
$
$
33.18 $
2.00 $
48.54 $
2.90 $
45.41 $
2.14 $
57.85 $
2.75 $
44.85 $
2.88 $
46.42 $
2.76 $
49.15 $
3.04 $
41.96 $
2.12 $
43.15
2.51
48.69
2.63
(1)
(2)
The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration.
The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration.
The decreases in revenues and direct operating costs primarily result from the decrease in the number of rigs operating. Average revenue per operating day and
average margin per operating day were higher in 2015 primarily due to higher average dayrates and early termination revenues of approximately $69.4
million. Early termination revenues were approximately $24.6 million in 2016. Depreciation, amortization and impairment expense for 2015 included a charge of
$131 million related to the write-down of drilling equipment primarily related to mechanical rigs and spare mechanical rig components. There were no similar
charges in 2016. Capital expenditures were significantly lower as no new rigs were added to the fleet in 2016 and drilling activity was lower, which required less
maintenance capital.
34
Pressure Pumping
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, amortization and impairment
Impairment of goodwill
Operating loss
Fracturing jobs
Other jobs
Total jobs
Average revenue per fracturing job
Average revenue per other job
Average revenue per total job
Average direct operating costs per total job
Average margin per total job (1)
Margin as a percentage of revenues (1)
Capital expenditures and acquisitions
$
$
$
$
$
$
$
$
2016
354,070
334,588
19,482
11,238
184,872
-
$
Year Ended December 31,
2015
(Dollars in thousands)
712,454
612,021
100,433
16,318
214,552
124,561
(254,998)
(176,628) $
352
799
1,151
982.56
10.28
307.62
290.69
16.93
$
$
$
$
$
5.5%
39,584
$
610
2,080
2,690
1,117.95
14.66
264.85
227.52
37.34
14.1%
197,577
% Change
(50.3)%
(45.3)%
(80.6)%
(31.1)%
(13.8)%
NA
(30.7)%
(42.3)%
(61.6)%
(57.2)%
(12.1)%
(29.9)%
16.1%
27.8%
(54.7)%
(61.0)%
(80.0)%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative
expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by
revenues.
Revenues and direct operating costs decreased in 2016 as a result of declines in both activity and pricing. Average revenue per fracturing job and average
revenue per other job decreased due to market-related pricing constraints. Average revenue per total job and average direct operating costs per total job increased
as a result of a shift in the job mix toward fracturing jobs. The total number of jobs decreased as a result of the downturn in the oil and natural gas industry. Lower
selling, general and administrative expense in 2016 reflects lower personnel costs due to headcount reductions. Depreciation, amortization and impairment expense
for 2015 includes a charge of $22.0 million related to the write-down of pressure pumping equipment and closed facilities. There were no similar charges in
2016. In addition, all of the goodwill associated with our pressure pumping business was impaired during 2015.
Other Operations
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, depletion and impairment
Operating loss
Capital expenditures
2016
Year Ended December 31,
2015
(Dollars in thousands)
% Change
$
$
$
18,133 $
8,384
9,749
3,026
10,114
(3,391) $
6,116 $
24,931
11,500
13,431
1,399
26,301
(14,269)
16,625
(27.3)%
(27.1)%
(27.4)%
116.3%
(61.5)%
(76.2)%
(63.2)%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, depletion and impairment and selling, general and administrative
expenses.
Revenues from other operations decreased as a result of lower production and lower oil prices which resulted in lower revenues from our oil and natural gas
working interests. Direct operating costs include a reduction in production taxes due to lower revenues. Selling, general and administrative expense increased
from 2015 as the 2016 results include costs related to our drilling technology service business which was acquired in September 2016. Depreciation, depletion and
impairment expense in 2016 includes approximately $2.8 million of oil and natural gas property impairments as compared to approximately $10.7 million of oil
and natural gas property impairments in 2015.
35
Corporate
Selling, general and administrative
Depreciation
Other operating (income) expense, net
Net gain on asset disposals
Legal settlements, net of insurance reimbursements
Other operating (income) expense, net
Interest income
Interest expense
Other income
Capital expenditures
2016
49,198
5,474
(14,771)
448
(14,323)
327
40,366
69
1,591
Year Ended December 31,
2015
(Dollars in thousands)
51,616
$
5,472
$
$
$
$
$
$
$
(10,613)
12,260
1,647
964
36,475
34
2,520
$
$
$
$
$
$
$
$
% Change
(4.7)%
0.0%
39.2%
(96.3)%
NA
(66.1)%
10.7%
102.9%
(36.9)%
Lower selling, general and administrative expense reflects lower personnel costs due to headcount reductions. Other operating (income) expense, net includes
net gains associated with the disposal of assets related to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses
have been excluded from the results of specific segments. Interest expense increased primarily due to lower capitalized interest, as we reduced our level of capital
expenditures in 2016. In addition, we repaid the entire outstanding principal amount of our bank term loans. As a result, we expensed $1.4 million of previously
unamortized debt issuance costs in 2016 related to these bank term loans.
Income Taxes
Loss before income taxes
Income tax benefit
Effective tax rate
The effective tax rate is a result of a federal rate of 35.0% adjusted as follows:
Statutory tax rate
State income taxes - net of the federal income tax benefit
Permanent differences
One-time tax effects of tax reform
Share-based payments
Acquisition related differences
Other differences, net
Effective tax rate
2017
Year Ended December 31,
2016
(Dollars in thousands)
2015
$
$
(327,801) $
(333,711) $
101.8%
(496,196) $
(177,562) $
35.8%
(442,449)
(147,963)
33.4%
2017
2016
2015
35.0%
1.9
(1.3)
66.7
3.6
(3.3)
(0.8)
101.8%
35.0%
2.0
(0.1)
—
—
—
(1.1)
35.8%
35.0%
2.1
(1.3)
—
—
—
(2.4)
33.4%
The effective tax rate increased by approximately 66.0% to 101.8% for 2017 compared to 2016, primarily due to a 66.7% increase related to the tax reform
enacted on December 22, 2017 and a 3.6% increase for excess tax benefits from employee stock compensation deductions. These increases were partially offset by
a 3.3% decrease in the effective tax rate for acquisitions that resulted in the revaluation of deferred tax assets and liabilities at the new state tax rates at which they
are expected to reverse. The lower 2015 effective rate is primarily related to the impact of goodwill impairment charges in 2015 along with an adjustment to our
deferred tax liability associated with the 2010 conversion of our Canadian operations to a controlled foreign corporation.
36
Tax reform reduces the U . S . federal corporate tax rate from 35% to 21% beginning in 2018, requires companies to pay a one-time transition tax on foreign
earnings that were previously tax deferred, creates new taxes on future foreign earnings, places a new limitation on the tax deduc tibility of interest expense,
accelerates the expensing of certain business assets, and reduces the amount of executive pay that will be tax deductible, among other changes. Based on a reduced
US federal corporate tax rate of 21% from tax reform, we remea sured certain deferred tax assets and liabilities at the tax rates at which they are expected to reverse
in the future. Due to the limited time to consider tax reform and its various interpretations, we are still analyzing and refining our calculations, w hich could
potentially affect the measurement of these balances or give rise to new deferred tax amounts, however, in certain cases, we have made a reasonable estimate of the
effects on our existing deferred tax balances and the one-time transition tax. F or the items for which we were able to determine a reasonable estimate, we
recognized a provisional amount , in accordance with Staff Accounting Bulletin (SAB) 118 , of approximately $ 219 million of tax benefit , which is included as a
component of income tax expense from continuing operations resulting in the above impact to our 2017 effective tax rate . See Note 1 2 of Notes to Consolidated
Financial Statements contained in this Report for additional information related to th e impact of tax reform .
Prior to tax reform, we had elected to permanently reinvest unremitted earnings in Canada effective January 1, 2010, and we intended to do so for the
foreseeable future. As a result, no deferred U.S. federal or state income taxes had been provided on such unremitted foreign earnings. With the enactment of tax
reform, there is a new territorial tax system that provides for a 100% dividends received deduction on future earnings, if remitted. However, we will need to
continue to evaluate our reinvestment intentions on future earnings and any other residual basis differences in order to determine whether we can continue to assert
indefinite reinvestment or whether we will be required to provide for additional taxes that would be due on future earnings if remitted, such as foreign withholding
taxes or state and local taxes. We will also need to determine whether we will be required to provide for additional taxes on any other outside basis differences in
our foreign operations. Due to the limited time to consider these provisions, we are still evaluating how tax reform will affect our existing accounting position to
indefinitely reinvest unremitted foreign earnings. We will continue to assert permanent reinvestment with respect to future unremitted earnings and have not
recorded any deferred federal or state income taxes that would be provided on future unremitted earnings. We will finalize our intentions on whether we will
permanently reinvest our foreign unremitted earnings within the measurement period provided under SAB 118.
We record deferred federal income taxes based primarily on the temporary differences between the book and tax bases of our assets and liabilities. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be
settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We
recognized a deferred tax benefit of approximately $330 million in 2017, $152 million in 2016 and $100 million in 2015.
In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-09, “Compensation-Stock Compensation”
(ASU 2016-09). The new standard was effective for us on January 1, 2017. Among other provisions, the new standard requires that excess tax benefits and tax
deficiencies that arise upon vesting or exercise of share-based payments be recognized as income tax benefits and expenses in the income statement. Previously,
such amounts were recorded to additional paid-in-capital. This aspect of the new guidance was required to be adopted prospectively. Our effective income tax rate
for the year ended December 31, 2017 includes approximately $12 million of excess tax benefits from share-based compensation awards that vested or were
exercised during the period.
During 2017, we had significant merger and acquisition activity. Based on this activity, we evaluated our overall state deferred tax rate, resulting in a slightly
increased rate. We remeasured certain deferred tax assets and liabilities at the tax rates at which they are expected to reverse in the future and recorded additional
taxes of approximately $11 million, resulting in the above impact to the 2017 effective tax rate.
Liquidity and Capital Resources
Our liquidity as of December 31, 2017 included approximately $201 million in working capital, including $42.8 million of cash and cash equivalents, and
$227 million available under our revolving credit facility.
We believe our current liquidity, together with cash expected to be generated from operations in 2018, should provide us with sufficient ability to fund our
current plans to maintain and make improvements to our existing equipment, service our debt and pay cash dividends for at least the next 12 months. If we pursue
opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from
operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such
capital will be available on reasonable terms, if at all.
As of December 31, 2017, we had working capital of $201 million, including cash and cash equivalents of $42.8 million, compared to negative working capital
of $17.9 million, including cash and cash equivalents of $35.2 million, at December 31, 2016.
37
During 2017, our sources of cash flow included:
•
•
•
•
$301 million from operating activities,
$60.9 million in proceeds from the disposal of property and equipment,
$268 million in net borrowings under our revolving credit facility, and
$472 million from net proceeds from common stock issuance.
During 2017, we used $502 million, net of cash acquired, for the acquisitions of SSE and MS Directional, $16.3 million to pay dividends on our common stock,
$6.8 million to acquire shares of our common stock and $567 million:
•
•
•
to make capital expenditures for the acquisition, betterment and refurbishment of drilling rigs and pressure pumping equipment,
to acquire and procure equipment and facilities to support our drilling, pressure pumping, directional drilling, oilfield rental and manufacturing operations,
and
to fund investments in oil and natural gas properties on a non-operating working interest basis.
We paid cash dividends during the year ended December 31, 2017 as follows:
Paid on March 22, 2017
Paid on June 22, 2017
Paid on September 21, 2017
Paid on December 21, 2017
Total cash dividends
Per Share
Total
(in thousands)
0.02 $
0.02
0.02
0.02
0.08 $
3,326
4,269
4,271
4,449
16,315
$
$
On February 7, 2018, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on March 22, 2018 to
holders of record as of March 8, 2018. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and
will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors.
On September 6, 2013, our Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of our common stock in open
market or privately negotiated transactions. All purchases executed to date have been through open market transactions. Purchases under the program are made at
management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice. Shares of
stock purchased under the plan are held as treasury shares. There is no expiration date associated with the buyback program. As of December 31, 2017, we had
remaining authorization to purchase approximately $187 million of our outstanding common stock under the 2013 stock buyback program.
We acquired shares of stock from directors in 2017 and 2016 and from employees during 2017, 2016 and 2015 that are accounted for as treasury stock. Certain
of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was acquired to satisfy
payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market
value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan and not pursuant to the stock
buyback program.
Treasury stock acquisitions during the years ended December 31, 2017, 2016 and 2015 were as follows (dollars in thousands):
Treasury shares at beginning of period
Purchases pursuant to 2013 stock buyback program
Acquisitions pursuant to long-term incentive plan
Treasury shares at end of period
2017
Shares
43,392,617 $
5,503
404,491
43,802,611 $
Cost
911,094
109
7,508
918,711
2016
Shares
43,207,240 $
8,488
176,889
43,392,617 $
Cost
907,045
183
3,866
911,094
2015
Shares
42,818,585 $
8,618
380,037
43,207,240 $
Cost
899,035
180
7,830
907,045
2012 Credit Agreement — On September 27, 2012, we entered into a Credit Agreement (“Base Credit Agreement”). The Base Credit Agreement (as amended,
the “Credit Agreement”) is a committed senior unsecured credit facility that includes a revolving credit facility.
38
On July 8, 2016, we entered into Amendment No. 2 to Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement to, among other
things, make borrowings under the revolving credit facility subject to a borrowing base calculated by reference to our and certai n of our subsidiaries’ eligible
equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains a letter of credit
facility that is limited to $50 million and a swing line facility th at is limited to $20 million, in each case outstanding at any time. The maturity date under the Base
Credit Agreement was September 27, 2017 for the revolving credit facility; however, Amendment No. 2 extended the maturity date of $357.9 million in revolv ing
credit commitments of certain lenders to March 27, 2019. On January 17, 2017, we entered into Amendment No. 3 to Credit Agreement, which amended the Credit
Agreement by restating the definition of Consolidated EBITDA to provide for the add-back of tra nsaction expenses related to the SSE merger. On January 24,
2017, we entered into an agreement with certain lenders under our revolving credit facility to increase the aggregate commitments under our revolving credit
facility to approximately $595.8 milli on, subject to the satisfaction of certain conditions. The aggregate commitment increase became effective on April 20, 2017
upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20, 2017, we entere d into Amendment No. 4 to
Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to be incurred under our credit facility and increased the
amount of the accordion feature of our revolving credit facility to permit aggregate commitments to be increased to an amount not to exceed $700 million (subject
to satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). On April 20, 2017, we also entered into an
additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit facility (after
giving effect to both commitment increases) increased to $632 million through September 2017 and t o $490 million through March 2019. On October 27, 2017, we
entered into an additional commitment increase agreement with certain of our lenders pursuant to which total commitments available under our revolving credit
facility increased to $500 million thro ugh March 27, 2019.
Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by
reference only to the base rate. Until September 27, 2017, the applicable margin on LIBOR rate loans varied from 2.75% to 3.25% and the applicable margin on
base rate loans varied from 1.75% to 2.25%, in each case determined based upon our debt to capitalization ratio. Beginning September 27, 2017, the applicable
margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based
on our excess availability under the revolving credit facility. As of December 31, 2017, the applicable margin on LIBOR rate loans was 3.50% and the applicable
margin on base rate loans was 2.50%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available
to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the revolving credit facility is 0.50%.
Each of our domestic subsidiaries unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and ours arising under
the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than
equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million. Such guarantees
also cover our or any of our subsidiaries arising under any interest rate swap contract with any person while such person is a lender or an affiliate of a lender under
the Credit Agreement.
The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 40%. The Credit
Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus
consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit our interest
coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of
earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in
compliance with these covenants at December 31, 2017.
The Credit Agreement limits our ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since
September 27, 2012 is above 20% of our total consolidated book value of the assets on a pro forma basis, we will not be able to make such investment. The Credit
Agreement also restricts our ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted
payments if before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in the Credit
Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if our consolidated cash balance, subject to certain exclusions, is more than
$100 million at the end of the day on which a borrowing is made, we can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and
the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, we must repay such unused proceeds on the fourth
business day following such borrowings.
The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and
covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.
39
Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational
covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of
default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement,
(ii) accelerate and re quire us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to our
insolvency and bankruptcy, such acceleration is automatic), and (iii) require us to cash collateralize any outstanding le tters of credit.
As of December 31, 2017, we had $268 million outstanding under our revolving credit facility at a weighted average interest rate of 5.71%. We had
$4.6 million in letters of credit outstanding under our revolving credit facility at December 31, 2017 and, as a result, had available borrowing capacity of
$227 million at that date. As of February 16, 2018, we had repaid all amounts outstanding under our revolving credit facility, had approximately $118,000 of
letters of credit outstanding under our revolving credit facility, and had borrowing capacity of $499.9 million.
2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of
Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit. As of December
31, 2017, we had $54.9 million in letters of credit outstanding under the Reimbursement Agreement.
Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of
credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in
accordance with Scotiabank’s prevailing practice. We are obligated to pay to Scotiabank interest on all amounts not paid on the date of demand or when otherwise
due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days
elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.
We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our subsidiaries’ property, then our reimbursement
obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any
letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.
Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), our payment obligations under the Reimbursement Agreement are
jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement.
Series A & B Senior Notes — On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A
Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We pay interest
on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.
On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior Notes due June 14, 2022
(the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We pay interest on the Series B Notes on April 5 and
October 5 of each year. The Series B Notes will mature on June 14, 2022.
The Series A Notes and Series B Notes are senior unsecured obligations, which rank equally in right of payment with all of our other unsubordinated
indebtedness. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of our domestic subsidiaries other than subsidiaries that
are not required to be guarantors under the Credit Agreement.
The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be
in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount
prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to
prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if
the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the
principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.
40
The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50%
at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of
such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must
not permit our interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest
coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at
December 31, 2017. We do not expect that the restrictions and covenants will impair, in any material respect, o ur ability to operate or react to opportunities that
might arise.
Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational
covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA
events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing,
then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In
addition, if we default in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note
purchase agreement to be immediately due and payable.
2028 Senior Notes — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes initially guaranteed on a
senior unsecured basis by certain of our subsidiaries. The net proceeds before offering expenses were approximately $521 million of which we used $239 million
to repay amounts outstanding under our revolving credit facility. We intend to use the remainder of the net proceeds for general corporate purposes.
We pay interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes bear interest at
a rate of 3.95% per annum.
The 2028 Notes are our senior unsecured obligations, which rank equally with all of our other existing and future senior unsecured debt and will rank senior in
right of payment to all of our other future subordinated debt. The 2028 Notes will be effectively subordinated to any of our future secured debt to the extent of the
value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the liabilities (including trade payables) of our subsidiaries
that do not guarantee the 2028 Notes. The guarantors’ guarantees of the 2028 Notes (the “Guarantees”) will rank equally in right of payment with all of the
guarantors’ future unsecured senior debt and senior in right of payment to all of the guarantors’ future subordinated debt. The Guarantees will be effectively
subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets securing such debt. In the future, the Guarantees may be released
and terminated under certain circumstances.
We, at our option, may redeem the Notes in whole or part, at any time or from time to time at a redemption price equal to 100% of the principal amount of such
2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole premium. Additionally,
commencing on November 1, 2027, we, at our option, may redeem the 2028 Notes in whole or part, at a redemption price equal to 100% of the principal amount of
the 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.
The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit our and our subsidiaries’ ability to incur certain
liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to important
qualifications and limitations set forth in the indenture.
Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 Notes may require us to purchase all or a portion of such
holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The indenture also provides for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if
any, on the 2028 Notes to become or to be declared due and payable.
Common Stock Offering — On January 27, 2017, we completed an offering of 18.2 million shares of our common stock and raised net proceeds of
$472 million. We used the net proceeds of the offering to repay of SSE’s outstanding indebtedness of approximately $472 million.
41
Commitments and Cont ingencies — As of December 31, 2017, we maintained letters of credit in the aggregate amount of $59.5 million for the benefit of
various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the t erms of the underlying insurance
contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2017, no amounts had been drawn
under the letters of credit.
As of December 31, 2017, we had commitments to purchase approximately $172 million of major equipment for our drilling and pressure pumping businesses.
Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. As of
December 31, 2017, the remaining obligation under these agreements was approximately $140 million, of which materials with a total purchase price of
approximately $35.9 million were required to be purchased during 2018. In the event that the required minimum quantities are not purchased during any contract
year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.
Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We
invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.
Contractual Obligations
The following table presents information with respect to our contractual obligations as of December 31, 2017 (in thousands):
Revolving credit facility (1)
Series A Notes (2)
Interest on Series A Notes (3)
Series B Notes (4)
Interest on Series B Notes (5)
Leases (6)
Equipment purchases (7)
Inventory purchases (8)
Total (9)
Total
268,000
300,000
44,730
300,000
60,102
48,022
172,123
140,004
1,332,981
$
$
$
$
Payments due by period
Less than 1
year
1-3 years
3-5 years
More than 5
years
—
—
14,910
—
12,810
13,616
172,123
35,933
249,392
$
$
268,000
300,000
29,820
—
25,620
16,480
—
24,418
664,338
$
$
—
—
—
300,000
21,672
9,009
—
6,626
337,307
$
$
—
—
—
—
—
8,917
—
73,027
81,944
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Revolving credit facility matures on March 27, 2019.
Principal repayment of the Series A Notes is required at maturity on October 5, 2020.
Interest to be paid on the Series A Notes using 4.97% coupon rate.
Principal repayment of the Series B Notes is required at maturity on June 14, 2022.
Interest to be paid on the Series B Notes using 4.27% coupon rate.
See Note 11 of Notes to Consolidated Financial Statements.
Represents commitments to purchase major equipment to be delivered in 2018 based on expected delivery dates.
Represents commitments to purchase proppants and chemicals for our pressure pumping business.
Excludes $525 million principal repayment of, and interest to be paid on, the 2028 Notes.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements at December 31, 2017.
42
Adjusted EBITDA
Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) is not defined by accounting principles generally accepted in the
United States of America (“U.S. GAAP”). We define Adjusted EBITDA as net income (loss) plus net interest expense, income tax expense (benefit) and
depreciation, depletion, amortization and impairment expense (including impairment of goodwill). We present Adjusted EBITDA because we believe it provides
to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of
our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net
income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon
accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as
an alternative to the U.S. GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as other similarly titled measures of
other companies. Set forth below is a reconciliation of the non-U.S. GAAP financial measure of Adjusted EBITDA to the U.S. GAAP financial measure of net
income (loss).
Net income (loss)
Income tax benefit
Net interest expense
Depreciation, depletion, amortization and impairment
Impairment of goodwill
Adjusted EBITDA
Critical Accounting Policies
2017
Year Ended December 31,
2016
(Dollars in thousands)
2015
$
$
5,910 $
(333,711)
35,606
783,341
—
491,146 $
(318,634) $
(177,562)
40,039
668,434
—
212,277 $
(294,486)
(147,963)
35,511
864,759
124,561
582,382
In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by
management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition, the use of
estimates and oil and natural gas properties.
Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs
are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful
lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision
for salvage value is considered in determining depreciation of our property and equipment.
On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring
them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling longer, horizontal
wells using higher specification rigs). The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility
to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs will be retired. In
2017, we recorded an impairment charge of $29.0 million for the write-down of drilling equipment with no continuing utility as a result of the upgrade of certain
rigs to super-spec capability. In 2016, we retired 19 mechanical rigs but recorded no impairment charge as we had written down mechanical rigs that were still
marketed in 2015. In 2015, we identified 24 mechanical rigs and nine non-APEX® electric rigs that would no longer be marketed. Also, we had 15 additional
mechanical rigs that continued to be marketed but were not operating and which we had lower expectations with respect to utilization of these rigs due to the
industry shift to higher specification drilling rigs. In 2015, we recorded a charge of $131 million related to the retirement of the 33 rigs, the 15 mechanical rigs that
remained marketed but were not operating, and the write-down of excess spare rig components to their realizable values.
We also periodically evaluate our pressure pumping assets, and in 2015, we recorded a charge of $22.0 million for the write-down of pressure pumping
equipment and certain closed facilities. There were no similar charges in 2017 or 2016.
We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying
values of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are grouped at
the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in
rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to
fluctuate. We estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows
are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. Provisions for
asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision
for impairment is measured at fair value.
43
Based on current commodity prices, our results of operations for the year ended December 31, 2017 a nd management’s expectations of operating results in
future periods, we concluded that no triggering events occurred during the year ended December 31, 2017 with respect to our reporting segments. Our expectations
of future operating results were based on the assumption that activity levels in all segments and our other operations will remain relatively stable or improve in
response to relatively stable or increasing oil prices.
We concluded that no triggering events occurred during the year ended December 31, 2016, with respect to our reporting segments, based on our results of
operations for the year ended December 31, 2016, our expectations of operating results in future periods and the prevailing commodity prices at the time.
During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new low for 2015 of $38.22 per barrel in August 2015. In light
of these lower oil prices in August, we lowered our expectations with respect to future activity levels in both the contract drilling and pressure pumping businesses.
