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, 2018
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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§
232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth 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 29, 2018, the last business day of the registrant’s
most recently completed second fiscal quarter, was approximately $3.9 billion, calculated by reference to the closing price of $18.00 for the common stock on the Nasdaq Global
Select Market on that date.
As of February 8, 2019, the registrant had outstanding 213,652,772 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 2019 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, press releases and presentations 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. As used in this Report, “the Company,” “us,” “we,” our” and like terms refer collectively to
Patterson-UTI Energy, Inc. and its consolidated subsidiaries. Patterson-UTI Energy, Inc. conducts its operations through its wholly-owned subsidiaries and has no
employees or independent business operations. 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.
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:
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adverse oil and natural gas industry conditions;
global economic conditions;
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;
excess availability of land drilling rigs, pressure pumping and directional drilling equipment, including as a result of reactivation, improvement or
construction;
competition and demand for our services;
strength and financial resources of competitors;
utilization, margins and planned capital expenditures;
liabilities from operational risks for which we do not have and receive full indemnification or insurance;
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);
the ability to realize backlog;
specialization of methods, equipment and services and new technologies;
shortages, delays in delivery, and interruptions in supply, of equipment and materials;
cybersecurity events;
the ability to retain management and field personnel;
loss of key customers;
synergies, costs and financial and operating impacts of acquisitions;
difficulty in building and deploying new equipment;
governmental regulation;
environmental risks and ability to satisfy future environmental costs;
legal proceedings and actions by governmental or other regulatory agencies;
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technology-related disputes;
the ability to effectively identify and enter new markets;
weather;
operating costs;
expansion and development trends of the oil and natural gas industry;
ability to obtain insurance coverage on commercially reasonable terms;
financial flexibility;
interest rate volatility;
adverse credit and equity market conditions;
availability of capital and the ability to repay indebtedness when due;
compliance with covenants under our debt agreements; and
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.
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. 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, 2018, we had a drilling fleet that consisted of 252 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. Substantially all of
the revenue in the pressure pumping segment is from well stimulation services (such as hydraulic fracturing) for 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. We
also provide cementing services through the pressure pumping segment. Cementing is the process of inserting material between the wall of the well bore and the
casing to support and stabilize the casing. As of December 31, 2018, 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, motor rentals, directional surveying, measurement-while-drilling, wireline steering
tools and services that improve the accuracy of horizontal wellbore placement.
We have other operations through which we provide oilfield rental tools in select markets in the United States. We also manufacture and sell pipe handling
components and related technology to drilling contractors, and provide electrical controls and automation to the energy, marine and mining industries, 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 October 25, 2018, we acquired all of the issued and outstanding shares of Current Power Solutions, Inc. (“Current Power”). Current Power is a provider of
electrical controls and automation to the energy, marine and mining industries.
On March 27, 2018, we entered into an amended and restated credit agreement, which is a committed senior unsecured revolving credit facility that permits
aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that,
at any time outstanding, is limited to $20 million.
On February 20, 2018, we acquired the business of Superior QC, LLC (“Superior QC”), including its assets and intellectual property. Superior QC is a provider
of software and services used to improve the statistical accuracy of horizontal wellbore placement. Superior QC’s measurement-while-drilling (MWD) Survey
FDIR (fault detection, isolation and recovery) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify the
position of a well.
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”) . 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.
3
On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of M S Directional , LLC (f/k/a Multi-Shot, LLC) (“MS
Directional”) . MS Directional is a leading directional drilling services company in the Unit ed 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, motor
rentals, directional surveyin g, measurement - while - drilling, and wireline steering tools.
On April 20, 2017, pursuant to an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), a subsidiary of ours was
merged with and into SSE (the “SSE merger”), with SSE continuing as the surviving entity and one of our wholly-owned subsidiaries. On April 20, 2017,
following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Seven 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 fracturing equipment located in Oklahoma
and Texas. The oilfield rentals business acquired through the SSE merger has a 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 Current Power since October 25, 2018, the results of
operations of Superior QC since February 20, 2018, 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 2016, 2017 and 2018 are as follows:
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)
2018:
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
$ 33.18
$ 45.41
$ 44.85
$ 49.15
71
55
60
66
$ 51.77
$ 48.24
$ 48.16
$ 55.37
81
145
159
159
$ 62.88
$ 68.04
$ 69.76
$ 59.08
166
175
177
182
(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 prices have recovered from the lows experienced in the first quarter of 2016. Oil prices reached a high of $77.41 in June 2018. Oil
prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42% over the
course of three months to reach a low of $44.48 per barrel in late December 2018. Oil prices averaged $59.08 per barrel in the fourth quarter of 2018.
Our rig count declined significantly during the industry downturn that began in late 2014 but has improved since the second quarter of 2016. Our average rig
count for the fourth quarter of 2018 was 183 rigs, which included 182 rigs in the United States and one rig in Canada. This was an increase from our average rig
count for the third quarter of 2018 of 178 rigs, which included 177 rigs in the United States and one rig in Canada. Our rig count in the United States at December
31, 2018 of 183 rigs was greater than the rig count of 163 rigs at December 31, 2017. Term contracts have supported our operating rig count during the last three
years. Based on contracts currently in place, we expect an average of 122 rigs operating under term contracts during the first quarter of 2019 and an average of 78
rigs operating under term contracts throughout 2019.
With the weakness in crude oil prices late in the fourth quarter, operators have been delaying starting new completion projects in the first quarter, and pricing
remains extremely competitive. As such, we have made the decision to idle spreads rather than work at unreasonably low prices. We ended the fourth quarter with
20 active spreads and idled three spreads early in the first quarter of 2019 .
Industry Segments
Our revenues, operating income (loss) and identifiable assets are primarily attributable to three industry segments:
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contract drilling services,
pressure pumping services, and
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directional drilling services .
Our contract drilling services industry segment had operating losses in 2018, 2017 and 2016. Our pressure pumping services industry segment had operating
losses in 2018 and 2016 and operating income in 2017. Our third industry segment, directional drilling services, was a new segment for us as a result of the MS
Directional acquisition in 2017 and accounted for approximately six percent and two percent of our 2018 and 2017 consolidated revenues, respectively. Our
directional drilling segment had operating losses in 2018 and 2017.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16 of Notes to Consolidated 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, 2018, we had
252 marketed land-based drilling rigs based in the following regions:
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74 in west Texas and southeastern New Mexico,
24 in north central and east Texas and northern Louisiana,
37 in the Rocky Mountain region (Colorado, Wyoming and North Dakota),
31 in south Texas,
38 in western Oklahoma,
42 in the Appalachian region (Pennsylvania, Ohio and West Virginia), and
6 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 $822 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 2018, 2017 and 2016, we spent approximately $395 million,
$354 million and $72.5 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 four years) or for a specified number of
wells. During 2018, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 21 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.
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Our drilling contracts provide for payment on a daywork basis , pursuant to which 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 wh en 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.
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
2018
Year Ended December 31,
2017
2016
175
1
193
3,088
64,479
136
2
179
2,553
50,427
63
2
100
1,164
23,596
(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, 2018, 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
169
14
4
5
6
48
246
—
—
—
—
—
6
6
169
14
4
5
6
54
252
1,465
1,117
1,457
94%
100%
100%
100%
67%
59%
87%
The U.S. land rig industry refers to certain high specification rigs as “super-spec” rigs. We consider a super-spec rig to be at least a 1,500 horsepower, AC
powered rig that has a 750,000-pound hookload, a 7,500-psi circulating system, and is pad-capable. We currently estimate there are approximately 650 super-spec
rigs in the United States, which includes 149 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, Ohio 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), the Mid-Continent region
(Mid-Con Region) and the Appalachian region (Northeast Region). Pressure pumping services consist primarily of well stimulation services (such as hydraulic
fracturing) 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 and proppant under pressure into the well
bore to fracture the formation. Many wells in conventional plays also receive well stimulation services. We also provide cementing services through the pressure
pumping segment. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing.
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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 cont racts are generally entered into for a specified period of time and may include minimum revenue, 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 cementing and acid pumping services, with a
total of approximately 1.6 million horsepower as of December 31, 2018. Pressure pumping equipment at December 31, 2018 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
229
524,450
138
334,750
118
269,250
200
430,050
31
32,340
1
950
—
—
78
44,700
260
556,790
139
335,700
118
269,250
278
474,750
685
1,558,500
110
77,990
795
1,636,490
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 may not cover all of our required supply. These supply arrangements 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, motor rentals, 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, assemble and maintain our own fleet of downhole drilling motors and MWD
equipment. We sometimes 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.
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Directional Drilling Services – We provide our directional drilling services on a day-rate basis, typically under master service agree ments. Revenue from
directional drilling services is recognized as work progresses based on the number 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 an d 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
whe n 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 direction al 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, assemble, maintain and inspect our own equipment. We sometimes 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 the 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, 2018, 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 127
MWD systems as well as downhole surveying equipment to provide accurate wellbore surveys.