As a result of these revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the markets
for contract drilling and pressure pumping services during the third quarter of 2015, we concluded a triggering event had occurred and deemed it necessary to
assess the recoverability of long-lived asset groups for both contract drilling and pressure pumping. We performed a Step 1 analysis to assess the recoverability of
long-lived assets within our contract drilling and pressure pumping segments. With respect to these assets, future cash flows were estimated over the expected
remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no
impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and
pressure pumping segments by approximately 120% and 60%, respectively.
Due to the continued deterioration of crude oil prices in the fourth quarter of 2015, we deemed it necessary to once again assess the recoverability of long-lived
assets groups for both contract drilling and pressure pumping. We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-
lived assets within our contract drilling and pressure pumping segments. With respect to these assets, future cash flows were estimated over the expected
remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no
impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and
pressure pumping segments by approximately 120% and 100%, respectively.
For both of the assessments performed in 2015, the expected cash flows for the contract drilling segment included the backlog of commitments for contract
drilling revenues under term contracts, which was approximately $801 million and $710 million at September 30, 2015 and December 31, 2015, respectively. Rigs
not under term contracts would be subject to pricing in the spot market. Utilization and rates for rigs in the spot market and for the pressure pumping segment were
estimated based upon our historical experience in prior downturns. Also, the expected cash flows for the contract drilling and pressure pumping segments were
based on the assumption that activity levels in both segments would begin to recover in the first quarter of 2017 in response to improved oil prices.
Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. Goodwill is evaluated at least annually as of
December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of
impairment testing, goodwill is evaluated at the reporting unit level. Our reporting units for impairment testing have been determined to be our operating
segments. We determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market
and other factors, and if this is the case, any necessary goodwill impairment is determined using a quantitative impairment test. From time to time, we may perform
quantitative testing for goodwill impairment in lieu of performing the qualitative assessment. If the resulting fair value of goodwill is less than the carrying value
of goodwill, an impairment loss would be recognized for the amount of the shortfall.
In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual
or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for
the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not exceed the total amount of goodwill allocated
to that reporting unit. We adopted this update in 2017. Prior to adoption w e first determined whether it was more likely than not that the fair value of a reporting
unit was less than its carrying value after considering qualitative, market and other factors, and if so, the resulting goodwill impairment was determined using a
two-step quantitative impairment test. The first step of the quantitative testing was to compare the fair value of an entity’s reporting units to the respective carrying
value of those reporting units. If the carrying value of a reporting unit exceeded its fair value, the second step of the quantitative testing was performed whereby
the fair value of the reporting unit was allocated to its identifiable tangible and intangible assets and liabilities, with any remaining fair value representing the fair
value of goodwill. If this resulting fair value of goodwill was less than the carrying value of goodwill, an impairment loss was recognized in the amount of such
shortfall.
44
In connection with our annual goodwill impairment assessment as of December 31, 2017 and 2016, we determined based on an assessment of qualitative factors
that it was more likely than not that the fair values of our reporting units were greater than the respective carrying amount. In making this determination, we
considered the curr ent and expected levels of commodity prices for oil and natural gas, which influence the overall level of business activity in our reporting units,
as well as our operating results for 2017 and 2016 and forecasted operating results for the respective succe eding year. Management also considered our overall
market capitalization at December 31, 2017 and 2016.
During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new low for 2015 of $38.22 per barrel in August 2015. In light
of these lower oil prices in August, we lowered our expectations with respect to future activity levels in both the contract drilling and pressure pumping
businesses. As a result of our revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the
markets for our contract drilling and pressure pumping services, we performed a quantitative Step 1 impairment assessment of our goodwill as of September 30,
2015. In completing the Step 1 assessment, the fair value of each reporting unit was estimated using both the income and market valuation methods. The estimate
of the fair value of each reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement. The inputs included
assumptions related to the future performance of our contract drilling and pressure pumping reporting units, such as future oil and natural gas prices and projected
demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums.
Based on the results of the Step 1 goodwill impairment test as of September 30, 2015, the fair value of the contract drilling reporting unit exceeded its carrying
value by approximately 15%, and we concluded that no impairment was indicated in our contract drilling reporting unit; however, impairment was indicated in our
pressure pumping reporting unit. In the third quarter of 2015, we recognized an impairment charge of $125 million associated with the impairment of all of the
goodwill in our pressure pumping reporting unit.
In connection with our annual goodwill impairment assessment as of December 31, 2015, we performed a quantitative Step 1 impairment assessment of the
goodwill in our contract drilling reporting unit. In completing the Step 1 assessment, the fair value of the contract drilling reporting unit was estimated using both
the income and market valuation methods. The estimate of the fair value of the reporting unit required the use of significant unobservable inputs, representative of
a Level 3 fair value measurement. The inputs included assumptions related to the future performance of our contract drilling reporting unit, such as future oil and
natural gas prices and projected demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums. Based on the
results of the quantitative Step 1 impairment assessment of our goodwill, as of December 31, 2015, the fair value of our contract drilling reporting unit exceeded its
carrying value by approximately 16%, and we concluded that no impairment was indicated in our contract drilling reporting unit.
Revenue recognition — Revenues from our contract drilling, pressure pumping, directional drilling, oilfield rental and pipe handling components and related
technology activities are recognized as services are performed. All of the wells we drilled in 2017, 2016 and 2015 were drilled under daywork contracts. Revenues
from sales of products are recognized upon customer acceptance. Revenues are presented net of any sales tax charged to the customer that we are required to remit
to local or state governmental taxing authorities.
Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of our customers are
recorded as revenue when incurred. The related costs are recorded as operating expense when incurred.
Use of estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.
Key estimates used by management include:
•
•
•
•
•
allowance for doubtful accounts,
depreciation, depletion and amortization,
fair values of assets acquired and liabilities assumed in acquisitions,
goodwill and long-lived asset impairments, and
reserves for self-insured levels of insurance coverage.
For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.
45
Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition
Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many
years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. Please see “Risk Factors – We
are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in
Oil and Natural Gas Prices May Adversely Affect Our Operating Results” in Item 1A of this Report. The closing price of oil was as high as $107.95 per barrel in
June 2014. Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016. Oil and natural gas prices have modestly
recovered from the lows experienced in the first quarter of 2016. Oil prices averaged $55.37 per barrel in the fourth quarter of 2017. In response to improved
prices, U.S. rig counts have increased, and we believe they will continue to increase throughout 2018 if prices for these commodities remain at or above current
levels.
We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher
oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future
oil and natural gas prices. A decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of decreases in oil and natural gas
prices, would likely result in reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on
our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas
may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand
for our services.
Impact of Inflation
Inflation has not had a significant impact on our operations during the three years ended December 31, 2017. We believe that inflation will not have a
significant near-term impact on our financial position.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.
Item 7A. Quantitative
and
Qualitative
Disclosures
About
Market
Risk
We currently have exposure to interest rate market risk associated with any borrowings that we have under the Credit Agreement and the Reimbursement
Agreement.
Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by
reference only to the base rate. Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin
on base rate loans varies from 2.25% to 2.75%, in each case determined based on our excess availability under the revolving credit facility. As of
December 31, 2017, the applicable margin on LIBOR rate loans was 3.50% and the applicable margin on base rate loans was 2.50%.
As of December 31, 2017, we had $268 million outstanding under our revolving credit facility at a weighted average interest rate of 5.71%. The interest rate on
the borrowings outstanding under our revolving credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate.
Under the Reimbursement Agreement, we will reimburse the issuing bank on demand for any amounts that it has disbursed under any letters of credit. We are
obligated to pay to the issuing bank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per
annum. As of December 31, 2017, no amounts had been disbursed under any letters of credit.
We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations and our Canadian manufacturing subsidiary. The
exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar
weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to
U.S. dollars. This currency risk is not material to our results of operations or financial condition.
The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.
46
Item 8. Financial
Statements
and
Supplementary
Data.
Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are
incorporated herein by this reference.
Item 9. Changes
in
and
Disagreements
with
Accountants
on
Accounting
and
Financial
Disclosure.
None.
Item 9A. Controls
and
Procedures.
Disclosure Controls and Procedures:
Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we
conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under
the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2017, our
disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act
is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management,
including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting:
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-
15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our
internal control over financial reporting as of December 31, 2017, based on the Internal Control-Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting
was effective as of December 31, 2017.
Our wholly-owned subsidiary, MS Directional, LLC, was excluded from our evaluation of the effectiveness of our internal control over financial reporting as of
December 31, 2017. We acquired MS Directional, LLC on October 11, 2017. This subsidiary was excluded from the scope of our review due to the fact that the
acquisition closed in the fourth quarter of 2017, at which time we began integrating the acquired business into our existing internal controls over financial
reporting. The acquired business represented approximately two percent of our consolidated revenues for the year ended December 31, 2017 and approximately
five percent of our consolidated total assets as of December 31, 2017.
The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this
Report.
Changes in Internal Control over Financial Reporting:
There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or
are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
47
Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to
Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information
included therein is incorporated herein by reference.
PART III
Item 10. Directors,
Executive
Officers
and
Corporate
Governance.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer and
principal financial and accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com . We
intend to disclose any amendments to or waivers from this code on our website.
Item 11. Executive
Compensation.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 12. Security
Ownership
of
Certain
Beneficial
Owners
and
Management
and
Related
Stockholder
Matters.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 13. Certain
Relationships
and
Related
Transactions,
and
Director
Independence.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
Item 14. Principal
Accounting
Fees
and
Services.
The information required by this Item is incorporated herein by reference to the Proxy Statement.
48
PART IV
Item 15. Exhibits
and
Financial
Statement
Schedule.
(a)(1) Financial Statements
See Index to Consolidated Financial Statements on page F-1 of this Report.
(a)(2) Financial Statement Schedule
Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.
All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.
(a)(3) Exhibits
The following exhibits are filed herewith or incorporated by reference herein. Our Commission file number is 0-22664.
2.1
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
10.1
Agreement and Plan of Merger by and among Patterson-UTI Energy, Inc., Pyramid Merger Sub, Inc. and Seventy Seven Energy Inc., dated as of
December 12, 2016 (filed December 13, 2016 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q and
incorporated herein by reference).
Certificate of Amendment to the Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Comp any’s Quarterly
Report on Form 10-Q and incorporated herein by reference) .
Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current
Report on Form 8-K and incorporated herein by reference) .
Seco nd Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q and incorporated
herein by reference).
Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March
19, 2002 as Exhib it 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by
reference) .
Registration Rights Agreement, dated as of October 11, 2017, between Patterson-UTI Energy, Inc. and the sellers party thereto.+
Base Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo Bank, National
Association, as trustee (filed January 19, 2018 as Exhibit 4.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
First Supplemental Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Wells Fargo
Bank, National Association, as trustee (filed January 19 , 2018 as Exhibit 4.2 to the Company’s Current Report on Form 8-K and incorporated herein
by reference).
Form of 3.95% Senior Note due 2028 (inc luded in Exhibit 4.4 above).
Registration Rights Agreement, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein and Goldman,
Sachs & Co. LLC, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated (filed January 19, 2018 as Exhibit 4.4 to the
Company’s Current Report on Form 8-K and incorporated herein by reference).
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of
Executive Of ficer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee
Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein b y
reference) .*
10.2
First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current
Report on Form 8-K and incorporated herein by reference). *
49
10. 3
Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current
Report on Form 8-K and incorporated herein by reference). *
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
Third Amend ment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s
Current Report on Form 8-K and incorporated herein by reference) .*
Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s
Current Report on Form 8-K an d incorporated herein by reference). *
Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 a s Exhibit 10.4 to the Company’s
Quarterly Report on Form 10-Q and incorporated herein by reference) .*
Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2,
2010 as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by
reference) .*
Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (filed April 21, 2014 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and
i ncorporated herein by reference) .*
Patterson-UTI Energy, Inc. Omnibus Incentive Plan (filed April 21, 2017 as Exhibit 4.4 to the Company’s Registration Statement on Form S-8 and
incorporated herein by reference)*
Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (as amended and restated effective June 29, 2017) (filed June 30, 2017 as Exhibit 10.1 to
the Company’s Current Report on Form 8-K and incorporated herein by reference).*
Form of Executive Officer Share-Settled Performance Share Award Agreement (filed April 21, 2014 as Exhibit 10.2 to the Company’s Current
Report on Form 8-K and incorporated herein by reference) .*
Form of Executive Officer Share-Settled Performance Share Award Agreement (filed May 2, 2016 as Exhibit 10.2 to the Company’s Quarterly
Report on Form 10-Q and incorporated herein by reference) .*
Form of Executive Officer Restricted Stock Award Agreement (filed April 21, 2014 as Exhibit 10.3 to the Company’s Current Report on Form 8-K
and incorporated herein by reference) .*
Form of Executive Officer Restricted Stock Award Agreement (filed May 2, 2016 as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q
and incorporated herein by reference) .*
Form of Executive Officer Restricted Stock Unit Award Agreement (filed August 4, 2017 as Exhibit 10.5 to the Company’s Quarterly Report on
Form 10-Q and incorp orated herein by reference).*
Form of Executive Officer Stock Option Agreement (filed April 21, 2014 as Exhibit 10.4 to the Company’s Current Report on Form 8-K and
incorporated herein by reference) .*
Form of Non-Employee Director Restricted Stock Award Agreement (filed April 21, 2014 as Exhibit 10.5 to the Company’s Current Report on Form
8-K and incorporated herein by reference) .*
Form of Non-Employee Director Stock Option Agreement (filed April 21, 2014 as Exhibit 10.6 to the Company’s Current Report on Form 8-K and
incorporated herein by reference) .*
Form of Non-Employee Director Restricted Stock Unit Award Agreement .+*
Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S.
Siegel and Kenneth N. Berns (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended
December 31, 2004 and incorporated herein by reference) .*
Employment Agreement, effective as of January 1, 2017, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb (filed
January 17, 2017 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). *
Employment Agreement, effective as of August 1, 2016, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed
August 2, 2016 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference). *
Employment Agreement, effective as of August 1, 2016, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed February 13, 2017 as
Exhibit 10.20 to the Company’s Annual Report o n Form 10-K for the year ended December 31, 2016 and incorporated herein by reference) .*
Employment Agreement, dated as of September 3, 2017, b etween Patterson-UTI Energy, Inc. and C. Andrew Smith (filed September 8, 2017 as
Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference). *
50
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
Employment Agreement, dated as of December 31, 2017, between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed December 27, 2017 as
Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).*
Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns, Curtis W. Huff,
Terry H. Hunt, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler, William Andrew Hendr icks, Jr., Michael W. Conlon, Tiffany J. Thom and
C. Andrew Smith (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December
31, 2003 and incorporated herein by reference) .*
Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S.
Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference) .*
Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth
N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K fo r the year ended December 31, 2003 and
incorporated herein by reference) .*
First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed
November 5, 2007 as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference) .*
First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed
November 5, 2007 as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference) .*
Credit Agreement dated September 27, 2012, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent,
letter of credit issuer, swing line lender and lender and each of the other letter of credit issuer and lender parties thereto (filed September 28, 2012 as
Exhibit 10.1 to the Company’s Cu rrent Report on Form 8-K and incorporated herein by reference).
Amendment No. 1 to Credit Agreement , dated as of January 9, 2015, among Patterson- UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as
administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuer and lender parties thereto (filed
January 12, 2015 as Exhibit 10.1 to the Co mpany’s Current Report on Form 8-K and incorporated herein by reference).
Amendment No. 2 to Credit Agreement dated as of July 8, 2016, by and among Patterson-UTI Energy, Inc., certain subsidiaries party thereto, Wells
Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and certain other lenders party thereto (filed July 12, 2016
as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference) .
Amendment No. 3 to Credit Agreement dated as of January 17, 2017 , by and among Patterson-UTI Energy, Inc., certain subsidiaries party thereto,
Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and certain other lenders party thereto (filed
February 13, 2017 as Exhibit 10 .31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 and incorporated herein
by reference).
Commitment Increase Agreement, dated as of January 24, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries party thereto, Wells
Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and certain other lenders party theret o (filed January 24,
2017 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Amendment No. 4 to Credit Agreement, dated as of April 20, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries of Patterson-UTI
Energy, Inc. party thereto, Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender and the other lenders
party thereto (filed April 21, 2017 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Commitment Increase Agreement, dated as of April 20, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries of Patterson-UTI
Energy, Inc. party thereto, Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit an d swing line lender and the other lenders
party thereto (filed April 21, 2017 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Commitment Increase Agreement, dated as of October 27, 2017, by and among Patterson-UTI Energy, Inc., certain subsidiaries of Patterson-UTI
Energy, Inc. party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuer of letters of credit and swing line lender (filed November 2,
2017 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference).
51
10.39
10.40
10.41
10.42
10.43
10.44
10.45
21.1
23.1
31.1
31.2
32.1
101
Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010
as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Amendment No. 1 to Note Purchase Agreement, dated as of October 22, 2015, by and among Patterson-UTI Energy, Inc., certain subsidiaries of
Patterson-UTI Energy, Inc. party thereto, and the purchasers named therein (relates to Note Purchase Agreement dated October 5, 2010) (filed
October 28, 2015 as Exhibit 10.1 to the Company’s Quar terly Report on Form 10-Q and incorporated herein by reference) .
Note Purchase Agreement dated June 14, 2012 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed June 18, 2012 as
Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
Amendment No. 1 to Note Purchase Agreement, dated as of October 22, 2015, by and among Patterson-UTI Energy, Inc., certain subsidiaries of
Patterson-UTI Energy, Inc. party thereto, and the purchasers named ther ein (relates to Note Purchase Agreement dated June 14, 2012) (filed October
28, 2015 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference).
Reimbursement Agreement, dated as of March 16, 2015, by and between Patterson-UTI Energy, Inc. and The Bank of Nova Scotia (filed March 16,
2015 as Exhibit 10.1 to t he Company’s Current Report on Form 8-K and incorporated herein by reference) .
Continuing Guaranty, dated as of March 16, 2015, by Patterson Petro leum LLC, Patterson-UTI Drilling Company LLC, Patterson-UTI Management
Services, LLC, Universal Well Services, Inc. and Universal Pressure Pumping, Inc. (filed March 16, 2015 as Exhibit 10.2 to the Company’s Current
Report on Form 8-K and incorporated here in by reference).
Securities Purchase Agreement, dated as of September 4, 2017, between Patterson-UTI Energy, Inc., certain holders of limited liability company
interests of Multi-Shot, LLC, and MS Incentive Plan Holdco, LLC (filed September 8, 2017 as Exhibit 10.1 to the Company’s Current Report on
Form 8-K and incorporated herein by reference).
Subsidiaries of the Registrant.+
Consent of Independent Registered Public Accounting Firm.+
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. +
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended. +
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. +
The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2017, formatted in XBRL
(Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the
Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Stockholders’ Equity, (v) the Consolidated
Statements of Cash Flows, and (vi) Notes to Consolidated Financial Statements.+
*
+
Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K.
Filed herewith.
Item 16. Form
10-K
Summary
None.
52
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2017 and 2016
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 201 5
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2017, 2016 and 2015
Consolidated Statemen ts of Cash Flows for the years ended December 31, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
Page
F-2
F-4
F-5
F-6
F-7
F-8
F-9
F-1
R eport of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Patterson-UTI Energy, Inc.:
Opinions
on
the
Financial
Statements
and
Internal
Control
over
Financial
Reporting
We have audited the accompanying consolidated balance sheets of Patterson-UTI Energy, Inc. and its subsidiaries as of December 31, 2017 and 2016, and the
related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity and cash flows for each of the three years in the period
ended December 31, 2017, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as
the “Consolidated Financial Statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017 based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December
31, 2017 and 2016 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with
accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it presents deferred tax assets and liabilities in 2017.
Basis
for
Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting , included in Management’s Report on Internal Control over Financial Reporting
appearing under Item 9A . Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits i n accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence
regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded MS Directional, LLC from its assessment of
internal control over financial reporting as of December 31, 2017 because it was acquired by the Company in a purchase business combination during 2017. MS
Directional, LLC is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over
financial reporting represent 5% and 2%, respectively of the related consolidated financial statement amounts as of and for the year ended December 31, 2017.
F-2
Definition
an
d
Limitations
of
Internal
Control
over
Financial
Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial
reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions
and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with
the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 20, 2018
We have served as the Company’s auditor since 1993.
F-3
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Current assets:
ASSETS
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts of $2,323 and $3,191 at
December 31, 2017 and 2016, respectively
Federal and state income taxes receivable
Inventory
Other
Total current assets
Property and equipment, net
Goodwill and intangible assets
Deposits on equipment purchases
Deferred tax assets, net
Other
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
Accrued expenses
Total current liabilities
Borrowings under revolving credit facility
Long-term debt, net of debt issuance cost of $1,217 and $1,563 at
December 31, 2017 and 2016, respectively
Deferred tax liabilities, net
Other
Total liabilities
Commitments and contingencies (see Note 8)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued
Common stock, par value $.01; authorized 300,000,000 shares with 266,259,083 and
191,525,872 issued and 222,456,472 and 148,133,255 outstanding at
December 31, 2017 and 2016, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income (loss)
Treasury stock, at cost, 43,802,611 shares and 43,392,617 shares at
December 31, 2017 and 2016, respectively
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31,
2017
2016
(In thousands, except share data)
$
42,828 $
35,152
580,354
1,152
69,167
53,354
746,855
4,254,730
687,072
16,351
3,875
49,973
5,758,856 $
319,621 $
226,629
546,250
268,000
598,783
350,836
12,494
1,776,363
148,091
2,126
20,191
41,322
246,882
3,408,963
88,966
16,050
4,124
7,306
3,772,291
125,667
139,148
264,815
—
598,437
650,661
9,654
1,523,567
—
—
2,662
2,785,823
2,105,897
6,822
(918,711)
3,982,493
5,758,856 $
1,915
1,042,696
2,116,341
(1,134)
(911,094)
2,248,724
3,772,291
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
F-4
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Operating revenues:
Contract drilling
Pressure pumping
Directional drilling
Other
Total operating revenues
Operating costs and expenses:
Contract drilling
Pressure pumping
Directional drilling
Other
Depreciation, depletion, amortization and impairment
Impairment of goodwill
Selling, general and administrative
Merger and integration expenses
Other operating (income) expense, net
Total operating costs and expenses
Operating loss
Other income (expense):
Interest income
Interest expense, net of amount capitalized
Other
Total other expense
Loss before income taxes
Income tax benefit
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average number of common shares outstanding:
Basic
Diluted
2017
Year Ended December 31,
2016
(In thousands, except per share data)
2015
$
1,040,033 $
1,200,311
45,580
70,760
2,356,684
543,663 $
354,070
—
18,133
915,866
667,105
966,835
32,172
51,428
783,341
—
105,847
74,451
(31,957)
2,649,222
(292,538)
1,866
(37,472)
343
(35,263)
305,804
334,588
—
8,384
668,434
—
69,205
—
(14,323)
1,372,092
(456,226)
327
(40,366)
69
(39,970)
1,153,892
712,454
—
24,931
1,891,277
608,848
612,021
—
11,500
864,759
124,561
74,913
—
1,647
2,298,249
(406,972)
964
(36,475)
34
(35,477)
$
$
$
(327,801)
(496,196)
(442,449)
(333,711)
(177,562)
(147,963)
5,910 $
(318,634) $
(294,486)
0.03 $
0.03 $
(2.18) $
(2.18) $
(2.00)
(2.00)
198,447
199,882
146,178
146,178
145,416
145,416
Cash dividends per common share
$
0.08 $
0.16 $
0.40
The accompanying notes are an integral part of these consolidated financial statements.
F-5
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)
Other comprehensive income (loss), net of taxes of $0 for 2017, $0
for 2016 and $0 for 2015:
Foreign currency translation adjustment
Total comprehensive income (loss)
2017
Year Ended December 31,
2016
(In thousands)
2015
$
5,910 $
(318,634) $
(294,486)
$
7,956
13,866 $
2,959
(315,675) $
(10,556)
(305,042)
The accompanying notes are an integral part of these consolidated financial statements.