Horizontal Wellbore Placement – We provide software and services used to improve the statistical accuracy of horizontal wellbore placement. Our
measurement-while-drilling (MWD) Survey FDIR (fault detection, isolation and recovery) service is a data analytics technology to analyze MWD survey data in
real-time and more accurately identify the position of a well. We provide these services to customers with onshore and offshore operations.
Oilfield Rentals
Our oilfield rentals business has a 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 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.
Other Operations
We manufacture and sell pipe handling components and related technology for drilling contractors in North America and other select markets, and provide
electrical controls and automation to the energy, marine and mining industries, 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.
Contracts
We believe that our contract drilling, pressure pumping, directional drilling, oilfield rentals and other 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 or supplier, any of which rights and obligations may deviate from what is customary due to particular industry conditions,
customer or supplier requirements, applicable law or other factors.
8
Customers
Our customer base includes major, independent and other oil and natural gas operators. With respect to our consolidated operating revenues in 2018, we
received approximately 41% from our ten largest customers and approximately 26% from our five largest customers. During 2018, 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.
Backlog
Our contract drilling backlog as of December 31, 2018 and 2017 was $770 million and $544 million, respectively. Approximately 23% of the total contract
drilling backlog at December 31, 2018 is reasonably expected to remain after 2019. 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. 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 and acidizing and related well servicing activities,
directional drilling services, third-party motor rentals, and downhole survey services,
services that improve the statistical accuracy of horizontal wellbore placement, including for customers with offshore operations,
containment and disposal of hazardous materials, oilfield waste, other waste materials and acids,
use of underground storage tanks and injection wells,
• manufacture and sale of pipe handling components and related technology,
•
•
provision of electrical controls and automation, 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 and products 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
9
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 pri or 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.
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 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 criteria regulations pertaining to oil and gas wastes or to
sign a determination that revision of the regulations is not necessary. The EPA has not yet proposed such a rule. 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.”
10
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, handli ng, 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 en vironmental 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 sa tisfaction 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
frequ ent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.
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 Occupational 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, explosions, 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. An accident or other event resulting in significant
environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local
authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as
cause lasting damage to our reputation, loss of customers and an inability to obtain insurance.
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.
11
Our insurance may 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 fut ure, 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.”
Employees
We had approximately 8,000 full-time employees as of February 8, 2019. 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 calendar years, we sometimes 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 availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate,
the environmental, tax and other laws and governmental regulations regarding the exploration, development, production, use 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
12
• merger and divestiture activity among oil and natural gas producers.
In particular, our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future
prices. Oil and natural gas prices and markets can be 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”), its members and other oil-producing nations, such as Russia, 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
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 experienced a severe decline in 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. Oil prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42%
over the course of three months to reach a low of $44.48 per barrel in late December 2018.
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. An economic slowdown or recession in the United States or in any other country that significantly affects the supply of or demand for oil or natural gas
could negatively impact our operations and therefore adversely affect our results. 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.
13
Ex
cess
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.
We periodically seek to increase the prices on our services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a
very competitive industry, and we are not always successful in raising or maintaining our existing prices. With the active rig count below the peak seen in 2014 and
many rigs, including highly capable AC rigs, and pressure pumping equipment still idle, there is considerable pricing pressure in the industry. Even if we are able
to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs without adversely affecting our activity levels. The inability to
maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial condition, cash flows and results of
operations. 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 oil and natural gas service contractors to have difficulty maintaining pricing, 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 service
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. For example, we recognized impairment charges of $277 million and $29 million in 2018 and 2017, respectively.
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.
Our operations are subject to many hazards inherent in the businesses in which we operate, including inclement weather, blowouts, explosions, 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. An accident or other event resulting in significant
environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local
authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as
cause lasting damage to our reputation, loss of customers and an inability to obtain insurance .
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. 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.
14
We maintain insurance coverage of types and amounts that we believe to be customary in the indu stry, 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 eq uipment 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 cove r 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 generall y 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, a nd 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 security risks, and we do not carry a
significant amount of insurance to cover risks of underground reservoir damage.
Our insurance may 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.
Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of our employees
who was injured in the accident. The lawsuits have been consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). These lawsuits
allege various causes of action against us including negligence, gross negligence, knowledge that injury or death was substantially certain, acting with purpose,
recklessness, wrongful death and survival, and the plaintiffs seek an unspecified amount of damages, including punitive or exemplary damages, costs, interest, and
other relief. We dispute the plaintiffs’ allegations and intend to continue to defend ourselves vigorously. Based on the information we have available as of the date
of this Report, we believe that we have adequate insurance to cover the Litigation. 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.
Our
Current
Backlog
of
Contract
Drilling
Revenue
May
Decline
and
May
Not
Ultimately
Be
Realized,
as
Fixed-Term
Contracts
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, 2018, 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 $770
million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of our calculation of backlog. Our
contract drilling backlog may decline, as fixed-term drilling contract coverage over time may not be offset by new contracts or may be reduced by price
adjustments to existing 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 pressure pumping and other equipment. Our customers are increasingly
demanding the services of newer, higher specification drilling rigs and pressure pumping and other equipment. Accordingly, a higher level of capital expenditures
may be required to maintain and improve existing
15
rigs and pressure pumping and other equipment and purchase and construct newer, higher specification drilling rigs and pressure pumping and other equipment to
meet the increasingly sophisticated needs of our customers. In addition, technologic al 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 business es 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 and technology 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 reduce our competitiveness
and 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.
Loss
of
Key
Personnel
and
Competition
for
Experienced
Personnel
May
Negatively
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 2018, we received approximately 41% from our ten largest customers, 26% 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.
16
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, attempts to
gain unauthorized access to our data and systems, 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, including via “phishing” or similar attacks directed at us or our customers;
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;
destruction or damage to our and our customers’ equipment;
downtime and loss of revenue;
injury to our reputation;
negative impacts on our ability to compete;
loss or damage to our worksite data delivery systems; and
increased costs to prevent, respond to or mitigate cybersecurity events.
Although we utilize various procedures and controls to mitigate our exposure to such risks, 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 incident could go unnoticed for a period of time. Any such incident could have a material adverse effect
on our business, financial condition, cash flows and results of operations.
Growth
Through
Acquisitions,
the
Building
of
New
Rigs
and
Pressure
Pumping
Equipment
and
the
Development
of
Technology
Is
Not
Assured.
We have grown our drilling rig fleet and pressure pumping fleet and expanded our business lines and use of technology in the past through mergers,
acquisitions, new construction and technology development. 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 or developing new technology. 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, our competitors may continue to build
new, high technology rigs and new, high horsepower equipment and develop new technology.
There can be no assurance that we will:
•
•
•
•
have sufficient capital resources to complete additional acquisitions, build new rigs or pressure pumping equipment or develop new technology,
successfully integrate additional drilling rigs, pressure pumping equipment, acquired or developed technology or other assets or businesses,
effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping equipment,
successfully deploy idle, stacked, upgraded or additional rigs, pressure pumping equipment and acquired or developed technology,
• maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment or the personnel necessary to evaluate, develop and deploy
new technology, or
•
successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition, the building of new
drilling rigs and pressure pumping equipment or the development of new technology.
17
Our failure to achieve consolidation savings, to inte grate acquired businesses and technology and other 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 f rom events
prior to any acquisitions , prior to our establishment of adequate compliance oversight or in connection with disputes over acquired or developed technology .
While we generally seek to obtain indemnities for liabilities arising from events occurr ing 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 new pressure pumping equipment or develop new technology,
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.
Environmental
and
Occupational
Health
and
Safety
Laws
and
Regulations,
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 or judgments,
• 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 places that 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 equipment and automation to the energy, marine and mining industries 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. The EPA
finalized amendments to some requirements in these standards in February 2018 and September 2018, including rescission of certain requirements and revisions to
other requirements such as fugitive emissions monitoring frequency. In November 2016, the EPA announced that it intends to impose methane emission standards
for existing sources and issued information collection requests for oil and natural gas facilities. That information request was withdrawn in March 2017. 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’s Bureau of Land Management (“BLM”) 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 BLM issued a two-year stay of these requirements in
December 2017. In February 2018, the BLM proposed to repeal certain of the requirements of the 2016 methane rules. Several states filed judicial challenges to the
BLM’s proposed repeal. In April 2018, a federal court stayed the litigation pending finalization or withdrawal of the BLM’s February 2018 proposal. In September
2018, the BLM published a final rule that largely adopted the February 2018 proposal and rescinded several requirements. The September 2018 rule was challenged
in the U.S. District Court for the Northern District of California almost immediately after issuance. The challenge is still pending. 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.
18
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.
In addition, legislation 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 hydraulic 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. The EPA has not yet finalized this rule.