F-6
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Common Stock
Number of
Shares
Amount
Additional
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Stock
Total
Balance, December 31, 2014
Net loss
Foreign currency translation adjustment
Issuance of restricted stock
Vesting of restricted stock units
Forfeitures of restricted stock
Stock-based compensation
Tax expense related to stock-
based compensation
Payment of cash dividends
Purchase of treasury stock
Balance, December 31, 2015
Net loss
Foreign currency translation adjustment
Shares issued for acquisition
Issuance of restricted stock
Vesting of restricted stock units
Forfeitures of restricted stock
Exercise of stock options
Stock-based compensation
Tax expense related to stock-
based compensation
Payment of cash dividends
Purchase of treasury stock
Balance, December 31, 2016
Net income
Foreign currency translation adjustment
Equity offering
Shares issued for acquisitions
Issuance of restricted stock
Vesting of restricted stock units
Forfeitures of restricted stock
Exercise of stock options
Stock-based compensation
Payment of cash dividends
Dividend equivalents
Purchase of treasury stock
Balance, December 31, 2017
189,263 $
—
—
1,180
14
(82)
—
—
—
—
190,375
—
—
354
785
15
(43)
40
—
—
—
—
191,526
—
—
18,170
55,097
891
549
(24)
50
—
—
—
—
266,259 $
(In thousands)
1,893 $ 984,674 $ 2,811,815 $
(294,486)
—
—
—
—
(12)
—
—
—
1
—
28,510
—
—
12
—
(1)
—
—
—
—
—
(58,775)
—
1,904 1,011,811 2,458,554
(1,362)
—
—
6,463 $ (899,035) $ 2,905,810
(294,486)
(10,556)
—
—
—
28,510
—
(10,556)
—
—
—
—
—
—
—
—
—
—
—
—
—
(4,093)
—
—
(8,010)
(1,362)
(58,775)
(8,010)
(907,045) 2,561,131
—
—
3
8
—
—
—
—
—
—
6,730
(8)
—
—
707
28,324
(318,634)
—
—
—
—
—
—
—
—
2,959
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(318,634)
2,959
6,733
—
—
—
707
28,324
—
—
—
—
(23,579)
—
1,915 1,042,696 2,116,341
(4,868)
—
—
5,910
—
—
—
—
—
—
182
471,388
—
551 1,226,339
—
(9)
—
(5)
—
—
—
931
—
44,483
(16,315)
—
(39)
—
—
—
2,662 $ 2,785,823 $ 2,105,897 $
9
5
—
—
—
—
—
—
—
—
—
(1,134)
—
—
(4,049)
(4,868)
(23,579)
(4,049)
(911,094) 2,248,724
—
7,956
—
—
—
—
—
—
—
—
—
—
5,910
—
7,956
—
—
471,570
— 1,226,890
—
—
—
—
—
—
931
—
44,483
—
(16,315)
—
(39)
—
(7,617)
(7,617)
6,822 $ (918,711) $ 3,982,493
The accompanying notes are an integral part of these consolidated financial statements.
F-7
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion, amortization and impairment
Impairment of goodwill
Dry holes and abandonments
Deferred income tax benefit
Stock-based compensation expense
Net gain on asset disposals
Tax expense related to stock-based compensation
Amortization of debt issuance costs
Changes in operating assets and liabilities:
Accounts receivable
Income taxes receivable/payable
Inventory and other assets
Accounts payable
Accrued expenses
Other liabilities
Net cash provided by operating activities
Cash flows from investing activities:
Acquisitions, net of cash acquired
Purchases of property and equipment
Proceeds from disposal of assets
Other investments
Net cash used in investing activities
Cash flows from financing activities:
Proceeds from equity offering
Purchases of treasury stock
Dividends paid
Proceeds from long-term debt
Repayment of long-term debt
Proceeds from borrowings under revolving credit facility
Repayment of borrowings under revolving credit facility
Debt issuance costs
Proceeds from exercise of stock options
Net cash provided by (used in) financing activities
Effect of foreign exchange rate changes on cash
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplemental disclosure of cash flow information:
Net cash (paid) received during the year for:
Interest, net of capitalized interest of $1,175 in 2017, $398 in 2016
and $6,332 in 2015
Income taxes
Non-cash investing and financing activities:
Net increase (decrease) in payables for purchases of property
and equipment
Issuance of common stock for business acquisition
Net decrease (increase) in deposits on equipment purchases
2017
Year Ended December 31,
2016
(In thousands)
2015
$
5,910 $
(318,634) $
(294,486)
783,341
—
1,929
(330,346)
44,483
(33,510)
—
346
(239,482)
990
(23,449)
104,072
(14,190)
617
300,711
(501,954)
(567,087)
60,945
(2,520)
(1,010,616)
471,570
(6,809)
(16,315)
—
—
599,000
(331,000)
—
123
716,569
1,012
7,676
35,152
42,828 $
668,434
—
58
(152,160)
28,324
(14,771)
(4,868)
2,270
72,327
30,379
5,664
12,024
(24,573)
560
305,034
155
(119,799)
21,889
—
(97,755)
—
(3,610)
(23,579)
—
(255,000)
200,500
(200,500)
(3,357)
268
(285,278)
(195)
(78,194)
113,346
35,152 $
864,759
124,561
1,224
(99,873)
28,510
(10,613)
(1,362)
1,245
440,884
49,895
38,993
(131,649)
(10,303)
(2,348)
999,437
—
(743,776)
20,814
—
(722,962)
—
(8,010)
(58,775)
200,000
(27,500)
54,000
(357,000)
(1,979)
—
(199,264)
(6,877)
70,334
43,012
113,346
(34,953) $
3,947
(36,551) $
52,716
(33,452)
97,333
$
$
$
17,228 $
1,226,890
(301)
28,926 $
6,733
6,317
(167,308)
—
90,012
The accompanying notes are an integral part of these consolidated financial statements.
F-8
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Summary of Significant Accounting Policies
A
description
of
the
business
and
basis
of
presentation
follows:
Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries (collectively referred to herein as “Patterson-UTI” or the
“Company”), provides onshore contract drilling services to oil and natural gas operators in the continental United States and western Canada. The Company
provides pressure pumping services to oil and natural gas operators primarily in Texas and the Mid-Continent and Appalachian regions. The Company provides
directional drilling services in most major producing onshore oil and gas basins in the United States. The Company also provides oilfield rental equipment in many
of the major producing onshore oil and gas basins in the United States and manufactures and sells pipe handling components and related technology to drilling
contractors in North America and other select markets. In addition, the Company owns and invests, as a non-operating working interest owner, in oil and natural
gas assets that are primarily located in Texas and New Mexico.
Basis of presentation — The consolidated financial statements include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All significant
intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any
other entity which would require consolidation.
The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian subsidiaries, which use the Canadian dollar as their
functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of
stockholders’ equity.
In 2017, the Company adopted new guidance for the presentation of deferred tax liabilities and assets and such guidance was applied retrospectively, resulting
in the reclassification of $36.4 million from current deferred tax assets as of December 31, 2016. Of this amount, $4.1 million was reclassified to long-term
deferred tax assets and $32.3 million was reclassified to long-term deferred tax liabilities. During 2016, the Company determined that certain income and expense
items should be classified as “other operating (income) expense, net” in the consolidated statements of operations. This caption now includes gains and losses on
asset disposals and expenses related to certain legal settlements. Gains and losses on asset disposals were previously presented as a separate line in the
consolidated statements of operations. Expenses related to certain legal settlements were previously included in operating costs of the respective operating segment
or within selling, general and administrative expense. For comparative purposes, all such prior period amounts were reclassified to conform to the current
presentation, including the Company’s previously disclosed $12.3 million legal settlement that was previously included within selling, general and administrative
expense for the year ended December 31, 2015. In addition, the Company changed its reporting segment presentation in 2016, as the Company no longer considers
its oil and natural gas exploration and production activities to be significant to an understanding of the Company’s results. The Company now presents the oil and
natural gas exploration and production activities, oilfield rental business, pipe handling components and related technology business and Middle East/North Africa
activities as “Other” and “Corporate” reflects only corporate activities. This change in segment presentation was applied retrospectively to all periods presented
herein (See Note 14).
On December 12, 2016, the Company entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), and
the merger closed on April 20, 2017 (the “merger date”). The Company’s results include the results of operations of SSE since the merger date (See Note 2). On
October 11, 2017, the Company acquired all of the issued and outstanding limited liability company interests of MS Directional, LLC (f/k/a Multi-Shot, LLC)
(“MS Directional”). The Company’s results include the results of operations of MS Directional since October 11, 2017 (See Note 2). The acquisition of MS
Directional created a new directional drilling reporting segment for the Company (See Note 14).
A
summary
of
the
significant
accounting
policies
follows:
Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America
(“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could
differ from such estimates.
Revenue recognition — Revenues from our contract drilling, pressure pumping, directional drilling, oilfield rental and pipe handling components and related
technology activities are recognized as services are performed. All of the wells the Company drilled in 2017, 2016 and 2015 were drilled under daywork
contracts. Revenue from sales of products are recognized upon customer acceptance. Revenue is presented net of any sales tax charged to the customer that the
Company is required to remit to local or state governmental taxing authorities.
Reimbursements for the purchase of supplies, equipment, personnel services, shipping and other services that are provided at the request of the Company’s
customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred.
F-9
Accounts receivable — Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts represents the Company’s
estimate of the amount of probable credit losses existing in the Company’s accoun ts receivable. The Company reviews the adequacy of its allowance for doubtful
accounts at least quarterly. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed
individually for col lectability. Account balances, when determined to be uncollectable, are charged against the allowance.
Inventories — Inventories consist primarily of sand and other products to be used in conjunction with the Company’s pressure pumping activities and materials
used in its directional drilling and drilling technology business. Such inventories are stated at the lower of cost or market, with cost determined using the average
cost method.
Other current assets — Other current assets includes reimbursement from the Company’s workers compensation insurance carrier for claims in excess of the
Company’s deductible in the amount of $30.0 million and $21.1 million at December 31, 2017 and 2016, respectively.
Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over
the estimated useful lives. The method of depreciation does not change whenever equipment becomes idle. The estimated useful lives, in years, are shown below:
Equipment
Buildings
Other
Useful Lives
1.25-15
15-20
3-12
Long-lived assets, including property and equipment, are evaluated for impairment when certain triggering events or changes in circumstances indicate that the
carrying values may not be recoverable over their estimated remaining useful life.
Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve
existing property and equipment are capitalized.
Disposals — Upon disposition of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected
in the consolidated statement of operations.
Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of
accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development
costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such
determination is made. Costs of exploratory wells are initially capitalized to wells-in-progress until the outcome of the drilling is known. The Company reviews
wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no
progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, the Company considers the
well costs to be impaired and recognizes the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped
properties are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well
equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total
proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized
using the units-of-production method, based on engineering estimates of total proved oil and natural gas reserves for each respective field.
The Company reviews its proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve
estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared
based on management’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum
engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between
net book value and fair value. The fair value estimates used in measuring impairment are based on internally developed unobservable inputs including reserve
volumes and future production, pricing and operating costs (Level 3 inputs in the fair value hierarchy of fair value accounting). The Company reviews unproved
oil and natural gas properties quarterly to assess potential impairment. The Company’s impairment assessment is made on a lease-by-lease basis and considers
factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property
costs are expensed.
Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. The Company assesses impairment of its goodwill at least
annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value.
F-10
Net income (loss) per common share — The Company provides a dual presentation of its net income (loss) per common share in its consolidated statements of
operations: Basic net income (loss) per common share (“Basic EPS”) and diluted net inco me (loss) per common share (“Diluted EPS”).
Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted
stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding
during the period, excluding non-vested shares of restricted stock.
Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock
options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined using the
treasury stock method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class
method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-
vested shares of restricted stock.
The following table presents information necessary to calculate net income (loss) per share for the years ended December 31, 2017, 2016 and 2015, as well as
potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-
dilutive (in thousands, except per share amounts):
BASIC EPS:
Net income (loss)
Adjust for (income) loss attributed to holders of non-vested restricted stock
Income (loss) attributed to common stockholders
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock
Basic net income (loss) per common share
DILUTED EPS:
Income (loss) attributed to common stockholders
Weighted average number of common shares outstanding, excluding
non-vested shares of restricted stock
Add dilutive effect of potential common shares
Weighted average number of diluted common shares outstanding
$
$
$
$
2017
2016
2015
5,910
(170)
5,740
$
$
(318,634)
—
(318,634)
$
$
(294,486)
3,022
(291,464)
198,447
146,178
145,416
0.03
$
(2.18)
$
(2.00)
5,740
$
(318,634)
$
(291,464)
198,447
1,435
199,882
146,178
—
146,178
145,416
—
145,416
Diluted net income (loss) per common share
$
0.03
$
(2.18)
$
(2.00)
Potentially dilutive securities excluded as anti-dilutive
3,289
9,057
7,781
Income taxes — The asset and liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for
operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable
income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax
rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is recorded to reduce the carrying
amounts of deferred tax assets unless it is more likely than not that such assets will be realized. The Company’s policy is to account for interest and penalties with
respect to income taxes as operating expenses.
F-11
On December 22, 2017, significant changes were enacted to U.S. tax law (“tax reform”). One of the provisions of tax reform is the introduction of a new U.S.
tax on certain off-shore earnings referred to as Global Intangible Low-T axed Income ( “ GILTI ” ) at an effective tax rate of 10.5% (in the case of a corporation)
for tax years beginning after December 31, 2017 (increasing to 13.125% for tax years beginning after December 31, 2025) with a partial offset for any related
foreign tax credits. The Company is still evaluating the GILTI provisions of tax reform and its impact, if any, on the Company’s consolidated financial statements
at December 31, 2017. The Financial Accounting Standards Board ( “ FASB ” ) staff allowed companies to ado pt an accounting policy to either provide deferred
taxes for GILTI or treat it as a tax cost in the year incurred. The Company has not yet determined its accounting policy because determining the impact of the
GILTI provisions requires analysis of its exi sting legal entity structure, the reversal of its U.S. GAAP and U.S. tax basis differences in the assets and liabilities of
its foreign subsidiaries, and its ability to offset any tax with foreign tax credits. As such, the Company did not record a deferre d income tax expense or benefit
related to the GILTI provisions in its c onsolidated s tatement of o perations for the year ended December 31, 2017 and will finalize its evaluation of the GILTI
provisions during the measurement period provided under Staff Accounting Bulletin ( “ SAB ” ) 118.
Stock-based compensation — The Company recognizes the cost of share-based payments under the fair-value-based method. Under this method, compensation
cost related to share-based payments is measured based on the estimated fair value of the awards at the date of grant, net of estimated forfeitures. This expense is
recognized over the expected life of the awards (See Note 10).
As share-based compensation expense recognized in the consolidated statements of operations is based on awards ultimately expected to vest, it has been
reduced for estimated forfeitures, based on historical experience. Forfeitures are estimated at the time of grant and revised in subsequent periods if actual
forfeitures differ from those estimates.
Statement of cash flows — For purposes of reporting cash flows, cash and cash equivalents include cash on deposit and money market funds.
Recently Issued Accounting Standards — In May 2014, the FASB issued an accounting standards update to provide guidance on the recognition of revenue
from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it
expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the
nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. The requirements in this update are effective
during interim and annual periods beginning after December 15, 2017. The Company adopted this new revenue guidance effective January 1, 2018, utilizing the
modified retrospective method, and will expand its consolidated financial statement disclosures in order to comply with the update. The adoption of this update did
not have a material impact on the Company’s consolidated financial statements.
In February 2016, the FASB issued an accounting standards update to provide guidance for the accounting for leasing transactions. The standard requires the
lessee to recognize a lease liability along with a right-of-use asset for all leases with a term longer than one year. A lessee is permitted to make an accounting
policy election by class of underlying asset to not recognize the lease liability and related right-of-use asset for leases with a term of one year or less. The
provisions of this standard also apply to situations where the Company is the lessor. The requirements in this update are effective during interim and annual
periods beginning after December 15, 2018. The Company previously disclosed its intention to adopt this standard at the same time as it adopted the new revenue
standard discussed above; however, the Company now expects to adopt this new guidance in the first quarter of 2019. The Company is currently evaluating the
impact that this new guidance will have on its consolidated financial statements.
In November 2015, the FASB issued an accounting standards update to provide guidance for the presentation of deferred tax liabilities and assets. Under this
guidance, for a particular tax-paying component of an entity and within a particular tax jurisdiction, all deferred tax liabilities and assets, as well as any related
valuation allowance, shall be offset and presented as a single noncurrent amount. This guidance became effective for the Company during the three months ended
March 31, 2017. The adoption of this update was applied retrospectively, resulting in the reclassification of $36.4 million from current deferred tax assets as of
December 31, 2016. Of this amount, $4.1 million was reclassified to long-term deferred tax assets and $32.3 million was reclassified to long-term deferred tax
liabilities.
In March 2016, the FASB issued an accounting standards update to provide guidance for the accounting for share-based payment transactions, including the
related income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance became
effective for the Company during the three months ended March 31, 2017. The Company believes this guidance has caused and will continue to cause volatility in
its effective tax rates and diluted earnings per share due to the tax effects related to share-based payments being recorded in the statement of operations. The
volatility in future periods will depend on the Company’s stock price and the number of shares that vest in the case of restricted stock, restricted stock units and
performance stock units, or the number of shares that are exercised in the case of stock options.
In August 2016, the FASB issued an accounting standard to clarify the presentation of cash receipts and payments in specific situations on the statement of cash
flows. The requirements in this update are effective during interim and annual periods beginning after December 15, 2017. The adoption of this update on January
1, 2018 did not have a material impact on the Company’s consolidated financial statements.
F-12
In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual
or interim goodwill impa irment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for
the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not e xceed the total amount of goodwill allocated
to that reporting unit. The requirements in this update are effective during interim and annual periods in fiscal years beginning after December 15, 2019. Early
adoption is permitted for interim or annual good will impairment tests performed on testing dates on or after January 1, 2017. The Company adopted this update in
2017, which did not have a material impact on the Company’s consolidated financial statements.
In May 2017, the FASB issued an accounting standards update that provided clarity on which changes to the terms or conditions of share-based payment awards
require an entity to apply modification accounting provisions. The requirements in this update are effective during interim and annual periods in fiscal years
beginning after December 15, 2017. The adoption of this update on January 1, 2018 did not have a material impact on the Company’s consolidated financial
statements.
2. Acquisitions
SSE
On April 20, 2017, pursuant to the merger agreement, a subsidiary of the Company was merged with and into SSE, with SSE continuing as the surviving entity
and one of the Company’s wholly owned subsidiaries (the “SSE merger”). Pursuant to the terms of the merger agreement, the Company acquired all of the issued
and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of common stock of the Company. Concurrent with the
closing of the merger, the Company repaid all of the outstanding debt of SSE totaling $472 million. Based on the closing price of the Company’s common stock on
April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion. On April 20, 2017, following
the SSE merger, SSE was merged with and into a newly-formed subsidiary of the Company named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC
continuing as the surviving entity and one of the Company’s wholly owned subsidiaries.
Through the SSE merger, the Company acquired a fleet of 91 drilling rigs, 36 of which the Company considers to be APEX® rigs. Additionally, through the
SSE merger, the Company acquired approximately 500,000 horsepower of modern, efficient fracturing equipment. The oilfield rentals business acquired through
the SSE merger has a modern, well-maintained fleet of premium rental tools, and it provides specialized services for land-based oil and natural gas drilling,
completion and workover activities.
The merger has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the
consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the
acquisition date, with the remaining unallocated amount recorded as goodwill. Merger and integration expenses incurred by the Company related to the SSE
merger were $69.5 million.
The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):
Shares of Company common stock issued to SSE shareholders
Company common stock price on April 20, 2017
Fair value of common stock issued
Plus SSE long-term debt repaid by Company
Total fair value of consideration transferred
F-13
$
$
$
$
46,298
22.45
1,039,396
472,000
1,511,396
The final determination of the fair value of assets acquired and liabilities assumed at the merger date will be completed as soon as possible, but no later than one
year from the merger date (the “measurement period”). The Company’s preliminary purchase price allocation is subject to revision as additional information about
the fair value of assets and liabilities becomes available. Additional information that existed as of the merger date, but at the time was unknown to the Company,
may become known to the Company during the remainder of the measurement period. The final determination of fair value may differ materially from these
preliminary estimates. The following table represents the preliminary allocation of the total purchase price of SSE to the assets acquired and the liabilities
assumed based on the fair value at the merger date, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired
recorded as goodwill (in thousands):
Identifiable assets acquired
Cash and cash equivalents
Accounts receivable
Inventory
Other current assets
Property and equipment
Other long-term assets
Intangible assets
Total identifiable assets acquired
Liabilities assumed
Accounts payable and accrued liabilities
Deferred income taxes
Other long-term liabilities
Total liabilities assumed
Net identifiable assets acquired
Goodwill
Total net assets acquired
$
$
37,806
149,659
8,518
19,038
984,433
20,918
22,500
1,242,872
133,415
32,881
1,734
168,030
1,074,842
436,554
1,511,396
The goodwill reflected above has decreased $1.9 million from the original preliminary purchase price allocation as a result of measurement period adjustments,
primarily related to a valuation adjustment to a long-term asset offset by valuation adjustments to accounts payable and accrued liabilities and deferred income
taxes.
The acquired goodwill is not deductible for tax purposes. Among the factors that contributed to a purchase price resulting in the recognition of goodwill was
SSE’s reputation as an experienced provider of high-quality contract drilling and pressure pumping services in a safe and efficient manner. See Note 5 for a
breakdown of goodwill acquired by operating segment.
A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:
Assets
Favorable drilling contracts
MS Directional
Fair Value
(in thousands)
Weighted Average
Useful Life
(in years)
$
22,500
0.83
On October 11, 2017, the Company acquired all of the issued and outstanding limited liability company interests of MS Directional. The aggregate
consideration paid by the Company consisted of $69.8 million in cash and approximately 8.8 million shares of the Company’s common stock. The purchase price
is subject to customary post-closing adjustments relating to cash, net working capital and indebtedness of MS Directional as of the closing. Based on the closing
price of the Company’s common stock on the closing date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS
Directional was approximately $257 million.
MS Directional is a leading directional drilling services company in the United States, with operations in most major producing onshore oil and gas basins. MS
Directional provides a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying,
measurement while drilling, and wireline steering tools.
The acquisition has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of
the consideration transferred is allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the
acquisition date, with the remaining unallocated amount recorded as goodwill. Merger and integration expenses incurred by the Company related to this
acquisition amounted to $5.0 million.
F-14
The total fair value of the consideration transferred was determined as follows (in thousands, except stock price):
Shares of Company common stock issued to MS Directional shareholders
Company common stock price on October 11, 2017
Fair value of common stock issued
Plus MS Directional long-term debt repaid by Company
Plus cash to sellers
Total fair value of consideration transferred
$
$
$
$
$
8,798
21.31
187,494
63,000
6,781
257,275
The final determination of the fair value of assets acquired and liabilities assumed at the acquisition date will be completed as soon as possible, but no later than
one year from the acquisition date (the “measurement period”). The Company’s preliminary purchase price allocation is subject to revision as additional
information about the fair value of assets and liabilities becomes available. Additional information that existed as of the acquisition date, but at the time was
unknown to the Company, may become known to the Company during the remainder of the measurement period. The final determination of fair value may differ
materially from these preliminary estimates. The following table represents the preliminary allocation of the total purchase price of MS Directional to the assets
acquired and the liabilities assumed based on the fair value at the merger date, with the excess of the purchase price over the estimated fair value of the identifiable
net assets acquired recorded as goodwill (in thousands):
Identifiable assets acquired
Cash and cash equivalents
Accounts receivable
Inventory
Other current assets
Property and equipment
Other long-term assets
Intangible assets
Total identifiable assets acquired
Liabilities assumed
Accounts payable and accrued liabilities
Other long-term liabilities
Total liabilities assumed
Net identifiable assets acquired
Goodwill
Total net assets acquired
$
$
2,021
42,782
28,060
155
63,998
318
74,682
212,016
43,099
327
43,426
168,590
88,685
257,275
The acquired goodwill is deductible for tax purposes. Among the factors that contributed to a purchase price resulting in the recognition of goodwill was MS
Directional’s reputation as an experienced provider of high-quality directional drilling services in a safe and efficient manner. All of the goodwill acquired is
attributable to the direction drilling operating segment (See Note 5).
A portion of the fair value consideration transferred has been provisionally assigned to identifiable intangible assets as follows:
Assets
Developed technology
Customer relationships
Internal use software
Fair Value
(in thousands)
Weighted Average
Useful Life
(in years)
$
$
48,000
26,200
482
74,682
10.00
3.00
5.00
7.51
F-15
Pro Forma
The results of SSE’s operations since the SSE merger date of April 20, 2017 and the results of MS Directional since the acquisition date of October 11, 2017 are
included in our consolidated statement of operations. It is impractical to quantify the contribution of the SSE operations since the merger, as the contract drilling
and pressure pumping businesses were fully integrated into the Company’s existing operations in 2017. The contribution of MS Directional since the date of the
acquisition is reflected as the Company’s directional drilling segment, as disclosed in Note 14. The following pro forma condensed combined financial information
was derived from the historical financial statements of the Company, SSE and MS Directional and gives effect to the acquisitions as if they had occurred on
January 1, 2016. The below information reflects pro forma adjustments based on available information and certain assumptions the Company believes are
reasonable, including (i) adjustments related to the depreciation and amortization of the fair value of acquired intangibles and fixed assets, (ii) removal of the
historical interest expense of the acquired entities, (iii) the tax benefit of the aforementioned pro forma adjustments, and (iv) adjustments related to the common
shares outstanding to reflect the impact of the consideration exchanged in the acquisitions. Additionally, the pro forma loss for the year ended December 31, 2017
was adjusted to exclude the Company’s merger and integration-related costs of $74.5 million and SSE’s merger related costs of $36.7 million with a corresponding
inclusion in the net loss for the year ended December 31, 2016 to give effect as if the acquisitions had occurred on January 1, 2016. The pro forma results of
operations do not include any cost savings or other synergies that may result from the SSE merger or MS Directional acquisition. The pro forma results of
operations also do not include any estimated costs that have been or will be incurred by the Company to integrate the SSE and MS Directional operations. The pro
forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have
actually occurred had the SSE merger and MS Directional acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a
projection of future results. The following table summarizes selected financial information of the Company on a pro forma basis (in thousands, except per share
data):
Revenues
Net income (loss)
Net income (loss) per share
Basic
Diluted
Warrior Rig Ltd
2017
2016
(Unaudited)
2,738,579 $
29,584 $
0.13 $
0.13 $
1,567,141
(505,413)
(2.30)
(2.30)
$
$
$
$
During September 2016, the Company issued 353,804 shares of its common stock, valued at $6.7 million, in connection with the acquisition of Warrior Rig
Ltd. and certain related entities (“Warrior”). Based in Calgary, Warrior manufactures and sells pipe handling components and related technology for drilling
contractors in North America and other select markets. This acquisition was not material to the Company’s consolidated financial statements.