Further, in March 2015, the BLM issued a final rule to regulate hydraulic fracturing on Indian land. The rule required companies to publicly disclose chemicals
used in hydraulic fracturing operations to the BLM. However, this rule was 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. In November
2018, voters rejected an initiative that would have materially restricted hydraulic fracturing activity in Colorado.
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.
19
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. 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 hydraulically 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, every 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. Due to the Paris Agreement’s protocol, the earliest the United
States will be able to withdraw is 2020. However, several 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 United 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 direct 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.
The
Design,
Manufacture,
Sale
and
Servicing
of
Products,
including
Electrical
Controls
and
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 electrical controls and rig components such as top drives, to customers involved in oil and gas exploration, development and
production and in the marine and mining industries. 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 harm to our reputation, contractual and warranty-related liability, damage to the equipment,
damage to the property of customers and others, personal injury and environmental contamination, leading to claims against us.
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 EPA, OSHA and
the U.S. Chemical Safety and Hazard Investigation Board (“CSB”) initiated investigations relating to the January 22, 2018 accident at a drilling site in Pittsburg
County, Oklahoma. The EPA and CSB investigations are ongoing. 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. Please see “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.”
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, or a third party’s
infringement of our 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 customers or supplying vendors
becomes involved in a dispute over infringement of intellectual property rights relating to equipment or technology owned or used by us, services performed by us
or products provided by us, we may lose access to important equipment or technology or our ability to provide services or products, or we could be required
20
to cease use of some equipment or technology or forced to modify our equipment, technology, services or products. We could also be required to pay licens e fees
or royalties for the use of equipment or technology or provision of services or products. In addition, we may lose a competitive advantage in the event we are
unsuccessful in enforcing our rights against third parties. Technology disputes involvin g us or our customers or supplying vendors could have a material adverse
impact on our business, financial condition , cash flows and results of operation s .
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 and electrical controls, 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.
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 effect 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 be 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. While 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 operations 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 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.
21
We
Are
Dependent
Upon
Our
Subsidiaries
to
Meet
our
Obligations
Under
O
ur
Long-Term
Debt
.
We have borrowings outstanding under our senior notes and, from time to time, our revolving credit facility. 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
1.00% to 2.00% and the applicable margin on base rate loans varies from 0.00% to 1.00%, in each case determined based upon our credit rating. As of
December 31, 2018, the applicable margin on LIBOR rate loans was 1.50% and the applicable margin on base rate loans was 0.50%. As of December 31, 2018, we
had no amounts outstanding under our revolving credit facility.
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, 2018, 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, industry
conditions 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.
22
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.
As
a
Result
of
the
SSE
Merger,
We
Are
Subject
to
Continuing
Contingent
T
ax
Liabilities
of
Chesapeake
Energy
Corporation
(“CHK”)
F
ollowing
SSE’s
Spin-Off
from
CHK.
Under the Internal Revenue Code of 1986, as amended (the “Code”), and the related rules and regulations, each corporation (or its successor) 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
entered into a tax sharing agreement with CHK that generally provides that SSE is responsible for all taxes attributable to its business, whether accruing before, on
or after the date of the spin-off, and CHK is responsible for any taxes arising from the spin-off or certain related transactions that are imposed on SSE, CHK or its
other subsidiaries. Notwithstanding such agreement, if CHK were unable to pay the taxes it is responsible for, we (as the successor to SSE) could be required to pay
the entire amount of such taxes under U.S. tax law, which could have a material adverse effect on us.
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, 2018, we had gross federal income tax NOLs of approximately $1.3 billion, approximately $247 million of which were assumed in
connection with the SSE merger. 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. Any NOL arising prior to January 1, 2018 is subject to expiration 20 years after it arose. NOLs arising on or after January 1, 2018 are not
subject to expiration .
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—our NOLs relating to SSE 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 prior to their expiration. Future changes in stock ownership
or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with 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.
23
Our corporate headquarters is in leased office space and is located at 10713 W. Sam Hou ston 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 electrical controls and automation operation is
supported by an office and yard facility in 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 5 of the Notes to
Consolidated Financial Statements included in Item 8 of this Report.
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 CSB initiated investigations related to this accident. The EPA and the CSB investigations are ongoing, and we are cooperating with the
agencies regarding these investigations.
On July 18, 2018, OSHA issued a citation containing alleged violations, proposed abatement dates and an aggregate proposed penalty of approximately
$74,000. We have filed a notice of contest with OSHA that contests all citation items, abatement dates and proposed penalties. The Department of Labor filed a
complaint on OSHA’s behalf seeking enforcement of the citation as issued. We have filed an answer to the complaint and are litigating our contest of the citation
items. The ultimate resolution of the OSHA citation items is not known at this time, and we are unable to determine what alleged violations and proposed
penalties will be modified or eliminated, if any.
Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of our
employees who was injured in the accident. The lawsuits have been consolidated for discovery purposes under Cause No. CJ-2018-60 (the “Litigation”). These
lawsuits allege various causes of action against us including negligence, gross negligence, knowledge that injury or death was substantially certain, acting with
purpose, recklessness, wrongful death and survival, and the plaintiffs seek an unspecified amount of damages, including punitive or exemplary damages, costs,
interest, and other relief. We dispute the plaintiffs’ allegations and intend to continue to defend ourselves vigorously. Based on the information we have available
as of the date of this Report, we believe that we have adequate insurance to cover the Litigation. However, if this accident 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, cash flows and results of operations.
Item 4. Mine
Safety
Disclosure.
Not applicable.
24
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.
PART II
(b)
Holders
As of February 8, 2019, there were approximately 1,100 holders of record of our common stock.
(c)
Dividends
On February 6, 2019, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 21, 2019 to
holders of record as of March 7, 2019. 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.
(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, 2018.
Period Covered
October 2018
November 2018
December 2018
Total
Total Number of Shares
Purchased (1)
Average Price
Paid per Share
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) (2)
4,630 $
1,527,000 $
2,289,195 $
3,820,825
16.23
15.47
11.53
— $
1,527,000 $
2,288,278 $
3,815,278 $
200,260
176,641
150,263
150,263
(1)
(2)
We withheld 4,630 shares in October 2018 and 917 shares in December 2018 with respect to employees’ tax withholding upon vesting of restricted stock units. These
shares were acquired at fair market value pursuant to the terms of the Patterson-UTI Energy, Inc. Long-Term Incentive Plan and not pursuant to the stock buyback
program.
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. On July 26, 2018, we announced that our Board of Directors approved an increase of the authorization under the
stock buyback program to allow for $250 million of future share repurchases. 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. There is no expiration date associated with the buyback program. Shares of stock purchased under the plan are held as treasury shares. On February 7,
2019, we announced that our Board of Directors approved another increase of the authorization under the stock buyback program to allow for $250 million of future
share repurchases.
(e)
Performance
Graph
The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2013 through December 31, 2018,
with the cumulative total return of the S & P 500 Index, the S & P MidCap 400 Index, the Oilfield Service Index and a peer group determined by us. Our peer
group consists 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.
25
The graph assumes investment of $100 on December 31, 201 3 and reinvestment of all dividends.
Company/Index
Patterson-UTI Energy, Inc.
S&P 500 Stock Index
S&P MidCap Index
Oilfield Service Index
Peer Group Index
Fiscal Year Ended December 31,
2013
($)
100.00
100.00
100.00
100.00
100.00
2014
($)
2015
($)
66.58
113.69
109.77
76.46
74.09
61.99
115.26
107.38
58.59
51.06
2016
($)
111.59
129.05
129.65
69.71
65.20
2017
($)
2018
($)
95.74
157.22
150.70
57.71
55.40
43.44
150.33
134.00
31.62
31.77
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.
26
Item 6. Selected
Financial
Data.
Our selected consolidated financial data as of December 31, 2018, 2017, 2016, 2015, and 2014, and for each of the five years in the period ended December 31,
2018, 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 Current
Power since October 25, 2018, the results of operations of Superior QC since February 20, 2018, the results of operations of MS Directional since October 11, 2017
and the results of operations of SSE since April 20, 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
2018
2017
2016
(In thousands, except per share amounts)
2015
$
1,430,492 $
1,573,396
209,275
113,834
3,326,997
1,040,033 $
1,200,311
45,580
70,760
2,356,684
543,663 $
354,070
—
18,133
915,866
1,153,892 $
712,454
—
24,931
1,891,277
885,704
1,263,850
175,829
77,104
916,318
211,129
134,071
2,738
(17,569)
3,649,174
(322,177)
(45,231)
(367,408)
(45,987)
(321,421) $
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 $
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) $
(1.47) $
(1.47) $
0.03 $
0.03 $
(2.18) $
(2.18) $
(2.00) $
(2.00) $
0.14 $
0.08 $
0.16 $
0.40 $
2014
1,838,830
1,293,265
—
50,196
3,182,291
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
1.12
1.11
0.40
218,643
218,643
198,447
199,882
146,178
146,178
145,416
145,416
144,066
145,376
5,469,866 $
—
1,119,205
3,505,423
423,881
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
27
$
$
$
$
$
Item 7. Management’s
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations
Recent Developments — On October 25, 2018, we acquired all of the issued and outstanding shares of Current Power Solutions, Inc. (“Current
Power”). Current Power is a provider of electrical controls and automation to the energy, marine and mining industries. Operational and financial data in the
discussion and analysis below includes the results of operations of the Current Power business in our other operations since October 25, 2018.