3. Inventory
Inventory consisted of the following at December 31, 2017 and 2016 (in thousands).
Finished goods
Work-in-process
Raw materials and supplies
Inventory
4. Property and Equipment
Property and equipment consisted of the following at December 31, 2017 and 2016 (in thousands):
Equipment
Oil and natural gas properties
Buildings
Land
Total property and equipment
Less accumulated depreciation, depletion and impairment
Property and equipment, net
F-16
$
$
$
$
2017
2016
2,270
529
66,368
69,167
$
$
—
1,803
18,388
20,191
2017
2016
8,066,404
211,566
185,475
26,593
8,490,038
(4,235,308)
4,254,730
$
$
6,809,129
201,568
97,029
22,270
7,129,996
(3,721,033)
3,408,963
Depreciation, depletion, amortization and impairment — The following table summarizes depreciation, depletion, amortization and impairment expense related
to property and equipment and intangible assets and liabilities for 2017, 2016 and 2015 (in thousands):
Depreciation and impairment expense
Amortization expense
Depletion expense
Total
$
$
2017
2016
2015
753,510
21,764
8,067
783,341
$
$
657,571
3,643
7,220
668,434
$
$
845,543
3,643
15,573
864,759
On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be
necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling
longer, horizontal wells using higher specification rigs). The components comprising rigs that will no longer be marketed are evaluated, and those components
with continuing utility to the Company’s other marketed rigs are transferred to other rigs or to the Company’s yards to be used as spare equipment. The remaining
components of these rigs are retired. In 2017, the Company r ecorded an impairment charge of $29.0 million for the write-down of drilling equipment with no
continuing utility as a result of the upgrade of certain rigs to super-spec capability. In 2016, the Company retired 19 mechanical rigs but recorded no impairment
charge as it had written down mechanical rigs that were still marketed in 2015. In 2015, the Company identified 24 mechanical rigs and nine non-APEX® electric
rigs that would no longer be marketed. Also, the Company had 15 additional mechanical rigs that continued to be marketed but were not operating and which the
Company had lower expectations with respect to utilization of these rigs due to the industry shift to higher specification drilling rigs. In 2015, the Company
recorded a charge of $131 million related to the retirement of the 33 rigs, the 15 mechanical rigs that remained marketed but were not operating, and the write-
down of excess spare rig components to their realizable values.
The Company also periodically evaluates its pressure pumping assets, and in 2015, the Company recorded a charge of $22.0 million for the write-down of
pressure pumping equipment and certain closed facilities. There were no similar charges in 2017 or 2016.
The Company reviews its long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that their
carrying amounts of certain assets may not be recovered over their estimated remaining useful lives (“triggering events”). In connection with this review, assets are
grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The Company estimates future cash flows over the
life of the respective assets or asset groupings in its assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry
as well as the Company’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when
estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured at fair value.
Based on current commodity prices, the Company’s results of operations for the year ended December 31, 2017 and management’s expectations of operating
results in future periods, the Company concluded that no triggering events occurred during the year ended December 31, 2017 with respect to its reporting
segments. The Company’s expectations of future operating results were based on the assumption that activity levels in all segments and in the Company’s other
operations will remain relatively stable or improve in response to relatively stable or increasing oil prices.
The Company concluded that no triggering events occurred during the year ended December 31, 2016 with respect to its reporting segments based on the
Company’s results of operations for the year ended December 31, 2016, management’s expectations of operating results in future periods and the prevailing
commodity prices at the time.
During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new low for 2015 of $38.22 per barrel in August 2015. In light
of these lower oil prices in August 2015, the Company lowered its expectations with respect to future activity levels in both the contract drilling and pressure
pumping businesses. As a result of these revised expectations of the duration of the lower oil and natural gas commodity price environment and the related
deterioration of the markets for contract drilling and pressure pumping services during the third quarter of 2015, management concluded a triggering event had
occurred and deemed it necessary to assess the recoverability of long-lived asset groups for both contract drilling and pressure pumping. The Company performed
a Step 1 analysis to assess the recoverability of long-lived assets within its contract drilling and pressure pumping segments. With respect to these assets, future
cash flows were estimated over the expected remaining life of the assets, and the Company determined that, on an undiscounted basis, expected cash flows
exceeded the carrying value of the long-lived assets, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying
values of the long-lived assets within the contract drilling and pressure pumping segments by approximately 120% and 60%, respectively.
F-17
Due to the continued deterioration of crude oil prices in the fourth quarter of 2015, manage ment deemed it necessary to once again assess the recoverability of
long-lived assets groups for both contract drilling and pressure pumping. The Company performed a Step 1 analysis to assess the recoverability of long-lived assets
within its contract dri lling and pressure pumping segments. With respect to these assets, future cash flows were estimated over the expected remaining life of the
assets, and the Company determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment
was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and pressure
pumping segments by approximately 120% and 100%, resp ectively.
For both of the assessments performed in 2015, the expected cash flows for the contract drilling segment included the backlog of commitments for contract
drilling revenues under term contracts, which was approximately $801 million and $710 million at September 30, 2015 and December 31, 2015, respectively . Rigs
not under term contracts would be subject to pricing in the spot market. Utilization and rates for rigs in the spot market and for the pressure pumping segment were
estimated based upon the Company’s historical experience in prior downturns. Also, the expected cash flows for the contract drilling and pressure pumping
segments were based on the assumption that activity levels in both segments would begin to recover in the first quarter of 2017 in response to improved oil prices.
5. Goodwill and Intangible Assets
Goodwill — Goodwill by operating segment as of December 31, 2017 and 2016 and changes for the years then ended are as follows (in thousands):
Balance December 31, 2015 and 2016
Goodwill acquired
Balance December 31, 2017
Contract
Drilling
Pressure
Pumping
Directional
Drilling
Oilfield
Rental
$
$
86,234
308,826
395,060
$
$
—
121,444
121,444
$
$
—
88,685
88,685
$
$
—
6,284
6,284
$
$
Total
86,234
525,239
611,473
There were no accumulated impairment losses related to goodwill as of December 31, 2017 or 2016.
Goodwill is evaluated at least annually as of December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased
below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment
testing have been determined to be its operating segments. The Company determines whether it is more likely than not that the fair value of a reporting unit is less
than its carrying value after considering qualitative, market and other factors, and if this is the case, any necessary goodwill impairment is determined using a
quantitative impairment test. From time to time, the Company may perform quantitative testing for goodwill impairment in lieu of performing the qualitative
assessment. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of such
shortfall.
In January 2017, the FASB issued an accounting standards update to eliminate Step 2 from the goodwill impairment test. An entity will now perform its annual
or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for
the amount by which the carrying amount exceeds the reporting unit’s fair value, but the loss recognized should not exceed the total amount of goodwill allocated
to that reporting unit. The Company adopted this update in 2017. Prior to adoption the Company first determined whether it was more likely than not that the fair
value of a reporting unit was less than its carrying value after considering qualitative, market and other factors, and if so, the resulting goodwill impairment was
determined using a two-step quantitative impairment test. The first step of the quantitative testing was to compare the fair value of an entity’s reporting units to the
respective carrying value of those reporting units. If the carrying value of a reporting unit exceeded its fair value, the second step of the quantitative testing was
performed whereby the fair value of the reporting unit was allocated to its identifiable tangible and intangible assets and liabilities, with any remaining fair value
representing the fair value of goodwill. If this resulting fair value of goodwill was less than the carrying value of goodwill, an impairment loss was recognized in
the amount of such shortfall.
In connection with its annual goodwill impairment assessment as of December 31, 2017 and 2016, the Company determined based on an assessment of
qualitative factors that it was more likely than not that the fair values of its reporting units were greater than the respective carrying amount. In making this
determination, the Company considered the current and expected levels of commodity prices for oil and natural gas, which influence the overall level of business
activity in its reporting units, as well as the Company’s operating results for 2017 and 2016 and forecasted operating results for the respective succeeding
year. Management also considered the Company’s overall market capitalization at December 31, 2017 and 2016.
F-18
During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new lo w for 2015 of $38.22 per barrel in August 2015. In light
of these lower oil prices in August, the Company lowered its expectations with respect to future activity levels in both the contract drilling and pressure pumping
businesses. As a result of the Co mpany’s revised expectations of the duration of the lower oil and natural gas commodity price environment and the related
deterioration of the markets for its contract drilling and pressure pumping services, the Company performed a quantitative Step 1 impa irment assessment of its
goodwill as of September 30, 2015. In completing the Step 1 assessment, the fair value of each reporting unit was estimated using both the income and market
valuation methods. The estimate of fair value for each reporting unit re quired the use of significant unobservable inputs, representative of a Level 3 fair value
measurement. The inputs included assumptions related to the future performance of the Company’s contract drilling and pressure pumping reporting units, such as
futur e oil and natural gas prices and projected demand for the Company’s services, and assumptions related to discount rates, long-term growth rates and control
premiums.
Based on the results of the Step 1 goodwill impairment test as of September 30, 2015, the fair value of the contract drilling reporting unit exceeded its carrying
value by approximately 15%, and management concluded that no impairment was indicated in its contract drilling reporting unit; however, impairment was
indicated in its pressure pumping reporting unit. In the third quarter of 2015, the Company recognized an impairment charge of $125 million associated with the
impairment of all of the goodwill in its pressure pumping reporting unit.
In connection with its annual impairment asset at December 31, 2015, the Company performed a quantitative Step 1 impairment assessment of the goodwill in
its contract drilling reporting unit. In completing the Step 1 assessment, the fair value of the contract drilling reporting unit was estimated using both the income
and market valuation methods. The estimate of the fair value of the reporting unit required the use of significant unobservable inputs, representative of a Level 3
fair value measurement. The inputs included assumptions related to the future performance of the Company’s contract drilling reporting unit, such as future oil and
natural gas prices and projected demand for the Company’s services, and assumptions related to discount rates, long-term growth rates and control
premiums. Based on the results of the quantitative Step 1 impairment assessment of its goodwill as of December 31, 2015, the fair value of the contract drilling
reporting unit exceeded its carrying value by approximately 16%, and management concluded that no impairment was indicated in its contract drilling reporting
unit.
Intangible Assets — In 2017, intangible assets were recorded in the Company’s directional drilling operating segment with the acquisition of MS Directional
and in the contract drilling operating segment with the SSE merger (See Note 2). In addition, intangible assets were recorded in the pressure pumping operating
segment in connection with the 2010 acquisition of the assets of a pressure pumping business. The Company’s intangible assets were recorded at fair value on the
date of acquisition and are amortized on a straight line basis. The following table identifies the segment and weighted average useful life of each of the Company’s
intangible assets:
Customer relationships
Customer relationships
Developed technology
Favorable drilling contracts
Internal use software
Segment
Pressure pumping
Directional drilling
Directional drilling
Contract drilling
Directional drilling
Weighted Average
Useful Life
(in years)
7.00
3.00
10.00
0.83
5.00
The Company concluded that no triggering events necessitating an impairment assessment of the intangible assets had occurred in 2017, 2016 or 2015. The
assessment of the recoverability of the respective operating segments asset group included the respective intangible assets, and no impairment was indicated.
The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2017 and 2016 are as follows (in thousands):
Customer relationships
Developed technology
Favorable drilling contracts
Internal use software
Gross Carrying
Amount
$
$
26,200
48,000
22,500
482
97,182
$
2017
Accumulated
Amortization
$
2016
Accumulated
Amortization
$
Net Carrying
Amount
Gross Carrying
Amount
Net Carrying
Amount
(1,943) $
(1,137)
(18,482)
(21)
(21,583) $
24,257
46,863
4,018
461
75,599
$
$
25,500
—
—
—
25,500
$
(22,768) $
—
—
—
(22,768) $
2,732
—
—
—
2,732
Amortization expense on intangible assets of approximately $24.3 million, $3.6 million and $3.6 million for the years ended December 31, 2017, 2016 and
2015, respectively. The remaining amortization expense associated with finite-lived intangible assets is expected to be as follows (in thousands):
F-19
Year ending December 31,
2018
2019
2020
2021
2022
Thereafter
Total
6. Accrued Expenses
Accrued expenses consisted of the following at December 31, 2017 and 2016 (in thousands):
Salaries, wages, payroll taxes and benefits
Workers’ compensation liability
Property, sales, use and other taxes
Insurance, other than workers’ compensation
Accrued interest payable
Accrued merger and integration
Other
7. Long-Term Debt
$
$
2017
2016
$
$
50,443
80,751
29,332
10,816
7,558
16,101
31,628
226,629
$
$
17,580
13,630
11,686
4,896
4,875
22,932
75,599
21,138
67,775
6,766
9,566
6,740
—
27,163
139,148
2012 Credit Agreement — On September 27, 2012, the Company entered into a Credit Agreement (“Base Credit Agreement”) with Wells Fargo Bank, N.A., as
administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto. The Base Credit Agreement (as amended, the
“Credit Agreement”) is a committed senior unsecured credit facility that includes a revolving credit facility.
On July 8, 2016, the Company entered into Amendment No. 2 to the Credit Agreement (Amendment No. 2”), which amended the Base Credit Agreement to,
among other things, make borrowings under the revolving credit facility subject to a borrowing base calculated by reference to the Company’s and certain of its
subsidiaries’ eligible equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2. The revolving credit facility contains a
letter of credit facility that is limited to $50 million and a swing line facility that is limited to $20 million, in each case outstanding at any time. The maturity date
under the Base Credit Agreement was September 27, 2017 for the revolving credit facility; however, Amendment No. 2 extended the maturity date of
$357.9 million in revolving credit commitments of certain lenders to March 27, 2019. On January 17, 2017, the Company entered into Amendment No. 3 to Credit
Agreement, which amended the Credit Agreement by restating the definition of Consolidated EBITDA to provide for the add-back of transaction expenses related
to the SSE merger. On January 24, 2017, the Company entered into an agreement with certain lenders under its revolving credit facility to increase the aggregate
commitments under its revolving credit facility to approximately $595.8 million, subject to the satisfaction of certain conditions. The aggregate commitment
increase became effective on April 20, 2017 upon the consummation of the SSE merger and the repayment and termination of the SSE credit facility. On April 20,
2017, the Company entered into Amendment No. 4 to Credit Agreement which permitted outstanding letters of credit under the SSE credit facility to be deemed to
be incurred under the Company’s credit facility and increased the amount of the accordion feature of the Company’s revolving credit facility to permit aggregate
commitments to be increased to an amount not to exceed $700 million (subject to satisfaction of certain conditions and the procurement of additional commitments
from new or existing lenders). On April 20, 2017, the Company also entered into an additional commitment increase agreement with certain of its lenders pursuant
to which total commitments available under the Company’s revolving credit facility (after giving effect to both commitment increases) increased to $632 million
through September 2017 and to $490 million through March 2019. On October 27, 2017, the Company entered into an additional commitment increase agreement
with certain of its lenders pursuant to which total commitments available under the Company’s revolving credit facility increased to $500 million through
March 27, 2019.
F-20
Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear
interest by reference only to the base rate. Until September 27, 2017, the ap plicable margin on LIBOR rate loans varie d from 2.75% to 3.25% and the applicable
margin on base rate loans varied from 1.75% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. Beginning September 27,
2017, the applic able margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each
case determined based on the Company’s excess availability under the credit facility. At December 31, 2017, the app licable margin on LIBOR rate loans was 3 .
50 % and the applicable margin on base rate loans was 2 . 50 %. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate
loans times the amount available to be drawn under outstand ing letters of credit. The commitment fee rate payable to the lenders for the unused portion of the
credit facility is 0.50%.
Each domestic subsidiary of the Company unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and the
Company arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no
material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1
million. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person
while such person is a lender or an affiliate of a lender under the Credit Agreement.
The Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 40%. The
Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus
consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit its
interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the
ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. The
Company was in compliance with these covenants at December 31, 2017.
The Credit Agreement limits the Company’s ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such
investments since September 27, 2012 is above 20% of the total consolidated book value of the assets of the Company and its subsidiaries on a pro forma basis, the
Company will not be able to make such investment. The Credit Agreement also restricts the Company’s ability to pay dividends and make equity repurchases,
subject to certain exceptions, including an exception allowing such restricted payments if before and immediately after giving effect to such restricted payment, the
Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) is at least 1.50 to 1.00. In addition, the Credit Agreement requires that, if the
consolidated cash balance of the Company and its subsidiaries, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing
is made, the Company can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such
proceeds are not used in such manner within three business days, the Company must repay such unused proceeds on the fourth business day following such
borrowings.
The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.
Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational
covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of
default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement,
(ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to
insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit.
As of December 31, 2017, the Company had $268 million outstanding under the revolving credit facility at a weighted average interest rate of 5.71%. The
Company had $4.6 million in letters of credit outstanding under its revolving credit facility at December 31, 2017 and, as a result, had available borrowing capacity
of $227 million at that date.
2015 Reimbursement Agreement — On March 16, 2015, the Company entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The
Bank of Nova Scotia (“Scotiabank”), pursuant to which the Company may from time to time request that Scotiabank issue an unspecified amount of letters of
credit. As of December 31, 2017, the Company had $54.9 million in letters of credit outstanding under the Reimbursement Agreement.
Under the terms of the Reimbursement Agreement, the Company will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under
any letters of credit. Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by the Company at the time of issuance at such
rates and amounts as are in accordance with Scotiabank’s prevailing practice. The Company is obligated to pay to Scotiabank interest on all amounts not paid by
the Company on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis
of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.
F-21
The Company has also agreed that if obligations under the Credit Agreement are secured by liens on any of its or any of its subsidiaries’ property, then the
Company’s reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the
Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.
Pursuant to a Continuing Guaranty dated as of March 16, 2015, the Company’s payment obligations under the Reimbursement Agreement are jointly and
severally guaranteed as to payment and not as to collection by subsidiaries of the Company that from time to time guarantee payment under the Credit Agreement.
Series A & B Senior Notes – On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.97%
Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The
Company pays interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.
On June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amounts of its 4.27% Series B Senior Notes due
June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. The Company pays interest on the
Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.
The Series A Notes and Series B Notes are senior unsecured obligations of the Company, which rank equally in right of payment with all other unsubordinated
indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of
the Company other than subsidiaries that are not required to be guarantors under the Credit Agreement.
The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment,
prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of
the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase
agreements. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes
upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the
purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.
The respective note purchase agreements require compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to
exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to
(b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal
quarter. The Company also must not permit its interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase
agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. The
Company was in compliance with these covenants at December 31, 2017.
Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational
covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA
events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing,
then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In
addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the
note purchase agreement to be immediately due and payable.
2028 Senior Notes – On January 19, 2018, the Company completed its offering of $525 million aggregate principal amount of the Company’s 2028 Notes
initially guaranteed on a senior unsecured basis by certain of its subsidiaries. The net proceeds before offering expenses were approximately $521 million of which
the Company used $239 million to repay amounts outstanding under its revolving credit facility. The Company intends to use the remainder of the net proceeds for
general corporate purposes.
The Company pays interest on the 2028 Notes on February 1 and August 1 of each year. The 2028 Notes will mature on February 1, 2028. The 2028 Notes
bear interest at a rate of 3.95% per annum.
F-22
The 2028 Notes are senior unsecured obligations of the Company, which rank equally with all of the Company’s other existing and future senior unsecured debt
and will rank senior in right of payment to all of the Compan y’s other future subordinated debt. The 2028 Notes will be effectively subordinated to any of the
Company’s future secured debt to the extent of the value of the assets securing such debt. In addition, the 2028 Notes will be structurally subordinated to the
liabilities (including trade payables) of the Company’s subsidiaries that do not guarantee the 2028 Notes. The guarantors’ guarantees of the 2028 Notes (the
“Guarantees”) will rank equally in right of payment with all of the guarantors’ future unsecur ed senior debt and senior in right of payment to all of the guarantors’
future subordinated debt. The Guarantees will be effectively subordinated to any of the guarantors’ future secured debt to the extent of the value of the assets
securing such debt. I n the future, the Guarantees may be released and terminated under certain circumstances.
The Company, at its option, may redeem the Notes in whole or part, at any time or from time to time at a redemption price equal to 100% of the principal
amount of such 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date, plus a make-whole
premium. Additionally, commencing on November 1, 2027, the Company, at its option, may redeem the 2028 Notes in whole or part, at a redemption price equal
to 100% of the principal amount of the 2028 Notes to be redeemed, plus accrued and unpaid interest, if any, on those 2028 Notes to the redemption date.
The indenture pursuant to which the 2028 Notes were issued includes covenants that, among other things, limit the Company and its subsidiaries’ ability to
incur certain liens, engage in sale and lease-back transactions or consolidate, merge, or transfer all or substantially all of their assets. These covenants are subject to
important qualifications and limitations set forth in the indenture.
Upon the occurrence of a change of control, as defined in the indenture, each holder of the 2028 Notes may require the Company to purchase all or a portion of
such holder’s 2028 Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The indenture also provides for events of default which, if any of them occurs, would permit or require the principal of, premium, if any, and accrued interest, if
any, on the 2028 Notes to become or to be declared due and payable.
The Company incurred approximately $6.0 million in debt issuance costs in connection with the Credit Agreement. The Company incurred approximately $1.9
million in debt issuance costs in connection with the Series A Notes and approximately $1.6 million in debt issuance costs in connection with the Series B Notes
. These costs were deferred and are being recognized as interest expense over the term of the underlying debt. Debt issuance costs, except those related to line-of-
credit arrangements, are presented in the balance sheet as a direct deduction from the carrying amount of the related debt. Debt issuance costs related to line-of-
credit arrangements are classified as a deferred charge. Amortization of debt issuance costs is reported as interest expense. Interest expense related to the
amortization of debt issuance costs was approximately $2.6 million, $4.1 million and $2.8 million for the years ended December 31, 2017, 2016 and 2015,
respectively. Amortization of debt issuance costs for the year ended December 31, 2016 includes $1.4 million of costs related to the early termination of the
previous term loan agreements.
Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2017 (in thousands):
Year ending December 31,
2018
2019
2020
2021
2022
Thereafter
Total
$
$
—
268,000
300,000
—
300,000
—
868,000
8. Commitments, Contingencies and Other Matters
Commitments – As of December 31, 2017, the Company maintained letters of credit in the aggregate amount of $59.5 million for the benefit of various
insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance
contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2017, no amounts had been drawn
under the letters of credit.
As of December 31, 2017, the Company had commitments to purchase approximately $172 million of major equipment for its drilling and pressure pumping
businesses.
The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. As
of December 31, 2017, the remaining obligation under these agreements was approximately $140 million, of which materials with a total purchase price of
approximately $35.9 million are required to be purchased during 2018. In the event that the required minimum quantities are not purchased during any contract
year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall.
F-23
Contingencies – The Company’s operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement
weather, blowouts, well fires, loss of well control, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage,
and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose the Company to
substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages.
Any contractual right to indemnification that the Company may have for any such risk may be unenforceable or limited due to negligent or willful acts of
commission or omission by the Company, its subcontractors and/or suppliers. In addition, certain states, including Louisiana, New Mexico, Texas and Wyoming,
have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield
service agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of the Company. The Company’s customers and other third
parties may dispute, or be unable to meet, their contractual indemnification obligations to the Company due to financial, legal or other reasons. Accordingly, the
Company may be unable to transfer these risks to its customers and other third parties by contract or indemnification agreements. Incurring a liability for which the
Company is not fully indemnified or insured could have a material adverse effect on its business, financial condition, cash flows and results of operations.
The Company has insurance coverage for fire, windstorm and other risks of physical loss to its rigs and certain other assets, employer’s liability, automobile
liability, commercial general liability, workers’ compensation and insurance for other specific risks. The Company has also elected in some cases to accept a
greater amount of risk through increased deductibles on certain insurance policies. For example, the Company generally maintains a $1.5 million per occurrence
deductible on its workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on its equipment insurance coverage, a $2.0 million per
occurrence deductible on its general liability coverage and a $2.0 million per occurrence deductible on its automobile liability insurance coverage. The Company
also self-insures a number of other risks, including loss of earnings and business interruption and cyber risks, and does not carry a significant amount of insurance
to cover risks of underground reservoir damage.
On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of the Company’s
employees. Based on the information the Company has available as of the date of this Report, the Company believes that it has adequate insurance to cover any
losses, excluding the applicable insurance deductibles and investigation-related expenses. However, if this accident is not, or another significant accident or other
event occurs that is not, fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on the
Company’s business, financial condition, cash flows and results of operations.
The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these
proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows.
Other Matters — The Company has Change in Control Agreements with its Chairman of the Board and one of its Executive Vice Presidents (the “Specified
Employees”). Each Change in Control Agreement generally has an initial term with automatic twelve-month renewals unless the Company notifies the Specified
Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the
term of the agreement and the Specified Employee’s employment is terminated (i) by the Company other than for cause or other than automatically as a result of
death, disability or retirement, or (ii) by the Specified Employee for good reason (as those terms are defined in the Change in Control Agreements), then the
Specified Employee shall generally be entitled to, among other things:
•
•
•
a bonus payment equal to the highest bonus paid after the Change in Control Agreement was entered into (such bonus payment for each Specified Employee
prorated for the portion of the fiscal year preceding the termination date);
a payment equal to 2.5 times (in the case of the Chairman of the Board) or 2 times (in the case of the Executive Vice President) of the sum of (i) the highest
annual salary in effect for such Specified Employee and (ii) the average of the three annual bonuses earned by the Specified Employee for the three fiscal
years preceding the termination date and
continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board) or two years (in the case of the
Executive Vice President).
Each Change in Control Agreement provides the Specified Employee with a full gross-up payment for any excise taxes imposed on payments and benefits
received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment.
F-24
The Company has Employment Agreements with its Chief Executive Officer, Chief Financial Officer, General Counsel and the President of the Company’s
subsidiary, Patterson-UTI Drilling Company LLC (“Patterson-UTI Drilling”) . In the case of the Chief Executive Officer and the General Counsel, the
Employment Agreement supersedes the prior Change in Control Agreement with each executive and, in the case of the President of Patterson-UTI Drilling, the
Employment Agreement super sedes his prior employment agreement. Each Employment Agreement generally has an initial three-year term, subject to automatic
annual renewal. The executive may terminate his employment under his Employment Agreement by providing written notice of such t ermination at least 30 days
before the effective date of such termination. Under specified circumstances, the Company may terminate the executive’s employment under his Employment
Agreement for Cause (as defined in the Employment Agreement) by either (i) providing written notice 10 days before the effective date of such termination and by
granting at least 10 days to cure the cause for such termination or (ii) by providing written notice of such termination at least 30 days before the effective date of
suc h termination and by granting at least 20 days to cure the cause for such termination, provided that if the matter is reasonably determined by the Company to
not be capable of being cured, the executive may be terminated for cause on the date the written n otice is delivered. The Employment Agreement also provides
for, among other things, severance payments and the continuation of certain benefits following termination by the Company of the executive other than for Cause,
or termination by the executive for Good Reason (as defined in each Employment Agreement). Under these provisions, if the executive’s employment is
terminated by the Company without Cause, or the executive terminates his employment for Good Reason :
•
•
•
•
the executive will have the right to receive a lump-sum payment consisting of 3 times (in the case of the Chief Executive Officer) or 2.5 times (in the case of
the Chief Financial Officer, General Counsel and President of Patterson-UTI Drilling) the sum of (i) his base salary and (ii) the average annual cash bonus
received by him for the three years prior to the date of termination;
the executive will have the right to receive a pro-rated lump-sum payment equal to his annual cash bonus based on actual results for the year, payable at the
same time as annual cash bonuses are paid to active employees,
the Company will accelerate vesting of all options and restricted stock awards on the 60th day following the executive’s termination, and
the Company will pay the executive certain accrued obligations and certain obligations pursuant to the terms of employee benefit plans.
If a termination by the Company other than for Cause or by the executive for Good Reason occurs following a Change in Control (as defined in his
Employment Agreement, which for the President of Patterson-UTI Drilling includes a change in control of the Company or, in certain circumstances, of Patterson-
UTI Drilling), the executive will generally be entitled to the same severance payments and benefits described above except that the pro-rated lump-sum payment
for annual cash bonuses will be based on his highest annual cash bonus for the last three years, and the executive will be entitled to 36 months (in the case of the
Chief Executive Officer) or 30 months (in the case of the Chief Financial Officer, General Counsel and President of Patterson-UTI Drilling) of subsidized benefits
continuation coverage.
9. Stockholders’ Equity
Stock Offering – On January 27, 2017, the Company completed an offering of 18.2 million shares of its common stock and raised net proceeds of
$472 million. The Company used the net proceeds of the offering to repay SSE’s outstanding indebtedness of approximately $472 million.
F-25
Cash Dividends – The Company paid cash dividends during the years ended December 31, 2017, 2016 and 2015 as follows:
2017
Paid on March 22, 2017
Paid on June 22, 2017
Paid on September 21, 2017
Paid on December 21, 2017
Total cash dividends
2016
Paid on March 24, 2016
Paid on June 23, 2016
Paid on September 22, 2016
Paid on December 22, 2016
Total cash dividends
2015
Paid on March 25, 2015
Paid on June 24, 2015
Paid on September 24, 2015
Paid on December 24, 2015
Total cash dividends
Per Share
Total
(in thousands)
0.02
0.02
0.02
0.02
0.08
0.10
0.02
0.02
0.02
0.16
0.10
0.10
0.10
0.10
0.40
$
$
$
$
$
$
3,326
4,269
4,271
4,449
16,315
14,712
2,953
2,953
2,961
23,579
14,640
14,712
14,712
14,711
58,775
$
$
$
$
$
$
On February 7, 2018, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.02 per share to be paid on
March 22, 2018 to holders of record as of March 8, 2018. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board
of Directors and will depend upon business conditions, results of operations, financial condition, terms of the Company’s debt agreements and other factors.
On September 6, 2013, the Company’s Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of the Company’s
common stock in open market or privately negotiated transactions. All purchases to date have been through open market transactions. Purchases under the program
are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be made at any time without prior notice.
Shares of stock purchased under the plan are held as treasury shares. There is no expiration date associated with the buyback program. As of December 31, 2017,
the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under the 2013 stock buyback
program.
The Company acquired shares of stock from directors during 2017 and 2016 and from employees during 2017, 2016 and 2015 that are accounted for as treasury
stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options. The remainder of these shares was
acquired to satisfy payroll withholding obligations upon the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired
at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan (the “2014 Plan”) and
not pursuant to the stock buyback program.
Treasury stock acquisitions during the years ended December 31, 2017, 2016 and 2015 were as follows (dollars in thousands):
Treasury shares at beginning of period
Purchases pursuant to 2013 stock buyback program
Acquisitions pursuant to long-term incentive plan
Treasury shares at end of period
10. Stock-based Compensation
2017
Shares
43,392,617
5,503
404,491
43,802,611
$
$
2016
2015
Cost
911,094
109
7,508
918,711
Shares
43,207,240
8,488
176,889
43,392,617
$
$
Cost
907,045
183
3,866
911,094
Shares
42,818,585
8,618
380,037
43,207,240
$
$
Cost
899,035
180
7,830
907,045
The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments
under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have
included service and, in certain cases, performance conditions. The Company issues shares of common stock when vested stock options are exercised, when
restricted stock is granted and when restricted stock units and share-settled performance unit awards vest.
F-26
The 2014 Plan was originally approved by the Company’s stockholders effective as of April 17, 2014 , and the Board of Directors adopted a resolution that no
future grants would be made und er any of the Company’s other previously existing plans. On June 29, 2017, the Company’s stockholders approved the
amendment and restatement of the 2014 Plan (the “Amended and Restated Plan”) to increase the number of shares available under the plan to 10 ,049,156
shares. The aggregate number of shares of the Company’s c ommon s tock authorized for grant under the Amended and Restated Plan is 18.9 million, which
includes 9.1 million shares previously authorized under the 2014 Plan . The Company’s share-based compensation plans at December 31, 2017 are as follows:
Plan Name
Amended and Restated Plan
Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended
A summary of the Amended and Restated Plan follows:
Shares
Authorized
for Grant
Shares Underlying
Awards
Outstanding
Shares
Available
for Grant
18,900,000
—
5,286,459
3,804,500
7,647,874
—
• The Compensation Committee of the Board of Directors administers the plan other than the awards to directors.
• All employees, officers and directors are eligible for awards.
• The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and three years
for employees.
• The Compensation Committee sets the term of awards and no option term can exceed 10 years.
• All options granted under the plan are granted with an exercise price equal to or greater than the fair market value of the Company’s common stock at the
time the option is granted.
• The plan provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock
awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents. As of December 31, 2017, non-incentive
stock options, restricted stock awards, restricted stock units and performance unit awards had been granted under the plan.
Options granted under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) typically vested over one year for non-employee
directors and three years for employees. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of
grant. Restricted stock awards granted under the 2005 Plan typically vested over one year for non-employee directors and three years for employees.
Stock Options— The Company estimates the grant date fair values of stock options using the Black-Scholes-Merton valuation model. Volatility assumptions
are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options
are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions
are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States
Treasury yields. No options were granted during the year ended December 31, 2017. Weighted-average assumptions used to estimate grant date fair values for
stock options granted during the years ended December 31, 2016 and 2015 are as follows:
Volatility
Expected term (in years)
Dividend yield
Risk-free interest rate
Stock option activity for the year ended December 31, 2017 follows:
Outstanding at beginning of year
Exercised
Expired
Outstanding at end of year
Exercisable at end of year
F-27
2016
2015
35.11%
5.00
2.05%
1.40%
37.95%
5.00
2.00%
1.37%
Shares
Weighted-average
exercise price
6,687,150
(50,000)
(600,000)
6,037,150
5,515,968
$
$
$
$
$
20.68
18.63
24.17
20.35
20.49
Options outstanding at December 31, 2017 have an aggregate intrinsic value of approximately $ 25.9 million and a weighted-average remaining contractual
term of 4.65 years. Options exercisable at December 31, 2017 have an aggregate intrinsic value of approximately $ 23.7 million and a weighted-average
remaining contractual term of 4. 3 1 years. Additional information with respect to options granted, vested and exercised during the years ended December 31, 2017,
2016 and 2015 follows:
Weighted-average grant date fair value of stock options granted (per share)
Aggregate grant date fair value of stock options vested during the year
(in thousands)
Aggregate intrinsic value of stock options exercised (in thousands)
2017
2016
2015
NA
$
4.90
$
$
$
4,565
209
$
$
4,729
366
$
$
5.79
5,077
—
As of December 31, 2017, options to purchase 521,182 shares were outstanding and not vested. All of these non-vested options are expected to ultimately vest.
Additional information as of December 31, 2017 with respect to these non-vested options follows:
Aggregate intrinsic value
Weighted-average remaining contractual term
Weighted-average remaining expected term
Weighted-average remaining vesting period
Unrecognized compensation cost
$2.1 million
8.2 years
3.2 years
1.4 years
$2.6 million
Restricted Stock— For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to
forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted
stock. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period.
Restricted stock activity for the year ended December 31, 2017 follows:
Non-vested restricted stock outstanding at beginning of year
Granted
Vested
Forfeited
Non-vested restricted stock outstanding at end of year
Shares
1,427,455
890,904
(764,213)
(23,808)
1,530,338
$
$
$
$
$
Weighted-
average Grant
Date Fair Value
22.26
21.78
23.40
22.34
21.41
As of December 31, 2017, approximately 1.5 million shares of non-vested restricted stock outstanding are expected to vest. Additional information as of
December 31, 2017 with respect to these non-vested shares follows:
Aggregate intrinsic value
Weighted-average remaining vesting period
Unrecognized compensation cost
$34.0 million
1.3 years
$19.6 million
Restricted Stock Units— For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are
subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable cash dividend equivalents are paid on
certain non-vested restricted stock units, and forfeitable dividend equivalents are accrued on certain other restricted stock units that will be paid upon vesting. The
Company uses the straight-line method to recognize periodic compensation cost over the vesting period.
Restricted stock unit activity for the year ended December 31, 2017 follows:
Non-vested restricted stock units outstanding at beginning of year
Granted
Assumed (1)
Vested
Forfeited
Non-vested restricted stock units outstanding at end of year
Shares
191,655
1,238,692
505,551
(549,451)
(49,174)
1,337,273
$
$
$
$
$
$
Weighted-average
Grant Date Fair
Value
19.85
19.85
22.45
22.24
21.26
19.80
(1)
Restricted stock unit awards under the Seventy Seven Energy Inc. 2016 Omnibus Incentive Plan, which was adopted, assumed, amended and renamed by
the Company in connection with the SSE merger. No additional awards will be made under this plan.
F-28
Performance Unit Awards. The Company has granted share-settled performance unit awards to certain executive officers (the “Performance Units”) on an
annual basis since 2010. The Performance Units provide for the recipients to receive a grant of shares of common stock upon the a chievement of certain
performance goals during a specified period established by the Compensation Committee. The performance period for the Performance Units is the three year
period commencing on April 1 of the year of grant, except that for the Performa nce Units granted in 2013 the performance period was extended pursuant to its
terms, as described below, and for the Performance Units granted in 2017 the three-year performance period commenced on May 1.
The performance goals for the Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total
shareholder return for a peer group determined by the Compensation Committee. These goals are considered to be market conditions under the relevant accounting
standards and the market conditions were factored into the determination of the fair value of the respective Performance Units. Generally, the recipients will receive
a target number of shares if the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 50 th percentile. If
the Company’s total shareholder return during the performance period, when compared to the peer group, is at the 75 th percentile or higher, then the recipients will
receive two times the target number of shares. If the Company’s total shareholder return during the performance period, when compared to the peer group, is at the
25 th percentile, the recipients will only receive one-half of the target number of shares. If the Company’s total shareholder return during the performance period,
when compared to the peer group, is between the 25 th and 75 th percentile, then the shares to be received by the recipients will be determined on a pro-rata basis.
For the Performance Units awarded prior to 2016, there is no payout unless the Company’s total shareholder return is positive and, when compared to the peer
group, is at or above the 25 th percentile. In respect of the 2013 Performance Units, for which the performance period ended March 31, 2016, the Company’s total
shareholder return for the performance period was negative, the Company’s total shareholder return for the performance period when compared to the peer group
was above the 75 th percentile, and there was no payout; provided, however, that pursuant to the terms of those 2013 awards, if, during the two-year period ending
March 31, 2018, the Company’s total shareholder return for any 30 consecutive day period equals or exceeds 18 percent on an annualized basis from April 1, 2013
through the last day of such 30 consecutive day period, and the recipient is actively employed by the Company through the last day of the extended performance
period, then the Company will issue to the recipient the number of shares equal to the amount the recipient would have been entitled to receive had the Company’s
total shareholder return been positive during the initial three-year performance period.
For the Performance Units granted in April 2016, if the Company’s total shareholder return is negative, and, when compared to the peer group is at or above the
25th percentile, then the recipients will receive one-half of the number of shares they would have received had the Company’s total shareholder return been
positive. For the Performance Units granted in May 2017, the payout is based on relative performance and does not have an absolute performance requirement.
The total target number of shares with respect to the Performance Units for the years 2012-2017 is set forth below:
Target number of shares
2017
Performance
Unit Awards
186,198
2016
Performance
Unit Awards
185,000
2015
Performance
Unit Awards
190,600
2014
Performance
Unit Awards
154,000
2013
Performance
Unit Awards
236,500
2012
Performance
Unit Awards
192,000
The 2012 Performance Units settled with an 87th total shareholder return percentile and 384,000 shares were issued. The 2014 Performance Units settled with
an 89 th total shareholder return percentile and a negative total shareholder return, so there was no payout under such Performance Units.
Because the Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte
Carlo simulation model. The fair value of the Performance Units is set forth below (in thousands):
Aggregate fair value at date of grant
2017
Performance
Unit Awards
5,780
$
2016
Performance
Unit Awards
3,854
$
2015
Performance
Unit Awards
4,052
$
2014
Performance
Unit Awards
5,388
$
2013
Performance
Unit Awards
5,564
$
2012
Performance
Unit Awards
3,065
$
These fair value amounts are charged to expense on a straight-line basis over the performance period. Compensation expense associated with the Performance
Units is set forth below (in thousands):
Year ended December 31, 2017
Year ended December 31, 2016
Year ended December 31, 2015
2017
Performance
Unit Awards
1,284
$
NA
NA
2016
Performance
Unit Awards
1,285
$
963
$
NA
2015
Performance
Unit Awards
1,351
$
1,351
$
1,013
2014
Performance
Unit Awards
$
449
1,796
$
1,796
$
2013
Performance
Unit Awards
NA
464
1,855
$
$
2012
Performance
Unit Awards
NA
NA
255
$
F-29
Dividends on Equity Awards – Non-forfeitable cash dividends are paid on restricted stock awards and dividend equivalents are paid or accrued on certain
restricted stock units. These dividends are recognized as follows:
• Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest.
• Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do not
vest.
• Dividend equivalents are recognized as reductions of retained earnings for the portion of restricted stock units expected to vest.
• Dividend equivalents are recognized as additional compensation cost for the portion of restricted stock units that are not expected to vest or that ultimately
do not vest.
11. Leases
The Company incurred rent expense of $48.9 million, $25.3 million and $37.6 million for the years ended December 31, 2017, 2016 and 2015,
respectively. Rent expense is primarily related to short-term equipment rentals that are generally passed through to customers.
Future minimum rental payments required under operating leases having initial or remaining non-cancelable lease terms in excess of one year at December 31,
2017 are as follows (in thousands):
Year ending December 31,
2018
2019
2020
2021
2022
Thereafter
Total
12. Income Taxes
$
$
13,616
9,368
7,112
5,165
3,844
8,917
48,022
Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2017, 2016 and 2015 are as
follows (in thousands):
Federal income tax benefit:
Current
Deferred
State income tax expense (benefit):
Current
Deferred
Foreign income tax expense (benefit):
Current
Deferred
Total income tax benefit:
Current
Deferred
Total income tax benefit:
2017
2016
2015
$
$
(42)
(335,106)
(335,148)
$
(24,777)
(134,592)
(159,369)
(215)
4,511
4,296
(3,108)
249
(2,859)
(257)
(14,163)
(14,420)
(368)
(3,405)
(3,773)
(3,365)
(330,346)
(333,711)
$
(25,402)
(152,160)
(177,562)
$
$
(42,020)
(83,812)
(125,832)
(3,480)
(12,433)
(15,913)
(2,590)
(3,628)
(6,218)
(48,090)
(99,873)
(147,963)
F-30
The difference between the statutory federal income tax rate and the effective income tax rate for the years ended December 31, 2017, 2016 and 2015 is
summarized as follows:
Statutory tax rate
State income taxes - net of the federal income tax benefit
Permanent differences
One-time tax effects of tax reform
Share-based payments
Acquisition related differences
Other differences, net
Effective tax rate
2017
2016
2015
35.0%
1.9
(1.3)
66.7
3.6
(3.3)
(0.8)
101.8%
35.0%
2.0
(0.1)
—
—
—
(1.1)
35.8%
35.0%
2.1
(1.3)
—
—
—
(2.4)
33.4%
The effective tax rate increased by approximately 66.0% to 101.8% for 2017 compared to 2016, primarily due to a 66.7% increase related to tax reform enacted
on December 22, 2017 and a 3.6% increase for excess tax benefits from employee stock compensation deductions. These increases were partially offset by a 3.3%
decrease in the effective tax rate for acquisitions that resulted in the revaluation of deferred tax assets and liabilities at the new state tax rates at which they are
expected to reverse. The lower 2015 effective tax rate is primarily related to the impact of goodwill impairment charges in 2015, along with an adjustment to the
Company’s deferred tax liability associated with the 2010 conversion of its Canadian operations to a controlled foreign corporation.
Tax reform reduces the U.S. federal corporate tax rate from 35% to 21% beginning in 2018, requires companies to pay a one-time transition tax on foreign
earnings that were previously tax deferred, creates new taxes on future foreign earnings, places a new limitation on the tax deductibility of interest expense,
accelerates the expensing of certain business assets, and reduces the amount of executive pay that will be tax deductible, among other changes. Based on a reduced
U.S. federal corporate tax rate of 21% from tax reform, the Company remeasured certain deferred tax assets and liabilities at the tax rates at which they are
expected to reverse in the future. Due to the limited time to consider tax reform and its various interpretations, the Company is still analyzing and refining its
calculations, which could potentially affect the measurement of these balances or give rise to new deferred tax amounts, however, in certain cases, the Company
has made a reasonable estimate of the effects on its existing deferred tax balances and the one-time transition tax. For the items for which the Company was able to
determine a reasonable estimate, it recognized a provisional amount, in accordance with SAB 118, of approximately $219 million of tax benefit, which is included
as a component of income tax expense from continuing operations resulting in the above impact to the Company’s 2017 effective income tax rate.
The one-time transition tax is based on the total post-1986 earnings and profits (E&P) of the Company’s foreign operation which it has previously deferred
from U.S. income taxes. Based on its current analysis, the Company has estimated an E&P deficit and therefore has not recorded any additional taxes for the one-
time transition tax. The Company notes that its analysis of the transition tax is provisional and represents a reasonable estimate resulting from the mandatory
deemed repatriation of its post-1986 untaxed foreign E&P. Determining the provisional transition tax required a significant number of steps, including determining
the composition of the Company’s post-1986 untaxed foreign E&P that is held in cash or liquid assets and other assets at several measurement dates, as a different
rate is applied to each when determining the transition tax liability, and analyzing the Company’s accumulated foreign post-1986 E&P, including historical
practices and assertions. As a result of these factors, as well as the proximity of the enactment of tax reform to its year-end, the Company had limited time to
consider tax reform and its various interpretations and has not completed its calculation of the total post-1986 E&P amounts of its foreign operations. Adjustments
to the Company’s estimates may occur once it finalizes these calculations.
Prior to tax reform, the Company had elected to permanently reinvest unremitted earnings in Canada effective January 1, 2010, and it intended to do so for the
foreseeable future. As a result, no deferred United States federal or state income taxes had been provided on such unremitted foreign earnings. With the enactment
of tax reform, there is a new territorial tax system that provides for a 100% dividends received deduction on future earnings, if remitted. However, the Company
will need to continue to evaluate its reinvestment intentions on future earnings and any other residual basis differences in order to determine whether it can continue
to assert indefinite reinvestment or whether it will be required to provide for additional taxes that would be due on future earnings if remitted, such as foreign
withholding taxes or state and local taxes. The Company will also need to determine whether it will be required to provide for additional taxes on any other outside
basis differences in its foreign operations. Due to the limited time to consider these provisions, the Company is still evaluating how tax reform will affect its
existing accounting position to indefinitely reinvest unremitted foreign earnings. The Company will continue to assert permanent reinvestment with respect to
future unremitted earnings and has not recorded any deferred federal or state income taxes that would be provided on future unremitted earnings. The Company
will finalize its intentions on whether it will permanently reinvest its foreign unremitted earnings within the measurement period provided under SAB 118.
F-31
Tax reform also introduced a new GILTI U.S. tax on certain off-shore earnings at an effective tax rate of 10.5 % for tax years beginning after December 31,
2017 (increasing to 13.125% for tax years beginning after December 31, 2025) with a partial offset for any related foreign tax credits. The Company is still
evaluating the GILTI provisions of t ax reform and its impact, if any, on the Company’s consolidated financial statements at December 31, 2017. The FASB staff
allowed companies to adopt an accounting policy to either provide deferred taxes for GILTI or treat it as a tax cost in the year incurred. Th e Company has not yet
determined its accounting policy because determining the impact of the GILTI provisions requires analysis of its existing legal entity structure, the reversal of
differences in the assets and liabilities of its foreign subsidiaries, a nd its ability to offset any tax with foreign tax credits. As such, the Company did not record a
deferred income tax expense or benefit related to the GILTI provisions in its c onsolidated s tatement of o perations for the year ended December 31, 2017 and wi
ll finalize its evaluation of the GILTI provisions during the measurement period provided under SAB 118.