On March 27, 2018, we entered into an amended and restated credit agreement, which is a committed senior unsecured revolving credit facility that permits
aggregate borrowings of up to $600 million, including a letter of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that,
at any time outstanding, is limited to $20 million. See “ Liquidity and Capital Resources.”
On February 20, 2018, we acquired the business of Superior QC, LLC (“Superior QC”), including its assets and intellectual property. Superior QC is a
provider of software and services used to improve the statistical accuracy of horizontal wellbore placement. Superior QC’s measurement-while-drilling (MWD)
Survey FDIR (fault detection, isolation and recovery) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify
the position of a well. Operational and financial data in the discussion and analysis below includes the results of operations of the Superior QC business in our
directional drilling segment since February 20, 2018.
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”) . We used
$239 million of the net proceeds from the sale to repay amounts outstanding under our revolving credit facility.
On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional, LLC (f/k/a Multi-Shot, LLC) (“MS
Directional”). 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, motor rentals,
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 in our directional drilling segment since October 11, 2017.
On April 20, 2017, pursuant to an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), a subsidiary of ours was
merged with and into SSE (the “SSE merger”), with SSE continuing as the surviving entity and one of our wholly-owned subsidiaries. On April 20, 2017,
following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Seven 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 fracturing equipment located in Oklahoma
and Texas. The oilfield rentals business acquired through the SSE merger has a 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 business since April 20, 2017.
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, and we provide services that improve the statistical accuracy of horizontal wellbore placement. We have other operations through
which we provide oilfield rental tools in select markets in the United States. We also manufacture and sell pipe handling components and related technology to
drilling contractors, and provide electrical controls and automation to the energy, marine and mining industries, 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.
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 prices have recovered from the lows experienced in the first quarter of 2016. Oil prices reached a high of $77.41 in June 2018. Oil
prices remain volatile, as the closing price of oil reached a fourth quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42% over the
course of three months to reach a low of $44.48 per barrel in late December 2018. Oil prices averaged $59.08 per barrel in the fourth quarter of 2018.
28
Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2016, 2017, and 2018 are as follows:
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
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)
2018:
Average
oil price
per Bbl
(1)
Average
rigs
operating
per day -
U.S. (2)
$ 33.18
$ 45.41
$ 44.85
$ 49.15
71
55
60
66
$ 51.77
$ 48.24
$ 48.16
$ 55.37
81
145
159
159
$ 62.88
$ 68.04
$ 69.76
$ 59.08
166
175
177
182
(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.
Our rig count declined significantly during the industry downturn that began in late 2014 but has improved since the second quarter of 2016. Our average rig
count for the fourth quarter of 2018 was 183 rigs, which included 182 rigs in the United States and one rig in Canada. This was an increase from our average rig
count for the third quarter of 2018 of 178 rigs, which included 177 rigs in the United States and one rig in Canada. Our rig count in the United States at December
31, 2018 of 183 rigs was greater than the rig count of 163 rigs at December 31, 2017. Term contracts have supported our operating rig count during the last three
years. Based on contracts currently in place, we expect an average of 122 rigs operating under term contracts during the first quarter of 2019 and an average of 78
rigs operating under term contracts throughout 2019.
With the weakness in crude oil prices late in the fourth quarter, operators have been delaying starting new completion projects in the first quarter, and pricing
remains extremely competitive. As such, we have made the decision to idle spreads rather than work at unreasonably low prices. We ended the fourth quarter with
20 active spreads and idled three spreads early in the first quarter of 2019 .
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.
The North American oil and natural gas services industry is cyclical and at times experiences downturns in demand. During these periods, there has been
substantially more oil and natural gas service equipment available than necessary to meet demand. As a result, oil and natural gas service contractors have had
difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. Currently, there is an excess of drilling rigs that are not super-
spec, pressure pumping equipment and directional drilling equipment available. In circumstances of excess capacity, providers of oil and natural gas services have
difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the future level of demand for our oil and natural gas
services or future conditions in the oil and natural gas service businesses.
We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather, the availability of products in our
pressure pumping business, supplier delays 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, 2018, our operating revenues consisted of the following (dollars in thousands):
Contract drilling
Pressure pumping
2018
$ 1,430,492
1,573,396
2017
43.0% $ 1,040,033
47.3% 1,200,311
44.1% $
50.9%
2016
543,663
354,070
59.4%
38.7%
Directional drilling
Other
Contract Drilling
209,275
113,834
$ 3,326,997
6.3%
3.4%
45,580
70,760
100.0% $ 2,356,684
1.9%
3.1%
100.0% $
—
18,133
915,866
—%
1.9%
100.0%
Contract drilling operations accounted for 43.0% of our consolidated 2018 revenues, and contract drilling revenues increased 37.5% over 2017.
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. The U.S. land rig industry refers to certain high specification rigs as “super-spec”
rigs. We consider a super-spec rig to be at least a 1,500 horsepower, AC powered rig
29
that has a 750,000 - pound hookload, a 7,500 - psi circulating system , and is pad - capable. As of December 31, 2018 , our rig fleet included 198 APEX ® rigs , of
which 149 were super-spec rigs. W e delivered 14 rigs with major upg rades in 2018 and one additional major rig upgrade in January 2019 . We currently have
one additional major rig upgrade contracted for delivery in 2019.
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, 2018 and 2017 was $770 million and $544 million, respectively. Approximately 23% of the total contract
drilling backlog at December 31, 2018 is reasonably expected to remain after 2019. 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,
other than initial 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. For contracts that contain
variable dayrate pricing, our backlog calculation uses the dayrate in effect for periods where the dayrate is fixed, and, for periods that remain subject to variable
pricing, uses the commodity price in effect at December 31, 2018. 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 on which we have
received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period over which 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.”
Ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased
drilling activity, include:
•
•
•
•
•
movement of drilling rigs from region to region,
reactivation of drilling rigs,
refurbishment and upgrades of existing drilling rigs,
development of new technologies that enhance drilling efficiency,
construction of new technology drilling rigs.
Pressure Pumping
Pressure pumping operations accounted for 47.3% of our consolidated 2018 revenues, and pressure pumping revenues increased 31.1% over 2017. As of
December 31, 2018, we had approximately 1.6 million horsepower in our pressure pumping fleet. In response to unreasonably low prices in the completions
market, we reduced the number of active frac spreads to 20 as of the end of the fourth quarter and idled three spreads early in the first quarter of 2019.
Directional Drilling
Directional drilling operations accounted for 6.3% of our consolidated 2018 revenues. Activity for directional drilling commenced with the acquisition of
MS Directional in October 2017, which provides 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, motor rentals, directional surveying, measurement-
while-drilling, and wireline steering tools, and we provide services that improve the statistical accuracy of horizontal wellbore placement.
Other Operations
Other operations revenues accounted for 3.4% of our consolidated 2018 revenues, and our other operations revenues increased 60.9% over 2017. Our
oilfield rentals business, which was acquired with the SSE merger, provides the largest revenue contribution to our other operations. Our oilfield rentals business
has a fleet of premium oilfield rental tools and provides specialized services for land-based oil and natural gas drilling, completion and workover activities. Other
operations also includes the results of our electrical controls and automation business, the results of our pipe handling components and related technology business,
and the results of our ownership, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.
Capital Expenditures
Cash capital expenditures for 2018 totaled $641 million. For 2019, based on near-term activity levels, we expect cash used for capital expenditures to be
approximately $465 million.
30
For the three years ended December 31, 2018 , our operating income (loss) consisted of the following (dollars in thousand s):
Contract drilling
Pressure pumping
Directional drilling
Other
Corporate
$
2018
(33,115)
(77,328)
(117,497)
(18,221)
(76,016)
$ (322,177)
2017
10.3% $ (171,897)
21,028
24.0%
(21)
36.5%
(20,813)
5.7%
23.5%
(120,835)
100.0% $ (292,538)
2016
58.8% $ (235,858)
(176,628)
(7.2)%
—
—%
(3,391)
7.1%
(40,349)
41.3%
100.0% $ (456,226)
51.7%
38.7%
—%
0.7%
8.9%
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.
While demand for our contract drilling and pressure pumping services improved in 2018 and merger and integration expenses were lower, an impairment of
goodwill and write-downs to drilling and pressure pumping equipment contributed to a consolidated net loss of $321 million for 2018, compared to consolidated
net income of $5.9 million for 2017 and a consolidated net loss of $319 million for 2016. Our net income for 2017 was positive due to the 2017 tax law change.
Results of Operations
Comparison
of
the
years
ended
December
31,
2018
and
2017
The following tables summarize results of operations by business segment for the years ended December 31, 2018 and 2017:
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
2018
Year Ended December 31,
2017
(Dollars in thousands)
% Change
$
$
$
$
$
$
1,430,492 $
885,704
544,788
6,296
571,607
(33,115) $
64,479
22.19 $
13.74 $
8.45 $
176.7
394,595 $
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
37.5%
32.8%
46.1%
6.1%
6.1%
(80.7)%
27.9%
7.6%
3.9%
14.2%
27.9%
11.3%
(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.
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 2018, our average number of rigs operating was 175 in the United States and one in Canada, compared to 136 in the United
States and two in Canada in 2017. Our average rig revenue per operating day was $22,190 in 2018, compared to $20,620 in 2017. Our average revenue per
operating day is largely dependent on the pricing terms of our rig contracts.
Revenues and direct operating costs increased primarily due to an increase in operating days. Operating days and average rigs operating increased in 2018
primarily due to the recovery in the oil and natural gas industry, the contribution of rigs acquired in the SSE merger and the contribution from rigs that have been
upgraded to super-spec capability. Capital expenditures increased in 2018 due to the upgrade of rigs to super-spec capability, higher maintenance capital
expenditures and other equipment upgrades. Depreciation, amortization, and impairment for 2018 included a charge of $48.4 million related to the retirement of 42
legacy non-APEX® rigs and related equipment. Based on the strong customer preference across the industry for super-spec drilling rigs, we believe the 42 rigs that
were retired had limited commercial opportunity. Depreciation, amortization, and impairment for 2017 included a 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.
31
Pressure
Pumping
Revenues
Direct
operating
costs
Margin (1)
Selling,
general and
administrative
Depreciation,
amortization
and
impairment
Impairment of
goodwill
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
Year Ended December 31,
2018
$ 1,573,396
2017
(Dollars in thousands)
$ 1,200,311
%
Change
31.1%
1,263,850
309,546
966,835
233,476
15,420
14,442
250,010
121,444
198,006
—
$
(77,328)
$
21,028
812
1,081
1,893
622
1,262
1,884
$ 1,909.42
$ 1,894.40
$
21.23
$
17.43
$
831.17
$
637.11
$
667.64
$
513.18
$
163.52
$
123.93
19.7%
19.5%
$ 173,848
$ 171,436
30.7%
32.6%
6.8%
26.3%
NA
NA
30.5%
(14.3)%
0.5%
0.8%
21.8%
30.5%
30.1%
31.9%
1.0%
1.4%
(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.
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 812 fracturing jobs during
2018 compared to 622 fracturing jobs in 2017. Our average revenue per fracturing job was $1.909 million in 2018 compared to $1.894 million in 2017.
Revenues and direct operating costs in 2018 increased primarily due to an increase in the number of fracturing jobs. Depreciation, amortization and
impairment expense increased due to the assets acquired in the SSE merger. Also included in depreciation, amortization and impairment expense for 2018 is a
charge of $17.4 million related to the write-down of obsolete sand-handling equipment. There was no similar charge in the comparable period of 2017. All of
the goodwill associated with our pressure pumping business was impaired during 2018. See Note 6 of Notes to Consolidated Financial Statements for
additional information.
Directional
Drilling
Revenues
Year Ended December 31,
2018
$ 209,275
2017
(Dollars in thousands)
$ 45,580
%
Change
359.1%
Direct
operating
costs
Margin (1)
Selling,
general and
administrative
Depreciation
and
amortization
Impairment of
goodwill
Operating
loss
Capital
expenditures
175,829
33,446
32,172
13,408
446.5%
149.4%
15,941
4,082
290.5%
45,317
89,685
9,347
—
$ (117,497)
$
(21)
384.8%
NA
NA
$
35,929
$ 7,795
360.9%
(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 the results for 2017 include less than
three months of operations. Margins in 2018 were negatively impacted by higher third-party rental expenses due to delays in the delivery of equipment and by
higher repairs and maintenance costs. All of the goodwill associated with our directional drilling business was impaired during 2018. See Note 6 of Notes to
Consolidated Financial Statements for additional information.
32
Other Operations
Revenues
Direct operating costs
Margin (1)
Selling, general and administrative
Depreciation, depletion, amortization and impairment
Operating loss
Capital expenditures
2018
Year Ended December 31,
2017
(Dollars in thousands)
% Change
$
$
$
113,834 $
77,104
36,730
13,439
41,512
(18,221) $
34,660 $
70,760
51,428
19,332
10,743
29,402
(20,813)
31,547
60.9%
49.9%
90.0%
25.1%
41.2%
(12.5)%
9.9%
(1) Margin is defined as revenues less direct operating costs and excludes depreciation, depletion, amortization and impairment and selling, general and administrative
expenses.
Revenues, direct operating costs, and depreciation, depletion, amortization and impairment expense from other operations increased primarily as a result of the
inclusion of our oilfield rentals business acquired in the SSE merger on April 20, 2017. The increase in capital expenditures was due to investments in the oilfield
rentals business.
Corporate
Selling, general and administrative
Merger and integration expenses
Depreciation
Other operating (income) expense, net
Net gain on asset disposals
Legal-related expenses and settlements, net of insurance reimbursements
Research and development
Other
Other operating income, net
Interest income
Interest expense
Other income
Capital expenditures
2018
Year Ended December 31,
2017
(Dollars in thousands)
% Change
$
$
$
$
$
$
$
$
82,975 $
2,738 $
7,872 $
(28,958)
12,684
3,444
(4,739)
(17,569) $
5,597 $
51,578 $
750 $
2,426 $
70,646
74,451
7,695
(33,510)
561
1,002
(10)
(31,957)
1,866
37,472
343
1,884
17.5%
(96.3)%
2.3%
(13.6)%
NA
243.7%
NA
(45.0)%
199.9%
37.6%
118.7%
28.8%
Selling, general and administrative expense increased in 2018, but as a percentage of consolidated revenues decreased to 2.5%, compared to 3.0% in
2017. Selling, general and administrative expense increased in 2018 primarily due to the personnel added as a result of the SSE merger. Merger and integration
expenses incurred in 2018 are related to the SSE merger, the MS Directional acquisition and the Superior QC acquisition. Merger and integration expenses
incurred in 2017 are related to the SSE merger and the MS Directional acquisition. Other operating income includes net gains associated with the disposal of
assets. Accordingly, the related gains or losses have been excluded from the results of specific segments. The majority of the net gain on asset disposals during the
2018 period reflects gains on disposal of drilling equipment. The 2017 period included a gain of $11.2 million related to the sale of real estate. Legal-related
expenses and settlements in 2018 includes insurance deductibles and investigation costs related to an accident at a drilling site in January 2018. Research and
development expense during 2018 and 2017 relate primarily to the funding of research into pressure pumping technology. Other operating income during 2018
also includes the gain on the collection of a note receivable that had previously been discounted. Interest income increased in 2018 due to interest earned on the
portion of the proceeds of the January 2018 debt offering that were held as cash during 2018. The debt offering also resulted in an increase in interest expense for
2018.
33
Comparison
of
the
years
ended
De
cember
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
Year Ended December 31,
2017
$ 1,040,033
2016
(Dollars in thousands)
$ 543,663
%
Change
91.3%
667,105
372,928
305,804
237,859
118.1%
56.8%
5,934
5,743
3.3%
538,891
467,974
$ (171,897)
$ (235,858)
15.2%
(27.1)%
50,427
23,596
113.7%
$
20.62
$
23.04
(10.5)%
$
$
$
$
13.23
$
12.96
2.1%
7.40
138.2
$
10.08
(26.6)%
$
64.5
114.3%
354,425
$
72,508
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.
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. Many of our higher day rate, legacy long-term rig contracts were entered into during
periods of higher demand, and as a result, these legacy contracts had a higher day rate on average relative to the more recent contracts pursuant to which work was
performed during 2017. The majority of these legacy contracts expired during the recent downturn prior to and during 2017, and as a result we experienced a lower
average revenue per operating day during 2017 relative to 2016. 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 the upgrade of 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
Year Ended December 31,
2017
$ 1,200,311
2016
(Dollars in thousands)
$ 354,070
966,835
233,476
334,588
19,482
%
Change
239.0%
189.0%
1,098.4%
14,442
11,238
28.5%
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
198,006
184,872
$
21,028
$ (176,628)
622
1,262
1,884
352
799
1,151
$ 1,894.40
$
982.56
17.43
$
10.28
7.1%
NA
76.7%
57.9%
63.7%
92.8%
69.6%
$
$
$
$
637.11
$
307.62
107.1%
513.18
$
290.69
76.5%
123.93
$
16.93
632.0%
19.5%
5.5%
$ 171,436
$
39,584
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.