In addition to the provisions above, the tax reform also changed the individuals whose compensation is subject to a $1 million cap on deductibility under
Section 162(m) and includes performance-based compensation such as stock options and stock appreciation rights in the calculation. For taxable years beginning
before December 31, 2017, a public company had been able to deduct up to $1 million of compensation paid to covered employees consisting of the chief executive
officer and the next three highest compensated officers, but not the chief financial officer (CFO). However, the limit did not apply to performance-based
compensation. The new law expands the definition of covered employees to include the CFO and any individual who has been considered a covered employee,
even if that individual is no longer a covered employee. Thus, once an individual is a covered employee, the deduction limitation applies to compensation paid to
that individual at any point in the future, including after a separation from service. Any individual who is a covered employee for a tax year after December 31,
2016 will remain a covered employee for all future years. The law also eliminates the exception for performance-based compensation. The provision generally
applies to taxable years beginning after December 31, 2017 and provides a transition for compensation paid pursuant to a written binding contract that is in effect
on November 2, 2017. The Company will need to carefully review the terms of its compensation plans and agreements to assess whether such plans and
agreements are considered to be written binding contracts in effect on November 2, 2017. Due to the complexity of applying this new provision and the limited
time to consider tax reform, the Company has not yet completed its analysis of these new provisions and will finalize its analysis during the measurement period
provided under SAB 118.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, "Compensation-Stock Compensation". The new standard was effective for the
Company on January 1, 2017. Among other provisions, the new standard requires that excess tax benefits and tax deficiencies that arise upon vesting or exercise of
share-based payments be recognized as income tax benefits and expenses in the income statement. Previously, such amounts were recorded to additional paid-in-
capital. This aspect of the new guidance was required to be adopted prospectively. The effective income tax rate for the year ended December 31, 2017 includes
approximately $12 million of excess tax benefits from share-based compensation awards that vested or were exercised during the period.
During 2017, there was significant merger and acquisition activity by the Company. Based on this activity, an evaluation was made of the Company’s overall
state deferred tax rate, resulting in a slightly increased rate. The Company remeasured certain deferred tax assets and liabilities at the tax rates at which they are
expected to reverse in the future and recorded additional taxes of approximately $11 million, impacting the 2017 effective income tax rate.
The tax effect of significant temporary differences representing deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows (in thousands):
Deferred tax assets:
Net operating loss carryforwards
Alternative minimum tax credit
Scientific research and experimental development tax credit
Expense associated with stock options and restricted stock
Workers' compensation allowance
Federal benefit of state deferred tax liabilities
Other
Total deferred tax assets
Deferred tax liabilities:
Property and equipment basis difference
Other
Total deferred tax liabilities
Net deferred tax liability
F-32
2017
2016
$
$
285,542 $
7,907
898
12,338
19,662
5,660
27,066
359,073
(695,111)
(10,923)
(706,034)
(346,961) $
203,485
7,907
—
17,116
26,157
5,310
14,998
274,973
(911,972)
(9,538)
(921,510)
(646,537)
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets
will not be realized, and necessary allowances are provided. The ultimate realization of deferr ed tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. Management considers the Company’s carryback availability, the scheduled
reversal of deferred tax liabilitie s, projected future taxable income and tax planning strategies in making this assessment. The Company expects the full carrying
value of its deferred tax assets at December 31, 2017 and 2016 to be realized as a result of the timing of the reversal s of its existing taxable temporary differences ,
which will give rise to taxable income and offset deductible temporary differences in the permitted carryforward periods. As of December 31, 2017 , the Company
does not consider a valuation allowance necessary.
Other deferred tax assets consist primarily of the tax effect of various allowance accounts and tax-deferred expenses expected to generate future tax benefits of
approximately $27.1 million. Other deferred tax liabilities of approximately $10.9 million consists primarily of the tax effect of receivables from insurance
companies and tax-deferred income not yet recognized for tax purposes.
For income tax purposes, the Company has approximately $1.1 billion of gross federal net operating losses, approximately $19.2 million of Canadian net
operating losses and approximately $678 million of post-apportionment state net operating losses as of December 31, 2017. Of these amounts, approximately
$11 million of Canadian and $1 million of state losses will be carried back to prior years and the remaining balance can be carried forward to future years. Net
operating losses that can be carried forward, if unused, are scheduled to expire as follows: 2023—$137,000; 2024—$2.4 million; 2025—$2.8 million; 2026—
$17.4 million; 2027—$102,000; 2029—$33.2 million; 2030—$28.6 million; 2031—$101.9 million; 2032—$9.7 million; 2034—$30,000; 2035—$302.7 million,
2036 - $644.6 million; and 2037—$647.1 million.
As of December 31, 2017, the Company had no unrecognized tax benefits. The Company has established a policy to account for interest and penalties related
to uncertain income tax positions as operating expenses. As of December 31, 2017, the tax years ended December 31, 2013 through December 31, 2016 are open
for examination by U.S. taxing authorities. As of December 31, 2017, the tax years ended December 31, 2013 through December 31, 2016 are open for
examination by Canadian taxing authorities.
13. Employee Benefits
The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses of approximately $8.7 million in 2017,
$4.4 million in 2016 and $7.1 million in 2015 for the Company’s contributions to the plan.
14. Business Segments
At December 31, 2017, the Company had three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii)
directional drilling services. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the
Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes
of determining resource allocation and assessing performance.
Contract Drilling — The Company markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2017, the
Company had 295 marketed land-based drilling rigs in the continental United States and western Canada.
For the years ended December 31, 2017, 2016 and, 2015, contract drilling revenue earned in Canada was $13.7 million, $15.6 million and $37.5 million,
respectively. Additionally, long-lived assets within the contract drilling segment located in Canada totaled $52.0 million and $44.0 million as of December 31,
2017 and 2016, respectively.
Pressure Pumping — The Company provides pressure pumping services to oil and natural gas operators primarily in Texas and the Mid-Continent and
Appalachian regions. Pressure pumping services are primarily well stimulation services (such as hydraulic fracturing) and cementing services for the completion of
new wells and remedial work on existing wells. Well stimulation involves processes inside a well designed to enhance the flow of oil, natural gas, or other desired
substances from the well. Cementing is the process of inserting material between the wall of the well bore and the casing to support and stabilize the casing.
Directional Drilling — The Company provides a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the
United States.
Major Customer — During 2017, no single customer accounted for more than 10% of the Company’s consolidated operating revenues. During 2016, one
customer accounted for approximately $124 million or 14% of the Company’s consolidated operating revenues. During 2015, one customer accounted for
approximately $244 million or 13% of the Company’s consolidated operating revenues. These revenues in 2015 and 2016 were earned in both the Company’s
contract drilling and pressure pumping businesses.
F-33
The following tables summari ze selected financial information relating to the Company’s business segments (in thousands):
2017
Year Ended December 31,
2016
2015
Revenues:
Contract drilling
Pressure pumping
Directional drilling
Other operations(a)
Elimination of intercompany revenues(b)
Total revenues
Income (loss) before income taxes:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate
Other operating income (expense), net (c)
Interest income
Interest expense
Other
Loss before income taxes
Identifiable assets:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate(d)
Total assets
Depreciation, depletion, amortization and impairment:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate
Total depreciation, depletion, amortization and impairment
Capital expenditures:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate
Total capital expenditures
$
$
$
$
$
$
$
$
$
$
1,041,492 $
1,200,311
45,580
76,781
(7,480)
2,356,684 $
(171,897) $
21,028
(21)
(20,813)
(152,792)
31,957
1,866
(37,472)
343
(327,801) $
544,196 $
354,070
—
18,299
(699)
915,866 $
(235,858) $
(176,628)
—
(3,391)
(54,672)
14,323
327
(40,366)
69
(496,196) $
3,931,994 $
1,209,424
301,275
172,094
144,069
5,758,856 $
3,032,819 $
653,630
—
48,885
36,957
3,772,291 $
538,891 $
198,006
9,347
29,402
7,695
783,341 $
354,425 $
171,436
7,795
31,547
1,884
567,087 $
467,974 $
184,872
—
10,114
5,474
668,434 $
72,508 $
39,584
—
6,116
1,591
119,799 $
1,155,565
712,454
—
24,931
(1,673)
1,891,277
(78,970)
(254,998)
—
(14,269)
(57,088)
(1,647)
964
(36,475)
34
(442,449)
3,457,044
813,704
—
38,726
155,574
4,465,048
618,434
214,552
—
26,301
5,472
864,759
527,054
197,577
—
16,625
2,520
743,776
( a)
(b)
(c)
(d)
Other operations includes the Company’s oilfield rental tools business, pipe handling components and related technology business, the oil and natural gas working
interests and the Middle East/North Africa activities.
In 2017, intercompany revenues consists of contract drilling and revenues from other operations for services provided to contract drilling, pressure pumping and within
other operations. In 2016, intercompany revenues consists of contract drilling and revenues within other operations. In 2015, intercompany revenues only consisted of
contract drilling.
Other operating income (expense), net includes net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive
management group. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments. This caption also
includes expenses related to certain legal settlements net of insurance reimbursements.
Corporate assets primarily include cash on hand, income tax receivables, certain property and equipment, and certain deferred tax assets.
F-34
15. Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of demand deposits, temporary cash investments
and trade receivables.
The Company believes it has placed its demand deposits and temporary cash investments with high credit-quality financial institutions. At December 31, 2017
and 2016, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands):
Deposits in FDIC and SIPC-insured institutions under insurance limits
Deposits in FDIC and SIPC-insured institutions over insurance limits
Deposits in foreign banks
Less outstanding checks and other reconciling items
Cash and cash equivalents
2017
2016
$
$
13,860 $
106,849
21,479
142,188
(99,360)
42,828 $
846
12,866
27,557
41,269
(6,117)
35,152
Concentrations of credit risk with respect to trade receivables are primarily focused on companies involved in the exploration and development of oil and
natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides services. As is general
industry practice, the Company typically does not require customers to provide collateral. No significant losses from individual customers were experienced during
the years ended December 31, 2017, 2016 or 2015. No expense for bad debts was recognized in 2017, 2016 or 2015.
16. Fair Values of Financial Instruments
The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these
items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting.
The estimated fair value of the Company’s outstanding debt balances as of December 31, 2017 and 2016 is set forth below (in thousands):
Borrowings under Credit Agreement:
Revolving credit facility
4.97% Series A Senior Notes
4.27% Series B Senior Notes
Total debt
December 31, 2017
December 31, 2016
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
$
$
268,000
300,000
300,000
868,000
$
$
268,000
303,966
295,616
867,582
$
$
—
300,000
300,000
600,000
$
$
—
283,534
263,194
546,728
The carrying value of the balances outstanding under the revolving credit facility approximates its fair values as this instrument has floating interest rates. The
fair values of the Series A Notes and Series B Notes at December 31, 2017 and 2016 are based on discounted cash flows associated with the respective notes using
current market rates of interest at those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.46% at
December 31, 2017 and 6.65% at December 31, 2016. For the Series B Notes, the current market rates used in measuring this fair value were 4.64% at
December 31, 2017 and 7.02% at December 31, 2016. These fair value estimates are based on observable market inputs and are considered Level 2 fair value
estimates in the fair value hierarchy of fair value accounting.
F-35
17. Quarterly Financial Information (in thousands, except per share amounts) (unaudited)
2017
Operating revenues
Operating loss
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
2016
Operating revenues
Operating loss
Net loss
Net loss per common share:
Basic
Diluted
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
305,175 $
(92,639)
(63,539)
579,186 $
(140,236)
(92,184)
684,989 $
(38,016)
(33,769)
(0.40) $
(0.40) $
(0.46) $
(0.46) $
(0.16) $
(0.16) $
787,334
(21,647)
195,402
0.88
0.88
268,939 $
(95,259)
(70,503)
193,907 $
(124,332)
(85,866)
206,133 $
(123,409)
(84,143)
246,887
(113,226)
(78,122)
(0.48) $
(0.48) $
(0.58) $
(0.58) $
(0.58) $
(0.58) $
(0.53)
(0.53)
$
$
$
$
$
$
F-36
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Description
Year Ended December 31, 2017
Deducted from asset accounts:
Allowance for doubtful accounts
Year Ended December 31, 2016
Deducted from asset accounts:
Allowance for doubtful accounts
Year Ended December 31, 2015
Deducted from asset accounts:
Allowance for doubtful accounts
(1)
Consists of uncollectible accounts written off.
Beginning
Balance
Charged to
Costs and
Expenses
Deductions(1)
Ending
Balance
(In thousands)
3,191 $
— $
(868) $
2,323
3,545 $
— $
(354) $
3,191
3,546 $
— $
(1) $
3,545
$
$
$
S-1
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form
10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
PATTERSON-UTI ENERGY, INC.
By:
/s/ William Andrew Hendricks, Jr.
William Andrew Hendricks, Jr.
President and Chief Executive Officer
Date: February 20, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report on Form 10-K has been signed by the following persons on behalf of
Patterson-UTI Energy, Inc. and in the capacities indicated as of February 20, 2018.
Signature
/s/ Mark S. Siegel
Mark S. Siegel
/s/ William Andrew Hendricks, Jr.
William Andrew Hendricks, Jr.
(Principal Executive Officer)
/s/ C. Andrew Smith
C. Andrew Smith
(Principal Financial and Accounting Officer)
/s/ Charles O. Buckner
Charles O. Buckner
/s/ Michael W. Conlon
Michael W. Conlon
/s/ Curtis W. Huff
Curtis W. Huff
/s/ Terry H. Hunt
Terry H. Hunt
/s/ Tiffany J. Thom
Tiffany J. Thom
S-2
Title
Chairman of the Board
President, Chief Executive Officer
and Director
Executive Vice President and
Chief Financial Officer
Director
Director
Director
Director
Director
Exhibit
4.2
REGISTRATION RIGHTS AGREEMENT
between
PATTERSON-UTI ENERGY, INC.
and
THE SELLERS PARTY HERETO
Dated as of October 6, 2017
TABLE OF CONTENTS
ARTICLE I DEFINITIONS
Section 1.1
Section 1.2
Definitions
Registrable Securities
ARTICLE II REGISTRATION RIGHTS
Section 2.1
Section 2.2
Section 2.3
Section 2.4
Section 2.5
Section 2.6
Section 2.7
Section 2.8
Section 2.9
Shelf Registration
Piggyback Registration
Sale Procedures
Cooperation by Holders
Restrictions on Public Sale by Holders of Registrable Securities
Expenses
Indemnification
Transfer or Assignment of Registration Rights
Aggregation of Registrable Securities
ARTICLE III MISCELLANEOUS
Section 3.1
Section 3.2
Section 3.3
Section 3.4
Section 3.5
Section 3.6
Section 3.7
Section 3.8
Section 3.9
Section 3.10
Section 3.11
Section 3.12
Section 3.13
Communications
Successors and Assigns
Assignment of Rights
Recapitalization (Exchanges, etc. Affecting the Common Stock)
Enforcement
Counterparts
Governing Law, Submission to Jurisdiction
Waiver of Jury Trial
Severability of Provisions
Entire Agreement
Amendment
No Presumption Against the Drafting Party
Interpretation
i
Page
1
1
4
4
4
6
8
10
11
11
12
14
14
14
14
15
15
15
15
15
15
16
16
16
16
17
17
REGISTRATION RIGHTS AGREEMENT
REGISTRATION RIGHTS AGREEMENT, dated as of October 6 , 2017 (this “ Agreement ”), among Patterson-UTI
Energy, Inc., a Delaware corporation (the “ Company ”), and the Persons identified on Schedule A hereto (each, a “ Seller ” and,
collectively, the “ Sellers ”).
WHEREAS, the Company and the Sellers are parties to a Securities Purchase Agreement, dated as of September 4 , 2017
(the “ Purchase Agreement ”), pursuant to which the Sellers are selling to the Company, and the Company is purchasing from the
Sellers, 100% of the issued and outstanding limited liability company interests in Multi-Shot, LLC, a Texas limited liability company
(the “ Sale ”);
WHEREAS, in accordance with Section 2.2 of the Purchase Agreement, as consideration for and at the closing of the Sale,
the Company is (i) issuing 7,541,478 shares of Common Stock to the Sellers and (ii) depositing 1,256,913 shares of Common Stock
with Continental Stock Transfer & Trust Company (the “ Escrow Agent ”) to be held and distributed by the Escrow Agent in
accordance with the terms of the Escrow Agreement (all such shares that are distributed to the Sellers in accordance with the Escrow
Agreement, together with the shares of Common Stock described in the foregoing clause (i), the “ Shares ”);
WHEREAS, the Company has agreed to provide the registration and other rights set forth in this Agreement for the benefit
of the Sellers pursuant to the Purchase Agreement; and
WHEREAS, it is a condition to the obligations of the Company and the Sellers under the Purchase Agreement that this
Agreement be executed and delivered;
NOW THEREFORE, in consideration of the mutual covenants and agreements set forth herein and for good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged by each party hereto, the parties hereby agree as
follows:
ARTICLE I
DEFINITIONS
Section 1.1 Definitions . The terms set forth below are used herein as so defined:
“ Affiliate ” means, with respect to any Person, any other Person that directly, or indirectly through one or more
intermediaries, controls, is controlled by, or is under common control with, such first Person.
“ Agreement ” has the meaning specified therefor in the introductory paragraph.
“ Automatic Shelf Registration Statement ” means an “automatic shelf registration statement” as defined in Rule 405
promulgated under the Securities Act.
“ Business Day ” means any day that is not a Saturday, a Sunday or other day on which banks are required or authorized
by Law to be closed in The City of New York.
1
“ Closing ” has the meaning specified in the Purchase Agreement.
“ Closing Date ” has the meaning specified in the Purchase Agreement.
“ Commission ” means the United States Securities and Exchange Commission.
“ Common Stock ” means the common stock, par value $0.01 per share, of the Company.
“ Company ” has the meaning specified therefor in the introductory paragraph of this Agreement.
“ Effective Date ” means the date of effectiveness of a Shelf Registration Statement filed pursuant to Section 2.1(a) .
“ Effectiveness Period ” has the meaning specified therefor in Section 2.1(a) .
“ Escrow Agent ” has the meaning specified therefor in the Recitals of this Agreement.
“ Escrow Agreement ” has the meaning specified in the Purchase Agreement.
“ Exchange Act ” means the Securities Exchange Act of 1934, as amended from time to time, and the rules and
regulations of the Commission promulgated thereunder.
“ Filing Date ” has the meaning specified therefore in Section 2.1(a) .
“ Governmental Authority ” has the meaning set forth in the Purchase Agreement.
“ Holder ” means the record holder of any Registrable Securities.
“ Incentive Plan Assignee ” has the meaning specified therefore in Section 2.8 .
“ Included Registrable Securities ” has the meaning specified therefor in Section 2.2(a) .
“ Law ” has the meaning set forth in the Purchase Agreement.
“ Liquidated Damages ” has the meaning specified therefor in Section 2.1(c) .
“ Liquidated Damages Multiplier ” has the meaning specified therefor in Section 2.1(c) .
“ Losses ” has the meaning specified therefor in Section 2.7(a) .
“ Managing Underwriter ” means, with respect to any Underwritten Offering, the book running lead manager of such
Underwritten Offering.
“ NASDAQ ” means the NASDAQ Global Select Market.
“ Other Holder ” has the meaning specified in Section 2.2(b) .
2
“ Person ” means any individual, corporation, partnership, limited liability company, limited liability partnership,
syndicate, person, trust, association, organization or other entity, including any Governmental Authority, and including any
successor, by merger or otherwise, of any of the foregoing.
“ Piggyback Opt-Out Notice ” has the meaning specified therefor in Section 2.2(a) .
“ Piggyback Registration ” has the meaning specified therefor in Section 2.2(a) .
“ Purchase Agreement ” has the meaning specified therefor in the Recitals of this Agreement.
“ Purchased Share Price ” means $19.89 per share.
“ Registrable Securities ” means (a) the Shares and (b) any shares of Common Stock issued or issuable with respect to the
Shares by way of a stock dividend or stock split or in exchange for or upon conversion of such shares or otherwise in connection
with a combination of shares, distribution, recapitalization, merger, consolidation, other reorganization or other similar event with
respect to the Common Stock (it being understood that, for purposes of this Agreement, a Person shall be deemed to be a Holder
whenever such Person has the right to then acquire or obtain from the Company any Registrable Securities, whether or not such
acquisition has actually been effected).
“ Registration Expenses ” has the meaning specified therefor in Section 2.6(a) .
“ Resale Opt-Out Notice ” has the meaning specified therefor in Section 2.1(b) .
“ Securities Act ” means the Securities Act of 1933, as amended from time to time, and the rules and regulations of the
Commission promulgated thereunder.
“ Seller ” or “ Sellers ” has the meaning set forth in the introductory paragraph of this Agreement.
“ Selling Expenses ” has the meaning specified therefor in Section 2.6(a) .
“ Selling Holder ” means a Holder who is selling Registrable Securities pursuant to a registration statement.
“ Shares ” has the meaning specified therefor in the Recitals of this Agreement.
“ Shelf Registration Statement ” means a registration statement under the Securities Act to permit the public resale of the
Registrable Securities from time to time as permitted by Rule 415 of the Securities Act (or any similar provision then in force under
the Securities Act).
“ Specified Holder ” means any Holder that is not an Incentive Plan Assignee.
“ Target Effective Date ” has the meaning specified therefor in Section 2.1(c) .
3
“ Underwritten Offering ” means an offering (including an offering pursuant to a Shelf Registration Statement) in which
Common Stock is sold to an underwriter on a firm commitment basis for reoffering to the public or an offering that is a “bought
deal” with one or more investment banks. For the avoidance of doubt, any offering or sale of Common Stock by the Company
pursuant to an “at-the-market” offering as defined in Rule 415(a)(4) of the Securities Act shall not be considered an Underwritten
Offering hereunder.
“ WKSI ” means a well-known seasoned issuer (as defined in the rules and regulations of the Commission).
Section 1.2 Registrable Securities . Any Registrable Security will cease to be a Registrable Security at the earliest
of the following: (a) when a registration statement covering such Registrable Security has been declared effective by the Commission
and such Registrable Security has been sold or disposed of pursuant to such effective registration statement; (b) when such
Registrable Security has been disposed of pursuant to any section of Rule 144 (or any similar provision then in force) under the
Securities Act; (c) when such Registrable Security is held by the Company or one of its subsidiaries; (d) when such Registrable
Security has been sold in a private transaction in which the transferor’s rights under this Agreement are not assigned to the transferee
of such securities; and (e) as to Registrable Securities beneficially owned by a Holder, the date on which all Registrable Securities
beneficially owned by such Holder may be sold in a single sale pursuant to any section of Rule 144 under the Securities Act (or any
similar provision then in force under the Securities Act) without any restriction or other requirement that must be satisfied by such
Holder or the Company.
Section 2.1 Shelf Registration .
ARTICLE II
REGISTRATION RIGHTS
(a) Shelf Registration . As soon as practicable following the Closing, but in no event more than 30 days
following the Closing Date , the Company shall use its commercially reasonable efforts to prepare and file a Shelf Registration
Statement under the Securities Act covering the Registrable Securities. The Company shall use its commercially reasonable efforts
to cause such Shelf Registration Statement to become effective as promptly as practicable after the date of filing of such Shelf
Registration Statement (the “ Filing Date ”). The Company will use its commercially reasonable efforts to cause such Shelf
Registration Statement filed pursuant to this Section 2.1(a) to be continuously effective under the Securities Act until the earliest of
(i) all Registrable Securities covered by the Shelf Registration Statement have been distributed in the manner set forth and as
contemplated in such Shelf Registration Statement, (ii) there are no longer any Registrable Securities outstanding or (iii) three years
from the Effective Date (the “ Effectiveness Period ”). A Shelf Registration Statement filed pursuant to this Section 2.1(a) shall be
on such appropriate registration form of the Commission as shall be selected by the Company; provided , however , that if the
Company is a WKSI at the time a Shelf Registration Statement is required to be filed hereunder, such Shelf Registration Statement
shall be filed as an Automatic Shelf Registration Statement. A Shelf Registration Statement when declared effective (including the
documents incorporated therein by reference) will comply as to form in all material respects with all applicable requirements of the
Securities Act and the Exchange Act
4
and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to
make the statements therein not misleading (and, in the case of any prospectus contained in such Shelf Registration Statement, in the
light of the circumstances under which a statement is made). As soon as practicable following the date that a Shelf Registration
Statement filed pursuant to this Section 2.1(a) becomes effective, but in any event within five Business Days of such date, the
Company shall provide the Holders with written notice of the effectiveness of a Shelf Registration Statement ; provided that no such
notice shall be required if such Shelf Registration Statement is an Automatic Shelf Registration Statement .
(b) Resale Registration Opt-Out . Any Holder may deliver advance written notice (a “ Resale Opt-Out
Notice ”) to the Company requesting that such Holder not be included in a Shelf Registration Statement filed pursuant to Section
2.1(a) . Following receipt of a Resale Opt-Out Notice from a Holder, the Company shall not be required to include the Registrable
Securities of such Holder in such Shelf Registration Statement.