34
Revenues and direct operating costs increased in 2017 primarily due to an increase in the number and size of fracturing jobs. The total number of jobs
increased 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 job s. 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
2017
$
$
Year Ended December 31,
2016
(Dollars in thousands)
—
—
—
—
—
—
45,580 $
32,172
13,408
4,082
9,347
(21) $
Capital expenditures
(1)Margin is defined as revenues less direct operating costs and excludes depreciation and amortization and selling, general and administrative expenses.
7,795 $
—
$
% Change
NA
NA
NA
NA
NA
NA
NA
Our directional drilling segment originated with the October 11, 2017 acquisition of MS Directional, and consequently we had 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
Year Ended December 31,
2017
$ 70,760
2016
(Dollars in thousands)
$ 18,133
51,428
19,332
8,384
9,749
%
Change
290.2%
513.4%
98.3%
10,743
3,026
255.0%
29,402
10,114
190.7%
$ (20,813)
$ (3,391)
513.8%
$ 31,547
$ 6,116
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 rentals 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 rentals 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
70,646
74,451
7,695
(33,510)
1,553
(31,957)
1,866
37,472
343
1,884
Year Ended December 31,
2016
(Dollars in thousands)
49,198
$
—
$
5,474
$
$
$
$
$
$
$
(14,771)
448
(14,323)
327
40,366
69
1,591
$
$
$
$
$
$
$
$
$
% Change
43.6%
NA
40.6%
126.9%
246.7%
123.1%
470.6%
(7.2)%
397.1%
18.4%
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 related gains or losses have been excluded from the results
35
of specific segments. The 2017 period includes a gain of $11.2 million related to the sale of real e state 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. Inte rest expense decreased primarily due to lower debt outstanding during 2017 compared to 2016.
Income Taxes
Loss before income taxes
Income tax benefit
Effective tax rate
2018
Year Ended December 31,
2017
(Dollars in thousands)
2016
$
$
(367,408) $
(45,987) $
12.5%
(327,801) $
(333,711) $
101.8%
(496,196)
(177,562)
35.8%
The difference between the statutory federal income tax rate and the effective income tax rate for the years ended December 31, 2018, 2017 and 2016 is
summarized as follows:
Statutory tax rate
State income taxes - net of the federal income tax benefit
Goodwill impairment
Permanent differences
Tax effects of tax reform
Share-based payments
Acquisition related differences
Valuation allowance
State deferred tax remeasurement
Other differences, net
Effective tax rate
2018
2017
2016
21.0%
1.2
(6.9)
(0.6)
(1.3)
(0.1)
—
(3.7)
2.3
0.6
12.5%
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%
The effective tax rate decreased by approximately 89.3% to 12.5% for 2018 compared to 2017. This was primarily due to U.S. tax reform legislation known as
the Tax Cuts and Jobs Act, enacted on December 22, 2017 (“Tax Reform”), which resulted in a 66.7% increase in the 2017 effective tax rate due to the
remeasurement of U.S. deferred taxes and a 14% decrease in the 2018 effective tax rate due to the change in U.S. federal corporate tax rate. Also impacting the
2018 effective tax rate are certain goodwill impairment charges, which are not deductible for tax purposes, and valuation allowances being established against
deferred tax assets in certain state and non-U.S. jurisdictions. The goodwill impairment and valuation allowances resulted in a 6.9% and 3.7% decrease in the
effective tax rate, respectively. These decreases were partially offset by a 2.3% increase in the effective tax rate following the remeasurement of deferred tax assets
and liabilities for state tax purposes.
Tax Reform includes, among other things, a reduction of the U.S. federal corporate tax rate from 35% to 21% for tax years beginning 2018, a mandatory deemed
repatriation tax on foreign earnings, repeal of the corporate alternative minimum tax, expensing of certain capital investments, and reducing the amount of
executive pay that will be tax deductible. Tax Reform also makes fundamental changes to the taxation of multinational entities, including a shift from worldwide
taxation with deferral to a hybrid territorial system, a minimum tax on certain low-taxed foreign earnings, and new measures to deter base erosion and promote
export sales from the United States. For December 31, 2017, we recorded provisional amounts for certain enactment-date effects of Tax Reform by applying the
guidance in Staff Accounting Bulletin 118 (“SAB 118”) because we had not yet completed our enactment-date accounting for these effects. In 2017, we recorded
approximately $219 million of tax benefit related to the enactment-date effects of Tax Reform that related solely to adjusting deferred tax assets and liabilities to
the new U.S. federal corporate tax rate at which they are expected to reverse. After filing our 2017 income tax returns in the fourth quarter of 2018, we completed
our accounting for all of the enactment-date income tax effects of Tax Reform. As a result, we recognized $4.6 million of tax expense as an adjustment to the
provisional amounts recorded at December 31, 2017 and included these adjustments as a component of income tax expense. The changes to 2017 enactment-date
provisional amounts decreased the effective tax rate in 2018 by 1.3%.
Prior to Tax Reform, we had elected to permanently reinvest unremitted earnings in Canada effective January 1, 2010, and we intend to do so for the
foreseeable future. If we were to repatriate earnings, in the form of dividends or otherwise, we may be subject to certain income taxes (subject to an adjustment for
foreign tax credits) and withholding taxes payable.
We record deferred 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 recognizing the benefit of deferred income taxes, we incur
36
deferred income tax expense as these benefits are utilize d. We recognized a deferred tax benefit of approximately $41.2 million in 2018, $330 million in 2017 and
$152 million in 2016.
Liquidity and Capital Resources
Our liquidity as of December 31, 2018 included approximately $424 million in working capital, including $245 million of cash and cash equivalents, and $600
million available under our revolving credit facility.
On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes. We used $239 million of the net proceeds from
the sale to repay amounts outstanding under our revolving credit facility. As described below, on March 27, 2018, we entered into an amended and restated credit
agreement, which is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter of credit
facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million.
We believe our current liquidity, together with cash expected to be generated from operations, 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, 2018, we had working capital of $424 million, including cash and cash equivalents of $245 million, compared to working capital of $201
million, including cash and cash equivalents of $42.8 million, at December 31, 2017.
During 2018, our sources of cash flow included:
•
•
•
•
$731 million from operating activities,
$47.4 million in proceeds from the disposal of property and equipment,
$23.8 million from collection of a note receivable, and
$521 million from proceeds from the issuance of long-term debt.
During 2018, we used $268 million to repay net borrowings under our revolving credit facility, $14.2 million for acquisitions, $30.6 million to pay dividends on
our common stock, $4.5 million for debt issuance costs, $162 million for the repurchases of our common stock and $641 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 rentals 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, 2018 as follows:
Paid on March 22, 2018
Paid on June 21, 2018
Paid on September 20, 2018
Paid on December 20, 2018
Total cash dividends
Per Share
Total
(in thousands)
0.02 $
0.04
0.04
0.04
0.14 $
4,443
8,832
8,685
8,629
30,589
$
$
On February 6, 2019, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share to be paid on March 21, 2019 to
holders of record as of March 7, 2019. 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.
37
On September 6, 2013, our Board of Directors approved a stock buyback program that authorize d purchase s of up to $200 million of our common stock in
open market or privately negotiated transactions. On July 25, 2018, our Board of Directors approved an increase of the authorization under the stock buyback
program to allow for $250 million of future share repurchases. All purchases executed to date have been through open market transactions. Purchases under the
program are made at management’s disc retion, 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 b uyback program. As of
December 31, 2018 , we had remaining authorization to purchase approximately $150 million of our outstanding common stock under the stock buyback program.
On February 6, 2019, our Board of Directors approved another increase of the a uthorization under the stock buyback program to allow for $250 million of future
share repurchases.
We acquired shares of stock from directors in 2017 and 2016 and from employees during 2018, 2017 and 2016 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 and restricted stock units. 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, 2018, 2017 and 2016 were as follows (dollars in thousands):
2018
2017
2016
Treasury shares at beginning of period
Purchases pursuant to stock buyback program
Acquisitions pursuant to long-term incentive plan
Treasury shares at end of period
Shares
Shares
43,802,611 $
9,331,131
567,354
Cost
918,711 43,392,617 $
5,503
150,497
404,491
11,240
53,701,096 $ 1,080,448 43,802,611 $
Shares
Cost
911,094 43,207,240 $
8,488
176,889
918,711 43,392,617 $
109
7,508
Cost
907,045
183
3,866
911,094
2018 Credit Agreement — On March 27, 2018, we entered into an amended and restated credit agreement (the “Credit Agreement”) among us, as borrower,
Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other lenders and letter of credit
issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada, as Documentation Agent
and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Lead Arrangers and Joint Book Runners.
The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter
of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to
customary conditions, we may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of
$900 million. The maturity date under the Credit Agreement is March 27, 2023. We have the option, subject to certain conditions, to exercise two one-year
extensions of the maturity date.
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. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from
0.00% to 1.00%, in each case determined based upon our credit rating. 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 varies from 0.10% to 0.30% based
on our credit rating.
None of our subsidiaries are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt in
excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.
The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that we believe
are customary for agreements of this nature, including certain restrictions on our ability and each of our subsidiaries to incur debt and grant liens. If our credit
rating is below investment grade, we will become subject to a restricted payment covenant, which would require us to have a Pro Forma Debt Service Coverage
Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and immediately after making any restricted payment. The
Credit Agreement also requires that our total debt to capitalization ratio, expressed as a percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.
As of December 31, 2018, we had no amounts outstanding under our revolving credit facility. We had $81,000 in letters of credit outstanding under our
revolving credit facility at December 31, 2018 and, as a result, had available borrowing capacity of approximately $600 million at that date.
38
2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of
Nova Scotia (“Sc otiabank”), pursuant to which we may fro m time to time request that Scotiabank issue an unspecified amount of letters of credit. As of
December 31, 2018 , we had $58.4 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. None of our subsidiaries are currently required to 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 amount 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. None of our subsidiaries are currently required to be a guarantor 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.
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, 2018. 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.
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.
39
2028 Senior Notes — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 2028 Notes . T he net proceeds before
offering expenses were approximately $521 million , of which we used $239 million to r epay amounts outstanding under our revolving credit facility.
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 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. None of our subsidiaries are currently required to be a guarantor under the 2028 Notes. If our subsidiaries guarantee the 2028 Notes
in the future, such guarantees (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.
We, at our option, may redeem the Notes in whole or in 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 in 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.
Commitments — As of December 31, 2018, we maintained letters of credit in the aggregate amount of $58.5 million primarily 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, 2018, no amounts had been drawn
under the letters of credit.
As of December 31, 2018, we had commitments to purchase major equipment and make investments totaling approximately $107 million for our drilling,
pressure pumping, directional drilling and oilfield rentals businesses.
Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The agreements
expire in years 2019 through 2022 and in 2043. As of December 31, 2018, the remaining obligation under these agreements was approximately $114 million, of
which approximately $24.7 million relates to purchases required during 2019. In the event 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.
40
Trading and Investing — We have not engaged in trading activities that incl ude 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, 2018 (in thousands):
Series A Notes (1)
Interest on Series A Notes (2)
Series B Notes (3)
Interest on Series B Notes (4)
2028 Notes (5)
Interest on 2028 Notes (6)
Leases (7)
Equipment purchases (8)
Inventory purchases (9)
Total
Total
300,000
29,820
300,000
47,292
525,000
197,006
40,860
107,088
114,174
1,661,240
$
$
$
Payments due by period
Less than 1
year
1-3 years
3-5 years
More than 5
years
—
14,910
—
12,810
—
20,737
11,408
107,088
24,725
191,678
$
300,000
14,910
—
25,620
—
41,475
15,612
—
20,583
418,200
$
—
—
300,000
8,862
—
41,475
7,288
—
5,533
363,158
$
$
—
—
—
—
525,000
93,319
6,552
—
63,333
688,204
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
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.
Principal repayment of the 2028 Notes is required at maturity on February 1, 2028.
Interest to be paid on the 2028 Notes using 3.95% coupon rate.
See Note 12 of Notes to Consolidated Financial Statements.
Represents commitments to purchase major equipment to be delivered in 2019 based on expected delivery dates.
Represents commitments to purchase proppants and chemicals for our pressure pumping business.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements at December 31, 2018.
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
2018
Year Ended December 31,
2017
(Dollars in thousands)
2016
$
$
(321,421) $
(45,987)
45,981
916,318
211,129
806,020 $
5,910 $
(333,711)
35,606
783,341
—
491,146 $
(318,634)
(177,562)
40,039
668,434
—
212,277
41
Critical Accounting Policies
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. 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 are retired. During 2018, we identified 42 legacy non-APEX® rigs and related equipment that would be retired. Based on the
strong customer preference across the industry for super-spec drilling rigs, we believe the 42 rigs that were retired had limited commercial opportunity. In 2018,
we recorded a charge of $48.4 million related to this retirement. In 2017, we recorded a 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 charge as we had
written down mechanical rigs that were still marketed in 2015.
We also periodically evaluate our pressure pumping assets, and in 2018, we recorded a charge of $17.4 million for the write-down of pressure pumping
equipment. The pressure pumping equipment was primarily obsolete sand handling equipment, which has been replaced with more efficient sand solutions.
There were no similar charges in 2017 or 2016.
In addition, we review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the
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. 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
our 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.
Due to the decline in the market price of our common stock and the deterioration of crude oil prices in the fourth quarter of 2018, we lowered our
expectations with respect to future activity levels in certain of our operating segments. Management deemed it necessary to assess the recoverability of our contract
drilling, pressure pumping, directional drilling and oilfield rentals asset groups. We performed an analysis as required by ASC 360-10-35 to assess the
recoverability of the asset groups within our contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments. With respect to these
asset groups, 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 asset groups, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded the carrying
values of the asset groups within the contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments by approximately 38%, 58%,
9% and 23%, respectively.
For the assessment performed in 2018, the expected cash flows for our asset groups included utilization , revenue and costs for our equipment and services
that were estimated based upon our existing contract backlog, as well as recent contract tenders and customer inquiries. Also, the expected cash flows for the
contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups were based on the assumption that activity levels in all four segments would
generally be lower than levels experienced in the fourth quarter of 2018, and would begin to recover in late 2019 and continue into 2020 in response to improved
oil prices. While we believe these assumptions with respect to future oil pricing are reasonable, actual future prices may vary significantly from the ones that were
assumed. The timeframe over which oil prices will recover is highly uncertain. Potential events that could affect our assumptions regarding future prices and the
timeframe for a recovery are affected by factors such as those described in “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.”
All of these factors are beyond our control. If the lower oil price environment experienced at the end of 2018 were to last into 2020 and beyond, our actual
cash flows would likely be less than the expected cash flows used in these assessments and could result in impairment charges in the future and such impairment
could be material.
We concluded that no triggering events occurred during the years ended December 31, 2017 or 2016 with respect to our asset groups based on our results of
operations for the years ended December 31, 2017 and 2016, our expectations of operating results in future periods and the prevailing commodity prices at the time.
42
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 are our operating segments. We determine whether
it is more likely than not that the fair value o f 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 qu antitative 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.
Due to the decline in the market price of our common stock and the deterioration of crude oil prices in the fourth quarter of 2018, we lowered our expectations
with respect to future activity levels in certain of our operating segments. We performed a quantitative impairment assessment of our goodwill as of December 31,
2018. In completing the assessment, the fair value of each reporting unit was estimated using the income valuation method. The estimate of fair value for 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, pressure pumping, directional drilling and oilfield rentals reporting units, such as future oil and natural gas prices
and projected demand for our services, and assumptions related to discount rates and long-term growth rates.
Based on the results of the goodwill impairment test as of December 31, 2018, the fair value of the contract drilling and oilfield rentals reporting units exceeded
their carrying values by approximately 16% and 14%, respectively, and we concluded that no impairment was indicated in our contract drilling and oilfield rentals
reporting units; however, impairment was indicated in our pressure pumping and directional drilling reporting units. We recognized an impairment charge of $211
million associated with the impairment of all of the goodwill in our pressure pumping and directional drilling reporting units.
While management believes the assumptions used with respect to future oil pricing are reasonable, actual future prices may vary significantly from the ones that
were assumed. The timeframe over which oil prices will recover is highly uncertain. If the lower oil price environment experienced at the end of 2018 were to last
into 2020 and beyond, our actual cash flows would likely be less than the expected cash flows used in these assessments and could result in additional impairment
charges in the future and such impairment could be material.
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 current 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 succeeding year. Management also considered our overall
market capitalization at December 31, 2017 and 2016.
Revenue recognition — On January 1, 2018, we adopted the new revenue guidance under Topic 606, Revenue from Contracts with Customers , using the
modified retrospective method for contracts that were not complete at December 31, 2017. The adoption of the new accounting standard did not have a material
impact on our consolidated financial statements, and a cumulative adjustment was not recognized. Revenues for reporting periods beginning after January 1, 2018
are presented under Topic 606, while revenues prior to January 1, 2018 continue to be reported under previous revenue recognition requirements of Topic 605.
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.