(c) Failure to Become Effective . If a Shelf Registration Statement required by Section 2.1(a) does not
become or is not declared effective within 120 days after the Filing Date (the “ Target Effective Date ”), then the Holders shall be
entitled to a payment (with respect to each of the Holder’s Registrable Securities which are included in such Shelf Registration
Statement), as liquidated damages and not as a penalty, (i) for each non-overlapping 30-day period for the first 60 days following the
Target Effective Date, an amount equal to (A) 0.25% times (B) the product of (x) the Purchased Share Price times (y) the number of
Registrable Securities, then held by such Holder and included on such Shelf Registration Statement (such product of (x) and (y)
being the “ Liquidated Damages Multiplier ”), and (ii) for each non-overlapping 30-day period beginning on the 61st day
following the Target Effective Date, with such payment amount increasing by an additional amount equal to 0.25% times the
Liquidated Damages Multiplier per non-overlapping 30-day period for each subsequent 60 days (i.e., 0.5% for 61-120 days, 0.75%
for 121-180 days, and 1.0% thereafter) up to a maximum amount equal to 1.0% times the Liquidated Damages Multiplier per non-
overlapping 30-day period (the “ Liquidated Damages ”), until such time as the Shelf Registration Statement is declared effective or
there are no longer any Registrable Securities outstanding. The Liquidated Damages shall accrue on a daily basis and be paid to the
Sellers in cash within ten Business Days of the end of such 30-day period. Any Liquidated Damages shall be paid to the Sellers in
immediately available funds. For the avoidance of doubt, nothing in this Section 2.1(c) shall relieve the Company from its
obligations under Section 2.1(a) .
(d) Waiver of Liquidated Damages . If the Company is unable to cause a Shelf Registration Statement to
become effective by the Target Effective Date as a result of an acquisition, merger, reorganization, disposition or other similar
transaction, then the Company may request a waiver of the Liquidated Damages, which may be granted by the consent of the
majority of Holders that have been included on such Shelf Registration Statement, in their sole discretion, and which such waiver
shall apply to all the Holders included on such Shelf Registration Statement.
5
(e) Delay Rights . Notwithstanding anything to the contrary contained herein, the Company may delay
the filing of a Shelf Registration Statement required by Section 2.1(a) and may , upon written notice to any Selling Holder whose
Registrable Securities are included in the Shelf Registration Statement, suspend such Selling Holder’s use of any prospectus which is
a part of the Shelf Registration Statement (in which event the Selling Holder shall discontinue sales of the Registrable Securities
pursuant to the Shelf Registration Statement) if (i) the Company is pursuing an acquisition, merger, reorganization, disposition or
other similar transaction and the Company determines in good faith that the Company’s ability to pursue or consummate such a
transaction would be materially and adversely affected by any required disclosure of such transaction in the Shelf Registration
Statement or (ii) the Company has experienced some other material non-public event the disclosure of which at such time, in the
good faith judgment of the Company, would materially and adversely affect the Company; provided , however , that in no event shall
the Selling Holders be suspended from selling Registrable Securities pursuant to the Shelf Registration Statement for a period that
exceeds an aggregate o f 60 days in any 180 day period . Upon disclosure of such information or the termination of the condition
described above, the Company shall provide prompt notice to the Selling Holders whose Registrable Securities are included in the
Shelf Registration Statement, and shall promptly terminate any suspension of sales it has put into effect and shall take such other
actions necessary or appropriate to permit registered sales of Registrable Securities as contemplated in this Agreement.
Section 2.2 Piggyback Registration .
(a) Participation . If the Company proposes to file (A) a registration statement under the Securities Act
providing for the public offering of Common Stock, for its own account or for the account of a selling stockholder, for sale to the
public in an Underwritten Offering, excluding a registration statement on Form S-4 or Form S-8 promulgated under the Securities
Act (or any successor forms thereto), a registration statement for the sale of Common Stock issued upon conversion of debt securities
or any other form not available for registering the Registrable Securities for sale to the public, or (B) a prospectus supplement to an
effective Shelf Registration Statement, so long as the Company is a WKSI at such time or, whether or not the Company is a WKSI,
so long as the Registrable Securities were previously included in the underlying Shelf Registration Statement, then, in each case with
respect to an Underwritten Offering of Common Stock, the Company will notify each Specified Holder of the proposed filing and
afford each Specified Holder an opportunity to include in such Underwritten Offering all or any part of the Registrable Securities
then held by such Specified Holder (the “ Included Registrable Securities ”) that may properly be offered on such registration
statement (a “ Piggyback Registration ”). Each Specified Holder of Registrable Securities agrees that the fact that such a notice has
been delivered shall constitute confidential information and such Specified Holder agrees not to disclose that such notice has been
delivered or effect any public sale or distribution of Common Stock until the earlier of (i) the date that the applicable registration
statement or prospectus supplement has been filed with the Commission and (ii) 20 days after the date of such notice. Each
Specified Holder desiring to include in such Piggyback Registration all or part of such Registrable Securities held by such Specified
Holder that may be included in such Piggyback Registration shall, within three Business Days after receipt of the above-described
notice from the Company in the case of a filing of a registration statement and within two Business Days after the day of receipt of
the above-described notice from the Company in the case of a filing of a prospectus supplement to an effective Shelf Registration
Statement with
6
respect to a Piggyback Registration, so notify the Company in writing, and in such notice shall inform the Company of the number of
shares of Registrable Securities such Specified Holder wishes to include in such Piggyback Registration and provide the Company
with such information with respect to such Specified Holder as shall be reasonably necessary in order to assure compliance with
federal and applicable state securities L aws. If no request for inclusion from a Specified Holder is received within the time period
specified in this Section 2.2(a) , such Specified Holder shall have no further right to participate in such Piggyback Registration. For
the avoidance of doubt, the Company shall not be required to register any Registrable Securities upon the request of any Specified
Holder pursuant to a Piggyback Registration, or to permit the related prospectus or prospectus supplement to be used, in connection
with any offering or transfer of Registrable Securities by a Specified Holder other than pursuant to an Underwritten Offering. If, at
any time after giving written notice of its intention to undertake an Underwritten Offering and prior to the closing of such
Underwritten Offering, the Company shall determine for any reason not to undertake or to delay such Underwritten Offering, the
Company may, at its election, give written notice of such determina tion to the Selling Holders and (x) in the case of a determination
not to undertake such Underwritten Offering, shall be relieved of its obligation to sell any Included Registrable Securities in
connection with such terminated Underwritten Offering, and (y) in the case of a determination to delay such Underwritten Offering,
shall be permitted to delay offering any Included Registrable Securities for the same period as the delay in the Underwritten
Offering. Any Specified Holder may deliver written notice (a “ Piggyback Opt-Out Notice ”) to the Company requesting that such
Specified Holder not receive notice from the Company of any proposed Underwritten Offering; provided , however , that such
Specified Holder may later revoke any such Piggyback Opt-Out Notice in writing. Following receipt of a Piggyback Opt-Out Notice
from a Specified Holder (unless subsequently revoked), the Company shall not be required to deliver any notice to such Specified
Holder pursuant to this Section 2.2(a) and such Specified Holder shall no longer be entitled to participate in Underwritten Offerings
by the Company pursuant to this Section 2.2(a) . For the avoidance of doubt, no Incentive Right Assignee shall have any right to
participate in any Piggyback Registration pursuant to , and no Incentive Right Assignee shall be a Selling Holder for purposes of,
this Section 2.2 .
(b) Priority of Piggyback Registration . If the Managing Underwriter or Underwriters of any proposed
Underwritten Offering of shares of Common Stock included in a Piggyback Registration advise the Company that the total shares of
Common Stock which the Selling Holders and any other Persons intend to include in such offering exceeds the number which can be
sold in such offering without being likely to have an adverse effect on the price, timing or distribution of Common Stock offered or
the market for the Common Stock, then the Common Stock to be included in such Underwritten Offering shall include the number of
shares of Common Stock that such Managing Underwriter or Underwriters advise the Company can be sold without having such
adverse effect, with such number to be allocated (i) first, to the Company and (ii) second, pro rata among the Selling Holders and
any other Persons who have been or are granted registration rights on or after the date of this Agreement (the “ Other Holders ”)
who have requested participation in the Piggyback Registration (based, for each such Selling Holder or Other Holder, on the
percentage derived by dividing (A) the number of shares of Common Stock proposed to be sold by such Selling Holder or such Other
Holder in such offering; by (B) the aggregate number of shares of Common Stock proposed to be sold by all Selling Holders and all
Other Holders in the Piggyback Registration).
7
(c) General Procedures . In connection with any Underwritten Offering , the Company shall be entitled
to select the Managing Underwriter or Underwriters . In connection with an Underwritten Offering contemplated by this Agreement
in which a Selling Holder participates, each Selling Holder shall be obligated to enter into an underwriting agreement with the
Managing Underwriter or Underwriters which contains such representations, covenants, indemnities and other rights and obligations
as are customary in underwriting agreements for firm commitment offerings of equity securities. No Selling Holder may participate
in such Underwritten Offering unless such Selling Holder agrees to sell its Registrable Securities on the basis provided in such
underwriting agreement and completes and executes all questionnaires, powers of attorney, indemnities and other documents
reasonably required under the terms of such underwriting agreement . No Selling Holder shall be required to make any
representations or warranties to or agreements with the Company or the underwriters other than representations, warranties or
agreements regarding such Selling Holder and its ownership of the securities being registered on its behalf and its intended method
of distribution and any ot her representation required by L aw. If any Selling Holder disapproves of the terms of an U nderwrit ten
Offering , such Selling Holder may elect to withdraw therefrom by notice to the Company and the Managing Underwriter; provided ,
however , that such withdrawal must be made at least one Business Day prior to the time of pricing of such Underwritten Offering to
be effective. No such withdrawal or abandonment shall affect the Company’s obligation to pay Registration Expenses.
Section 2.3 Sale Procedures . In connection with its obligations under this Article II , the Company will, as
promptly as practicable:
(a) subject to Section 2.1(e) , prepare and file with the Commission such amendments and supplements
to the Shelf Registration Statement and the prospectus used in connection therewith as may be necessary to keep a Shelf Registration
Statement effective for the Effectiveness Period and as may be necessary to comply with the provisions of the Securities Act with
respect to the disposition of all Registrable Securities covered by a Shelf Registration Statement;
(b) furnish to each Selling Holder (i) as far in advance as reasonably practicable before filing a Shelf
Registration Statement or any other registration statement contemplated by this Agreement or any supplement or amendment thereto
(other than any amendment or supplement resulting from the filing of a document incorporated by reference therein), upon request,
copies of reasonably complete drafts of all such documents proposed to be filed (excluding exhibits and any document incorporated
by reference therein ), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling
Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder
with respect to such information prior to filing such Shelf Registration Statement or such other registration statement and the
prospectus included therein or any such supplement or amendment thereto, and (ii) such number of copies of such Shelf Registration
Statement or such other registration statement and the prospectus included therein and any such supplements and amendments
thereto as such Persons may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities
covered by such Shelf Registration Statement or any other registration statement;
8
(c) if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities
covered by a Shelf Registration Statement or any other registration statement contemplated by this Agreement under the securities or
blue sky laws of such jurisdictions as the Selling Holders shall reasonably request, provided that the Company will not be required to
qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action which would
subject it to general service of process in any such jurisdiction where it is not then so subject;
(d) promptly notify each Selling Holder, at any time when a prospectus relating thereto is required to be
delivered under the Securities Act, of (i) the filing of a Shelf Registration Statement or any other registration statement contemplated
by this Agreement or any prospectus included therein or any amendment or supplement thereto (other than any amendment or
supplement resulting from the filing of a document incorporated by reference therein) , and, with respect to such Shelf Registration
Statement or any other registration statement or any post-effective amendment thereto, in each case other than an Automatic Shelf
Registration Statement, when the same has become effective; and (ii) the receipt of any written comments from the Commission with
respect to any filing referred to in clause (i) and any written request by the Commission for amendments or supplements to such
Shelf Registration Statement or any other registration statement or any prospectus or prospectus supplement thereto;
(e) immediately notify each Selling Holder, at any time when a prospectus relating thereto is required to
be delivered under the Securities Act, of (i) the happening of any event as a result of which the prospectus contained in a Shelf
Registration Statement or any other registration statement contemplated by this Agreement or any supplemental amendment thereto,
includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make
the statements therein not misleading in the light of the circumstances then existing; (ii) the issuance or threat of issuance by the
Commission of any stop order suspending the effectiveness of such Shelf Registration Statement or any other registration statement
contemplated by this Agreement, or the initiation of any proceedings for that purpose; or (iii) the receipt by the Company of any
notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or
blue sky laws of any jurisdiction. Following the provision of such notice but subject to Section 2.1(e) , the Company agrees to as
promptly as practicable amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the
prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required
to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to
take such other action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto;
(f) otherwise use its commercially reasonable efforts to comply with all applicable rules and regulations
of the Commission, and make available to its security holders , as soon as reasonably practicable, an earnings statement covering the
period of at least 12 months, but not more than 18 months, beginning with the first full calendar month after the Effective Date of
such registration statement, which earnings statement shall satisfy the provisions of Section l1(a) of the Securities Act and Rule 158
promulgated thereunder;
9
(g) make available to the appropriate representatives of the Selling Holders access to such information
and the Company personnel as is reasonable and customary to enable such parties and their representatives to establish a due
diligence defense under the Securities Act; provided that the Company need not disclose any non-public information to any such
representative unless and until the Selling Holders and such representative s ha ve entered into a confidentiality agreement with the
Company;
letters in connection with the sale of Registrable Securities by any Selling Holder utilizing the Shelf Registration Statement;
(h) use all commercially reasonable efforts to procure customary legal opinions and auditor “comfort”
securities exchange or nationally recognized quotation system on which similar securities issued by the Company are then listed;
(i) cause all such Registrable Securities registered pursuant to this Agreement to be listed on each
(j) use its commercially reasonable efforts to cause the Registrable Securities to be registered with or
approved by such other governmental agencies or authorities as may be necessary by virtue of the business and operations of the
Company to enable the Selling Holders to consummate the disposition of such Registrable Securities;
statement not later than the Effective Date; and
(k) provide a transfer agent and registrar for all Registrable Securities covered by such registration
(l) if reasonably requested by a Selling Holder, (i) incorporate in a prospectus supplement or post-
effective amendment such information as such Selling Holder reasonably requests to be included therein relating to the sale and
distribution of Registrable Securities by such Selling Holder, including information with respect to the number of Registrable
Securities being offered or sold, the purchase price being paid therefor and any other terms of the offering of the Registrable
Securities to be sold in such offering; and (ii) make all required filings of such prospectus supplement or post-effective amendment
after being notified of the matters to be incorporated in such prospectus supplement or post-effective amendment.
Each Selling Holder, upon receipt of notice from the Company of the happening of any event of the kind described in
subsection (e) of this Section 2.3 , shall forthwith discontinue disposition of the Registrable Securities until such Selling Holder’s
receipt of the copies of the supplemented or amended prospect us contemplated by subsection (e) of this Section 2.3 or until it is
advised in writing by the Company that the use of the prospectus may be resumed, and has received copies of any additional or
supplemental filings incorporated by reference in the prospectus, and, if so directed by the Company, such Selling Holder will
deliver to the Company (at the Company’s expense) all copies in its possession or control, other than permanent file copies then in
such Selling Holder’s possession, of the prospectus and any prospectus supplement covering such Registrable Securities current at
the time of receipt of such notice.
Section 2.4 Cooperation by Holders . The Company shall have no obligation to include Registrable Securities of a
Holder in the Shelf Registration Statement or in an Underwritten Offering under Article II of this Agreement if such Selling Holder
has failed to timely furnish such information which, in the opinion of counsel to the Company, is reasonably required in order for the
registration statement or prospectus supplement, as applicable, to comply with the Securities Act.
10
Section 2.5 Restrictions on Public Sale by Holders of Registrable Securities . Regardless of whether a Holder
elects to include shares of Common Stock that constitute Registrable Securities in an Underwritten Offering, each Holder of
Registrable Securities hereby agrees that it shall not, to the extent requested by the Company or an underwriter of securities of the
Company, directly or indirectly sell, offer to sell (including any short sale or hedging or similar transaction with the same economic
effect as a sale), grant any option or otherwise transfer or dispose of any Registrable Securities or other securities of the Company or
any securities convertible into or exchangeable or exercisable for Common Stock of the Company then owned by such Holder during
the period beginning 14 days prior to the expected date of “pricing” of such offering and continuing for a period not to exceed 90
days following the effective date of a registration statement for an Underwritten Offering or the date of a prospectus supplement filed
with the Commission with respect to the pricing of an Underwritten Offering, other than the sale or distribution of shares of Common
Stock that constitute Registrable Securities in such Underwritten Offering; provided , however , that such period shall in no event be
greater than that which applies to executive officers and directors of the Company. In order to enforce the foregoing covenant, the
Company shall have the right to impose stop transfer instructions with respect to the Registrable Securities and such other securities
of each Holder (and the securities of every other Person subject to the foregoing restriction) until the end of such period.
Section 2.6 Expenses .
(a) Certain Definitions . “ Registration Expenses ” means all expenses incident to the Company ’s
performance under or compliance with this Agreement to effect the registration of Registrable Securities in a Shelf Registration
Statement pursuant to Section 2.1 or a Piggyback Registration pursuant to Section 2.2 , and the disposition of such securities,
including, without limitation, all registration , filing, securities exchange listing and NASDAQ fees, all registration, filing,
qualification and other fees and expenses of complying with securities or blue sky laws, fees of the Financial Industry Regulatory
Authority, including, transfer taxes and fees of transfer agents and registrars, all word processing, duplicating and printing expenses,
the fees and disbursements of counsel and independent public accountants for the Company, including the expenses of any special
audits or “cold comfort” letters required by or incident to such performance and compliance. Except as otherwise provided in
Section 2.7 , the Company shall not be responsible for legal fees incurred by Holders in connection with the exercise of such
Holders’ rights hereunder. In addition, the Company shall not be responsible for any “ Selling Expenses ,” which means all
underwriting fees, discounts and selling commissions and transfer taxes allocable to the sale of the Registrable Securities.
(b) Expenses . The Company will pay all reasonable Registration Expenses in connection with a Shelf
Registration Statement or a Piggyback Registration, whether or not any sale is made pursuant to such Shelf Registration Statement or
Piggyback Registration. Each Selling Holder shall pay all Selling Expenses in connection with any sale of its Registrable Securities
hereunder.
11
Section 2.7 Indemnification .
(a) By the Company . In the event of a registration of any Registrable Securities under the Securities Act
pursuant to this Agreement, the Company will indemnify and hold harmless each Selling Holder thereunder, its directors, officers,
employees, agents and managers, and each Person, if any, who controls such Selling Holder within the meaning of the Securities Act
and the Exchange Act, and its directors, officers, employees, agents and managers, against any losses, claims, damages, expenses or
liabilities (including reasonable attorneys’ fees and expenses) (collectively, “ Losses ”), joint or several, to which such Selling
Holder or controlling Person may become subject under the Securities Act, the Exchange Act or otherwise, insofar as such Losses (or
actions or proceedings, whether commenced or threatened, in respect thereof) arise out of or are based upon any untrue statement or
alleged untrue statement of any material fact (in the case of any prospectus, in light of the circumstances under which such statement
is made) contained in the Shelf Registration Statement or any other registration statement contemplated by this Agreement, any
preliminary prospectus or final prospectus contained therein, or any free writing prospectus related thereto, or any amendment or
supplement thereof, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be
stated therein or necessary to make the statements therein (in the case of a prospectus, in light of the circumstances under which they
were made) not misleading, and will reimburse each such Selling Holder, its directors and officers and each such controlling Person
for any legal or other expenses reasonably incurred by them in connection with investigating or defending any such Loss or actions
or proceedings; provided , however , that the Company will not be liable in any such case if and to the extent that any such Loss
arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission so made in conformity
with information furnished by such Selling Holder or such controlling Person in writing expressly for inclusion in the Shelf
Registration Statement or such other registration statement, or prospectus supplement, as applicable.
(b) By Each Selling Holder . Each Selling Holder agrees to, severally and not jointly, indemnify and
hold harmless the Company, its directors, officers, employees and agents and each Person, if any, who controls the Company within
the meaning of the Securities Act or of the Exchange Act to the same extent as the foregoing indemnity from the Company to the
Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such
Selling Holder expressly for inclusion in the Shelf Registration Statement or prospectus supplement relating to the Registrable
Securities, or any amendment or supplement thereto.
(c) Notice . Promptly after receipt by an indemnified party hereunder of notice of the commencement of
any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party hereunder, notify
the indemnifying party in writing thereof, but the omission so to notify the indemnifying party shall not relieve it from any liability
which it may have to any indemnified party other than under this Section 2.7(c) except to the extent that the indemnifying party is
materially prejudiced by such failure. In any action brought against any indemnified party, it shall notify the indemnifying party of
the commencement thereof. The indemnifying party shall be entitled to participate in and, to the extent it shall wish, to assume and
undertake the defense thereof with counsel reasonably satisfactory to such indemnified party and, after notice from the indemnifying
party to such
12
indemnified party of its election so to assume and undertake the defense thereof, the indemnifying party shall not be liable to such
indemnified party under this Section 2.7(c) for any legal expenses subsequently incurred by such indemnified party in connection
with the defense thereof other than reasonable costs of investigation and of liaison with counsel so selected; provided , however ,
that, (i) if the indemnifying party has failed to assume the defense and employ counsel or (ii) if the defendants in any such action
include both the indemnified party and the indemnifying party and counsel to the indemnified party shall have concluded that there
may be reasonable defenses available to the indemnified party that are different from or additional to those available to the
indemnifying party, or if the interests of the indemnified party reasonably may be deemed to conflict with the interests of the
indemnifying party, then the indemnified party shall have the right to select a separate counsel and to assume such legal defense and
otherwise to participate in the defense of such action, with the reasonable expenses and fees of such separate counsel and other
reasonable expenses related to such participation to be reimbursed by the indemnifying party as incurred. Notwithstanding any other
provision of this Agreement, the indemnifying party shall not settle any indemnified claim without the consent of the indemnified
party, unless the settlement thereof imposes no liability or obligation on, includes a complete release from liability of, and does not
contain any admission of wrong doing by, the indemnified party.
(d) Contribution . If the indemnification provided for in this Section 2.7 is held by a court or government
agency of competent jurisdiction to be unavailable to the Company or any Selling Holder or is insufficient to hold them harmless in
respect of any Losses, then each such indemnifying party, in lieu of indemnifying such indemnified party, shall contribute to the
amount paid or payable by such indemnified party as a result of such Losses in such proportion as is appropriate to reflect the
relative fault of the Company on the one hand and of such Selling Holder on the other in connection with the statements or omissions
which resulted in such Losses, as well as any other relevant equitable considerations. The relative fault of the Company on the one
hand and each Selling Holder on the other shall be determined by reference to, among other things, whether the untrue or alleged
untrue statement of a material fact or the omission or alleged omission to state a material fact has been made by, or relates to,
information supplied by such party, and the parties’ relative intent, knowledge, access to information and opportunity to correct or
prevent such statement or omission. The parties hereto agree that it would not be just and equitable if contributions pursuant to this
paragraph were to be determined by pro rata allocation or by any other method of allocation which does not take account of the
equitable considerations referred to in the first sentence of this paragraph. The amount paid by an indemnified party as a result of the
Losses referred to in the first sentence of this paragraph shall be deemed to include any legal and other expenses reasonably incurred
by such indemnified party in connection with investigating or defending any Loss which is the subject of this paragraph. No Person
guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution
from any Person who is not guilty of such fraudulent misrepresentation.
indemnification or contribution which an indemnified party may have pursuant to law, equity, contract or otherwise.
(e) Other Indemnification . The provisions of this Section 2.7 shall be in addition to any other rights to
13
Section 2.8 Transfer or Assignment of Registration Rights . The rights to cause the Company to register
Registrable Securities granted to the Sellers by the Company under this Article II may be transferred or assigned by each Seller only
to one or more transferee(s) or assignee(s) of such Registrable Securities who are (a) Affiliates of such Seller and, (b) in the case of
MS Incentive Plan Holdco, LLC, to participants in that certain MS Incentive Plan Holdco, LLC Transaction Incentive Plan (any
Person that becomes a Holder as an assignee described in this clause (b) that is not otherwise a Seller or an Affiliate of a Seller , an “
Incentive Plan Assignee ”) . The Company shall be given written notice prior to any said transfer or assignment, stating the name
and address of each such transferee and identifying the securities with respect to which such registration rights are being transferred
or assigned, and each such transferee shall assume in writing responsibility for its obligations of such Seller under this Agreement.
Section 2.9 Aggregation of Registrable Securities . All Registrable Securities held or acquired by Persons who are
Affiliates of one another shall be aggregated together for the purpose of determining the availability of any rights under this
Agreement.
ARTICLE III
MISCELLANEOUS
Section 3.1 Communications . All notices and demands provided for hereunder shall be in writing and shall be
given by registered or certified mail, return receipt requested, e-mail, air courier guaranteeing overnight delivery or personal delivery
to the following addresses:
(a) If to a Seller, to such address indicated on Schedule A attached hereto.
with a copy (which shall not constitute notice) to:
Vinson & Elkins LLP
1001 Fannin Street
Suite 2500
Houston, Texas 77002
Attention: W. Matthew Strock
E-mail: mstrock@velaw.com
(b) If to the Company:
Patterson-UTI Energy, Inc.
10713 W. Sam Houston Pkwy N, Suite 800
Houston, Texas 77064
Attention: General Counsel
E-mail: legalnotice@patenergy.com
with a copy (which shall not constitute notice) to:
Gibson, Dunn & Crutcher LLP
1221 McKinney Street, 37 th Floor
Houston, Texas 77010-2046
Attention: Tull R. Florey
E-mail: tflorey@gibsondunn.com
14
or, if to a transferee of a Seller, to the transferee at the address provided pursuant to Section 2.8 . All notices and communications
shall be deemed to have been duly given: at the time delivered by hand, if personally delivered; upon actual receipt if sent by
certified or registered mail, return receipt requested, or regular mail, if mailed; upon actual receipt if sent via e-mail; and upon actual
receipt when delivered to an air courier guaranteeing overnight delivery.
Section 3.2 Successors and Assigns . This Agreement shall inure to the benefit of and be binding upon the
successors and assigns of each of the parties, including subsequent Holders of Registrable Securities to the extent permitted herein.
Section 3.3 Assignment of Rights . All or any portion of the rights and obligations of any Seller under this
Agreement may be transferred or assigned by such Seller in accordance with Section 2.8 .
Section 3.4 Recapitalization (Exchanges , etc. Affecting the Common Stock) . The provisions of this Agreement
shall apply to the full extent set forth herein with respect to any and all shares of capital stock of the Company or any successor or
assign of the Company (whether by merger, consolidation, sale of assets or otherwise) which may be issued in respect of, in
exchange for or in substitution of, the Registrable Securities, and shall be appropriately adjusted for combinations, recapitalizations
and the like occurring after the date of this Agreement.
Section 3.5 Enforcement . The parties hereto agree that irreparable damage would occur in the event that any of the
provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. Accordingly,
each of the parties shall be entitled to specific performance of the terms hereof, including an injunction or injunctions to prevent
breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement in any Texas state or federal court
sitting in Harris County, Texas (or, if such court lacks subject matter jurisdiction, in any appropriate Texas state or federal court),
this being in addition to any other remedy to which such party is entitled at law or in equity. Each of the parties hereby further
waives (a) any defense in any action for specific performance that a remedy at law would be adequate and (b) any requirement under
any law to post security as a prerequisite to obtaining equitable relief.
Section 3.6 Counterparts . This Agreement may be executed in two or more counterparts, all of which shall be
considered one and the same instrument and shall become effective when one or more counterparts have been signed by each of the
parties and delivered to the other party.
Section 3.7 Governing Law, Submission to Jurisdiction . This Agreement and all disputes or controversies arising
out of or relating to this Agreement or the transactions contemplated hereby shall be governed by, and construed in accordance with,
the internal laws of the State of Texas, without regard to the laws of any other jurisdiction that might be applied because of the
conflicts of laws principles of the State of Texas. Each of the parties irrevocably agrees that any legal action or proceeding arising
out of or relating to this Agreement brought by any party or its successors or assigns against the other party shall be brought and
determined any Texas state or federal court sitting in Harris County, Texas (or, if such court lacks subject matter jurisdiction, in any
appropriate Texas state or federal court), and each of the parties hereby
15
irrevocably submits to the exclusive jurisdiction of the aforesaid courts for itself and with respect to its property, generally and
unconditionally, with regard to any such action or proceeding arising out of or relating to this Agreement or the transactions
contemplated hereby. Each of the parties agrees not to commence any action, suit or proceeding relating thereto except in the courts
described above in Texas, other than actions in any court of competent jurisdiction to enforce any judgment, decree or award
rendered by any such court in Texas as described herein. Each of the parties further agrees that notice as provided herein shall
constitute sufficient service of process and the parties further waive any argument that such service is insufficient. Each of the
parties hereby irrevocably and unconditionally waives, and agrees not to assert, by way of motion or as a defense, counterclaim or
otherwise, in any action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby, (a) any
claim that it is not personally subject to the jurisdiction of the courts in Texas as described herein for any reason, (b) that it or its
property is exempt or immune from jurisdiction of any such court or from any legal process commenced in such courts (whether
through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or
otherwise) and (c) that (i) the suit, action or proceeding in any such court is brought in an inconvenient forum, (ii) the venue of such
suit, action or proceeding is improper or (iii) this Agreement, or the subject matter hereof, may not be enforced in or by such courts.
Section 3.8 Waiver of Jury Trial
EACH OF THE PARTIES TO THIS AGREEMENT HEREBY
IRREVOCABLY WAIVES ALL RIGHT TO A TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM
ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.
.
Section 3.9 Severability of Provisions . Whenever possible, each provision or portion of any provision of this
Agreement shall be interpreted in such manner as to be effective and valid under applicable Law, but if any provision or portion of
any provision of this Agreement is held to be invalid, illegal or unenforceable in any respect under any applicable Law or rule in any
jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision or portion of any provision in such
jurisdiction, and this Agreement shall be reformed, construed and enforced in such jurisdiction as if such invalid, illegal or
unenforceable provision or portion of any provision had never been contained herein.
Section 3.10 Entire Agreement . This Agreement and the Purchase Agreement constitute the entire agreement ,
and supersede all prior written agreements , arrangements, communications and understandings and all prior and contemporaneous
oral agreements, arrangements, communications and understandings between the parties with respect to the subject matter hereof and
thereof.
Section 3.11 Amendment . This Agreement may not be amended, modified or supplemented in any manner,
whether by course of conduct or otherwise, except by an instrument in writing specifically designated as an amendment hereto,
signed on behalf of the Company and a majority of Holders.
16
Section 3.12 No Presumption Against the Drafting Party . The Company and each of the Sellers acknowledges
that each party to this Agreement has been represented by legal counsel in connection with this Agreement and the transactions
contemplated by this Agreement. Accordingly, any rule of law or any legal decision that would require interpretation of any claimed
ambiguities in this Agreement against the drafting party has no application and is expressly waived.
Section 3.13 Interpretation . When a reference is made in this Agreement to a Section or Article such reference
shall be to a Section or Article of this Agreement unless otherwise indicated. The table of contents and headings contained in this
Agreement are for convenience or reference purposes only and shall not affect in any way the meaning or interpretation of this
Agreement. All words used in this Agreement will be construed to be of such gender or number as the circumstances require. The
word “including” and words of similar import when used in this Agreement will mean “including, without limitation,” unless
otherwise specified. The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall
refer to the Agreement as a whole and not to any particular provision in this Agreement. The term “or” is not exclusive. The word
“will” shall be construed to have the same meaning and effect as the word “shall.” References to days mean calendar days unless
otherwise specified.
[ Signature page follows .]
17
IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above.
PATTERSON-UTI ENERGY, INC.
/s/ William Andrew Hendricks, Jr.
By:
Name: William Andrew Hendricks, Jr.
Title: President and Chief Executive Officer
THE SELLERS:
/s/ Allen Neel
ALLEN NEEL
/s/ Paul Culbreth
PAUL CULBRETH
/s/ Ron Whitter
RON WHITTER
[ Signature Page to Registration Rights Agreement ]
MULTI-SHOT HOLDING CORPORATION
/s/ Geer Blalock
By:
Name: Geer Blalock
Title: Vice President
NGP MS HOLDINGS, LLC
By:
NGP X US HOLDINGS, L.P., its managing member
By:
NGP X HOLDINGS GP, L.L.C., its general partner
/s/ Richard L. Covington
By:
Name: Richard L. Covington
Title:
Authorized Person
MS INCENTIVE PLAN HOLDCO, LLC
/s/ Geer Blalock
By:
Name: Geer Blalock
Title: Authorized Person
[ Signature Page to Registration Rights Agreement ]
Name
Allen Neel
Paul Culbreth
Ron Whitter
Multi-Shot Holding Corporation
NGP MS Holdings, LLC
MS Incentive Plan Holdco, LLC
Schedule A
The Sellers
Address
c/o Multi-Shot, LLC
3335 Pollok Drive
Conroe, TX 77303
c/o Multi-Shot, LLC
3335 Pollok Drive
Conroe, TX 77303
c/o Multi-Shot, LLC
3335 Pollok Drive
Conroe, TX 77303
600 Travis Street, Suite 2310
Houston, TX 77002
Attn: Paul Winters
5221 N. O’Connor Blvd.
Suite 1100
Irving, TX 75039
Attn: General Counsel
c/o Multi-Shot Holding Corporation
600 Travis Street, Suite 2310
Houston, TX 77002
Attn: Paul Winters
c/o NGP MS Holdings, LLC
5221 N. O’Connor Blvd.
Suite 1100
Irving, TX 75039
Attn: General Counsel
Schedule A
NON-EMPLOYEE DIRECTOR
RESTRICTED STOCK UNIT AWARD AGREEMENT
PATTERSON-UTI ENERGY, INC.
2014 LONG-TERM INCENTIVE PLAN
(As Amended and Restated Effective June 29, 2017)
Exhibit 10.19
THIS RESTRICTED STOCK UNIT AWARD AGREEMENT (the “ Agreement ”) is between Patterson-UTI Energy, Inc., a Delaware corporation
(the “ Company ”), and ____________ (the “ Recipient ”) effective as of the ____ day of _____, 20__ (the “ Grant Date ”), pursuant to the Patterson-UTI Energy,
Inc. 2014 Long-Term Incentive Plan, as amended and restated effective as of June 29, 2017 and as thereafter amended from time to time (the “ Plan ”), which is
incorporated by reference herein in its entirety.
WHEREAS , the Company desires to grant to the Recipient the restricted stock units specified herein (the “ RSUs ”), subject to the terms and
conditions of this Agreement and the Plan; and
NOW, THEREFORE , in consideration of the premises, mutual covenants and agreements contained herein, and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, agree as follows:
1.
Definitions
. For purposes of this Agreement, the following terms shall have the meanings indicated:
(a)
For purposes of this Agreement, a “ Change in Control of the Company ” shall mean the occurrence of any of the following after the Grant
Date:
(i)
(ii)
The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities
Exchange Act of 1934, as amended) (a “ Covered Person ”) of beneficial ownership (within the meaning of rule 13d-3
promulgated under the Exchange Act) of 35% or more of either (A) the then outstanding shares of the common stock of the
Company (the “ Outstanding Company Common Stock ”), or (B) the combined voting power of the then outstanding voting
securities of the Company entitled to vote generally in the election of directors (the “ Outstanding Company Voting Securities
”); provided , however , that for purposes of this subsection (i) of this Section 1(a), the following acquisitions shall not
constitute a Change in Control of the Company: (A) any acquisition directly from the Company, (B) any acquisition by the
Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any
entity controlled by the Company, or (D) any acquisition by any corporation pursuant to a transaction which complies with
clauses (A), (B) and (C) of subsection (iii) of this Section 1(a); or
Individuals who, as of the Grant Date, constitute the Board (the “ Incumbent Board ”) cease for any reason to constitute at
least a majority of the Board; provided , however , that any individual becoming a director subsequent to the Grant Date
whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of
the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the
Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of
an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a Covered Person other than the Board; or
-1-
(iii)
Consummation of (xx) a reorganization, merger or consolidation or sale of the Company or any subsidiary of the Company, or
(yy) a disposition of all or substantially all of the assets of the Company (a “ Business Combination ”), in each case, unless,
following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial
owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately
prior to such Business Combination beneficially own, direct or indirectly, more than 65% of, respectively, the then
outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination
(including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all
of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their
ownership immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding
Company Voting Securities, as the case may be, (B) no Covered Person (excluding any employee benefit plan (or related
trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or
indirectly, 35% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such
Business Combination or the combined voting power of the then outstanding voting securities of such corporation, except to
the extent that such ownership existed prior to the Business Combination, and (C) at least a majority of the members of the
board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the
time of the execution of the initial agreement, or, if earlier, of the action of the Board, providing for such Business
Combination.
(b)
(c)
“ Forfeiture Restrictions ” shall mean any prohibitions and restrictions set forth herein with respect to the sale or other disposition of RSUs
issued to the Recipient hereunder and the obligation to forfeit and surrender such RSUs to the Company.
“ Restricted Period ” shall mean the period designated by the Company during which the RSUs are subject to Forfeiture Restrictions under
this Agreement.
Capitalized terms not otherwise defined in this Agreement shall have the meanings given to such terms in the Plan.
2.
3.
Grant
of
Restricted
Stock
Units
. Effective as of the Grant Date, the Company hereby grants to the Recipient pursuant to the terms and conditions of
the Plan and this Agreement the following number of RSUs: _________. Each RSU shall represent the right to receive one share of the Company’s
common stock, $.01 par value per share (“ Common Stock ”) on the conditions set forth herein. During the Restricted Period, the RSUs will be
evidenced by entries in a bookkeeping ledger account which reflect the number of RSUs credited under the Plan for the Recipient’s benefit.
Vesting
and
Settlement
. The RSUs that are granted hereby shall be subject to the Forfeiture Restrictions. The Restricted Period and all of the
Forfeiture Restrictions on the RSUs shall lapse and the RSUs shall vest as follows (it being understood that the number of RSUs as to which all
restrictions have lapsed and which have vested in the Recipient at any time shall be the greatest of the number of vested RSUs specified in
subparagraph (a), (b), (c) or (d) below):
(a)
(b)
The Recipient shall become 100% vested as to the RSUs on the first anniversary of the Grant Date.
If the Recipient’s service as a Director is terminated for any reason other than death or disability before all the RSUs have vested, the
RSUs that have not vested shall be forfeited and the Recipient shall cease to have any rights with respect to such forfeited RSUs.
-2-
(c)
(d)
In the event of the death or disability of the Recipient while a Director and before all of the RSUs have vested, the Recipient shall become
vested in the number of RSUs equal to the product of (A) 100% of the RSUs that are granted hereby, multiplied by (B) a fraction, the
numerator of which is the number of days in the period commencing on and including the Grant Date and ending on and including the date
of the Recipient’s death or disability, and the denominator of which is 365.
Upon the occurrence of a Change in Control of the Company, the RSUs that have not vested as of the date of such Change in Control of
the Company shall be 100% vested; provided, however , that this subparagraph (d) shall not apply if the Recipient is the Covered Person or
forms part of the Covered Person as specified in Section 1(a)(i) that acquires 35% or more of either the Outstanding Company Common
Stock or Outstanding Company Voting Securities and such acquisition constitutes a Change in Control of the Company.
RSUs that do not become vested pursuant to subparagraphs (a), (c) or (d) above shall be forfeited and the Recipient shall cease to have any rights with
respect to such forfeited RSUs.
On the date the RSUs granted hereunder become vested, the Recipient shall be entitled to receive one Share, which shall be delivered or transferred as
soon as administratively practicable thereafter in exchange for each vested RSU granted hereunder and after such delivery or transfer the Recipient
shall have no further rights with respect to such RSU. The Company shall cause to be delivered or transferred to the Recipient (or the Recipient’s legal
representative or heir) a stock certificate representing those shares of the Common Stock issued in exchange for RSUs awarded hereby or shall cause
the shares to be registered on the applicable stock transfer records in the Recipient’s name, and such shares of the Common Stock shall be transferable
by the Recipient (except to the extent that any proposed transfer would, in the opinion of counsel satisfactory to the Company, constitute a violation of
applicable federal or state securities law).
Dividend
Equivalents
. During the Restricted Period, Dividend Equivalents with respect to the RSUs shall be accrued and credited, without interest, to
a notional account and shall be subject to the same vesting and payment schedule as the underlying RSUs and payable in cash.
Section
409A.
The RSUs granted hereby are subject to the payment timing and other restrictions set forth in Section 13.14 of the Plan.
Transfer
Restrictions
. The RSUs granted hereby may not be sold, assigned, pledged, exchanged, hypothecated or otherwise transferred, encumbered
or disposed of to the extent then subject to the Forfeiture Restrictions. Any such attempted sale, assignment, pledge, exchange, hypothecation, transfer,
encumbrance or disposition in violation of this Agreement shall be void and the Company shall not be bound thereby. Notwithstanding the foregoing,
the Recipient may assign or transfer the RSUs granted hereby pursuant to a qualified domestic relations order (as defined in Section 414(p) of the
Internal Revenue Code of 1986, as amended, or Section 206(d)(3) of the Employee Retirement Income Security Act of 1974, as amended) or with the
consent of the Committee (i) for charitable donations; (ii) to the Recipient’s spouse, children or grandchildren (including any adopted and stepchildren
and grandchildren), or (iii) a trust for the benefit of the Recipient or the persons referred to in clause (ii) (each transferee thereof, a “ Permitted
Assignee ”); provided that such Permitted Assignee shall be bound by and subject to all of the terms and conditions of the Plan and this Award
Agreement and shall execute an agreement satisfactory to the Company evidencing such obligations, relating to the RSUs; and provided further that
the Recipient shall remain bound by the terms and conditions of the Plan. Further, any Shares delivered upon the vesting of the RSUs awarded
hereunder may not be sold or otherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws,
and the Recipient agrees (i) that the Company may refuse to cause the transfer of such shares to be registered on the applicable stock transfer records if
such proposed transfer would, in the opinion of counsel satisfactory to the Company, constitute a violation of any applicable securities law, and (ii) that
the Company may give related instructions to the transfer agent, if any, to stop registration of the transfer of such shares.
-3-
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
Capital
Adjustments
and
Reorganizations
. The existence of the RSUs shall not affect in any way the right or power of the Company or any company
the stock of which is awarded pursuant to this Agreement to make or authorize any adjustment, recapitalization, reorganization or other change in its
capital structure or its business, engage in any merger or consolidation, issue any debt or equity securities, dissolve or liquidate, or sell, lease, exchange
or otherwise dispose of all or any part of its assets or business, or engage in any other corporate act or proceeding.
No
Fractional
Shares
. All provisions of this Agreement concern whole Shares. Notwithstanding anything contained in this Agreement to the
contrary, if the application of any provision of this Agreement would yield a fractional share, such fractional share shall be rounded down to the next
whole Share.
No
Obligation
to
Retain
Services
. This Agreement is not a services or employment agreement, and no provision of this Agreement shall be
construed or interpreted to guarantee the Recipient the right to remain a Director for any specified term.
Notices
. Any notice, instruction, authorization, request or demand required hereunder shall be in writing, and shall be delivered either by personal
delivery, by telegram, telex, telecopy or similar facsimile means, by certified or registered mail, return receipt requested, by facsimile transmission or
by courier or delivery service, to the Company at 10713 West Sam Houston Parkway N., Suite 800, Houston, Texas 77064, Attention: Chief Financial
Officer, facsimile number (281) 765-7175, and to the Recipient at the Recipient’s address and facsimile number (if applicable) indicated beneath the
Recipient’s signature on the execution page of this Agreement, or at such other address and facsimile number as a party shall have previously
designated by written notice given to the other party in the manner hereinabove set forth. Notices shall be deemed given when received, if sent by
facsimile means (confirmation of such receipt by confirmed facsimile transmission being deemed receipt of communications sent by facsimile means);
and when delivered (or upon the date of attempted delivery where delivery is refused), if hand-delivered, sent by express courier or delivery service, or
sent by certified or registered mail, return receipt requested.
Amendment
and
Waiver
. Except as otherwise provided in Section 12.1 of the Plan, this Agreement may be amended, modified or superseded only by
written instrument executed by the Company and the Recipient. Only a written instrument executed and delivered by the party waiving compliance
hereof shall make any waiver of the terms or conditions effective. Any waiver granted by the Company shall be effective only if executed and
delivered by a duly authorized executive officer of the Company. The failure of any party at any time or times to require performance of any
provisions hereof shall in no manner affect the right to enforce the same. No waiver by any party of any term or condition, or of any breach of any term
or condition, contained in this Agreement, in one or more instances, shall be construed as a continuing waiver of any such condition or breach, a
waiver of any other term or condition, or a waiver of any breach of any other term or condition.
Governing
Law
and
Severability
. This Agreement shall be governed by the laws of the State of Delaware without regard to its conflicts of law
provisions. The invalidity of any provision of this Agreement shall not affect any other provision of this Agreement, which shall remain in full force
and effect.
Successors
and
Assigns
. Subject to the limitations which this Agreement imposes upon the transferability of the RSUs granted hereby, this Agreement
shall bind, be enforceable by and inure to the benefit of the Company and its successors and assigns, and to the Recipient and the Recipient’s Permitted
Assignees, executors, administrators, agents, legal and personal representatives.
Counterparts
. This Agreement may be executed in two or more counterparts, each of which shall be an original for all purposes but all of which
taken together shall constitute but one and the same instrument.
Grant
Subject
to
Terms
of
Plan
and
this
Agreement
. The Recipient acknowledges and agrees that the grant of the RSUs hereunder is made pursuant
to and governed by the terms of the Plan and this Agreement, ratifies and consents to any action taken by the Company, the Board of Directors or the
Committee concerning the Plan and agrees that the grant of the RSUs pursuant to this Agreement is subject in all respects to the more detailed
provisions of the Plan.
[SIGNATURES BEGIN ON FOLLOWING PAGE]
-4-
IN WITNESS WHEREOF , the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized, and the Recipient has
executed this Agreement, all effective as of the date first above written.
PATTERSON-UTI ENERGY, INC.:
By:
Name:
Title:
RECIPIENT:
[Name]
Address:
Facsimile No.:
5
Subsidiaries of the Registrant
Exhibit 21.1
Name
Ambar Lone Star Fluid Services LLC
Drilling Technologies 1 LLC
Drilling Technologies 2 LLC
Great Plains Oilfield Rental, L.L.C.
Keystone Rock & Excavation, L.L.C.
MS Directional, LLC
Patterson Petroleum LLC
Patterson UTI Energy Arabia DMCC
Patterson UTI International Saudi Arabia Limited
Patterson-UTI Drilling Canada Limited
Patterson-UTI Drilling Company LLC
Patterson-UTI Drilling International, Inc.
Patterson-UTI Global Resources Management Office Limited
Patterson-UTI International (Netherlands) Coöperatief U.A.
Patterson-UTI International Holdings (BVI) Limited
Patterson-UTI International Holdings (Netherlands) One B.V.
Patterson-UTI International Holdings (Netherlands) Two B.V.
Patterson-UTI International Holdings GP (BVI), Inc.
Patterson-UTI International Holdings GP 1 LLC
Patterson-UTI International Holdings, Inc.
Patterson-UTI International (India) B.V.
Patterson-UTI International (Kuwait) Limited
Patterson-UTI Management Services, LLC
PTEN International Holdings (Netherlands) 1 C.V.
PTEN International Leasing (Netherlands) 2 C.V.
PTL Prop Solutions, L.L.C.
Seventy Seven Energy LLC
Seventy Seven Land Company LLC
Seventy Seven Operating LLC
Universal Pressure Pumping, Inc.
Warrior Rig Technologies Limited
Warrior Rig Technologies US LLC
Western Wisconsin Sand Company, LLC
State of
Incorporation or
organization
Texas
Delaware
Delaware
Oklahoma
Oklahoma
Texas
Texas
United Arab Emirates
Kingdom of Saudi Arabia
Nova Scotia
Texas
Delaware
Dubai International Financial Centre
The Netherlands
British Virgin Islands
The Netherlands
The Netherlands
British Virgin Islands
Delaware
Delaware
The Netherlands
British Virgin Islands
Delaware
The Netherlands
The Netherlands
Oklahoma
Delaware
Oklahoma
Oklahoma
Delaware
Alberta
Delaware
Wisconsin
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-215678 and 333-220922) and Form S-8 (Nos. 333-
166434, 333-126016, 333-152705, 333-195410, 333-217414, and 333-219063) of Patterson-UTI Energy, Inc. of our report dated February 20, 2018 relating to the
consolidated financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23.1
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 20, 2018
Exhibit 31.1
I, William Andrew Hendricks, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.;
CERTIFICATIONS
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during
the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 20, 2018
/s/ William Andrew Hendricks, Jr.
William Andrew Hendricks, Jr.
President and Chief Executive Officer
Exhibit 31.2
I, C. Andrew Smith, certify that:
1. I have reviewed this annual report on Form 10-K of Patterson-UTI Energy, Inc.;
CERTIFICATIONS
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during
the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
/s/ C. Andrew Smith
C. Andrew Smith
Executive Vice President and
Chief Financial Officer
Date: February 20, 2018
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
NOT FILED PURSUANT TO THE SECURITIES EXCHANGE ACT OF 1934
Exhibit 32.1
In connection with the Annual Report of Patterson-UTI Energy, Inc. (the “Company”) on Form 10-K for the period ended December 31, 2017, as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), William Andrew Hendricks, Jr., Chief Executive Officer, and C. Andrew Smith, Chief
Financial Officer, of the Company, each certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to
his knowledge:
(1)
(2)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange Commission upon request. The foregoing is being furnished solely pursuant to said Section 906 and Rule 13a-14(b) promulgated under
the Securities Exchange Act of 1934, as amended, and is not being filed as part of the Report or as a separate disclosure document.
/s/ William Andrew Hendricks, Jr.
William Andrew Hendricks, Jr.
Chief Executive Officer
February 20, 2018
/s/ C. Andrew Smith
C. Andrew Smith
Chief Financial Officer
February 20, 2018