43
Volatility of Oil and Natural Gas Prices and its Impac t 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 prices have recovered from the lows
experienced in the first quarter of 2016. Oil prices reached a high of $77.41 in June 2018. Oil prices remain volatile, as the closing price of oil reached a fourth
quarter 2018 high of $76.40 per barrel on October 3, 2018, before declining by 42% over the course of three months to reach a low of $44.48 per barrel in late
December 2018. Oil prices averaged $59.08 per barrel in the fourth quarter of 2018. U.S. rig counts increased in response to improved oil prices in early 2018.
However, rig counts have fallen in response to lower oil prices, and we believe the rig count will not increase until oil prices increase.
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, 2018. 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
As of December 31, 2018, we would have had exposure to interest rate market risk associated with any borrowings that we had 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. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate loans varies from
0.00% to 1.00%, in each case determined based on our credit rating. As of December 31, 2018, the applicable margin on LIBOR rate loans was 1.50% and the
applicable margin on base rate loans was 0.50%. As of December 31, 2018, we had no amounts outstanding under our revolving credit facility. The interest rate on
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 Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit. We
are obligated to pay Scotiabank 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, 2018, no amounts had been disbursed under any letters of credit.
We conduct a portion of our business in Canadian dollars. 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 financial condition or results of operations.
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.
44
Item 8. Financial
Statements
a
nd
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, 2018, 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, 2018, 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, 2018.
The effectiveness of our internal control over financial reporting as of December 31, 2018 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 .
45
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.
46
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
3.5
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 Company’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) .
Certificate of Amendment to Restated Certificate of Incorporation, as amended (filed July 30, 2018 as Exhibit 3.4 to the Company’s Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 2018 and incorporated herein by reference).
Fourth Amended and Restated Bylaws (filed February 12, 2019 as Exhibit 3.1 to the Company’s Current Report on Form 8-K 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. (filed February 20,
2018 as Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 a nd incorporated herein by
reference).
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 herei n by reference).
First Supplemental Indenture, dated January 19, 2018, among Patterson-UTI Energy, Inc., the several guarantors named therein an d 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 (included 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 C ompany’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 Officer 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 by
reference) .*
47
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
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). *
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). *
Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhib it 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 and incorporated herein by reference). *
Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s
Quarterly Report on Form 10-Q and incorporated 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 ( filed April 21, 2014 as Exhibit 10.1 to the Company’s Current Report on Form 8-K
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 Restricted Stock Award Agreement (filed May 2, 2016 as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q
and incorporated h erein 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 incorporated 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 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 (filed February 20, 2018 as Exhibit 10.19 to the Company’s Annual
Report on Form 10-K for the fiscal year ended December 31, 2017 and incorporated herein by reference) . *
10.15
Form of Executive Officer Share-Settled Performance Share Award Agreement.*+
10.16
10.17
10.18
10.19
10.20
10.21
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 b y 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 on Form 10-K for the year ended December 31, 2016 and incorporated herein by reference) .*
Employment Agreement, dated as of September 3, 2017, between 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). *
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, Seth D. Wexler, William Andrew Hendricks, Jr., Michael W. Conlon, Tiffany J. Thom, C. Andrew Smith and
Janeen S. Judah (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year en ded December
31, 2003 and incorporated herein by reference) .*
48
10.2 2
Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 2 9, 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) .*
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
21.1
23.1
31.1
31.2
32.1
101
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 for 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 here in by reference) .*
First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into Nove mber 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) .*
Amended and Restated Credit Agreement dated March 27, 2018 among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, National
Association, as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuers and lenders party
thereto (filed March 27, 2018 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).
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 Quarterly 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) .
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, 2018, 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.
49
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the years ended December 31, 2018 , 2017 and 2016
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2018 , 2017 and 2016
Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2018 , 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2018 , 2017 and 2016
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 (the “Company”) as of December 31, 2018 and
2017, 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, 2018, 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, 2018, 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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
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 stat ements. 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 f inancial 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.
Definition
and
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.
F-2
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 13, 2019
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 $2,312 and $2,323 at
December 31, 2018 and 2017, 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
Federal and state income taxes payable
Accrued expenses
Total current liabilities
Borrowings under revolving credit facility
Long-term debt, net of debt discount and issuance costs of $5,795 and $1,217 at
December 31, 2018 and 2017, respectively
Deferred tax liabilities, net
Other
Total liabilities
Commitments and contingencies (see Note 9)
Stockholders’ equity:
Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued
Common stock, par value $.01; authorized 400,000,000 shares at December 31, 2018 and 300,000,000
shares at December 31, 2017 with 267,315,526 and 266,259,083 issued and 213,614,430 and 222,456,472
outstanding at
December 31, 2018 and 2017, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Treasury stock, at cost, 53,701,096 shares and 43,802,611 shares at
December 31, 2018 and 2017, respectively
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31,
2018
2017
(In thousands, except share data)
$
245,029 $
42,828
558,817
4,110
65,579
76,662
950,197
4,002,549
477,640
12,040
—
27,440
5,469,866 $
288,962 $
1,408
235,946
526,316
—
1,119,205
306,161
12,761
1,964,443
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
5
226,624
546,250
268,000
598,783
350,836
12,494
1,776,363
—
—
2,673
2,827,154
1,753,557
2,487
(1,080,448)
3,505,423
5,469,866 $
2,662
2,785,823
2,105,897
6,822
(918,711)
3,982,493
5,758,856
$
$
$
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, 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
2018
Year Ended December 31,
2017
(In thousands, except per share data)
2016
$
1,430,492 $
1,573,396
209,275
113,834
3,326,997
1,040,033 $
1,200,311
45,580
70,760
2,356,684
885,704
1,263,850
175,829
77,104
916,318
211,129
134,071
2,738
(17,569)
3,649,174
(322,177)
5,597
(51,578)
750
(45,231)
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)
543,663
354,070
—
18,133
915,866
305,804
334,588
—
8,384
668,434
—
69,205
—
(14,323)
1,372,092
(456,226)
327
(40,366)
69
(39,970)
(367,408)
(327,801)
(496,196)
(45,987)
(333,711)
(177,562)
$
(321,421) $
5,910 $
(318,634)
$
$
(1.47) $
(1.47) $
0.03 $
0.03 $
(2.18)
(2.18)
218,643
218,643
198,447
199,882
146,178
146,178
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 2018, $0
for 2017 and $0 for 2016:
Foreign currency translation adjustment
Total comprehensive income (loss)
2018
Year Ended December 31,
2017
(In thousands)
2016
$
(321,421) $
5,910 $
(318,634)
$
(4,335)
(325,756) $
7,956
13,866 $
2,959
(315,675)
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
(In thousands)
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
Net loss
Foreign currency translation adjustment
Restricted stock issued for acquisition
Issuance of restricted stock
Issuance of common 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, 2018
190,375 $
—
—
354
785
15
(43)
40
—
—
—
—
191,526
—
—
18,170
55,097
891
549
(24)
50
—
—
—
—
266,259
—
—
192
381
—
452
(8)
40
—
—
—
—
267,316 $
1,904 $ 1,011,811 $ 2,458,554 $
(318,634)
—
—
—
—
—
—
—
—
—
6,730
(8)
—
—
707
28,324
—
—
3
8
—
—
—
—
—
—
—
—
(23,579)
—
1,915 1,042,696 2,116,341
(4,868)
—
—
—
—
—
—
182
471,388
551 1,226,339
(9)
(5)
—
931
44,483
—
—
—
5,910
—
—
—
—
—
—
—
—
(16,315)
(39)
—
2,662 2,785,823 2,105,897
9
5
—
—
—
—
—
—
—
—
2
4
—
5
—
—
—
—
—
—
(321,421)
—
—
—
—
—
—
—
—
(30,589)
(330)
—
2,673 $ 2,827,154 $ 1,753,557 $
—
—
2,930
(4)
—
(5)
—
485
37,925
—
—
—
(4,093) $ (907,045) $ 2,561,131
(318,634)
2,959
6,733
—
—
—
707
28,324
—
2,959
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,134)
—
—
(4,049)
(4,868)
(23,579)
(4,049)
(911,094) 2,248,724
—
7,956
—
—
—
—
—
—
—
—
—
—
6,822
5,910
—
7,956
—
—
471,570
— 1,226,890
—
—
—
—
—
—
931
—
44,483
—
(16,315)
—
(39)
—
(7,617)
(7,617)
(918,711) 3,982,493
—
(4,335)
—
—
—
—
—
—
—
—
—
—
(321,421)
—
(4,335)
—
2,932
—
—
—
—
—
—
—
—
—
485
—
37,925
—
(30,589)
—
(330)
—
(161,737)
(161,737)
2,487 $ (1,080,448) $ 3,505,423
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 discount and 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
Collection of note receivable
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 $1,435 in 2018, $1,175 in 2017
and $398 in 2016
Income taxes
Non-cash investing and financing activities:
Receivable from property and equipment insurance
Net increase in payables for purchases of property
and equipment
Issuance of common stock for business acquisitions
Net decrease (increase) in deposits on equipment purchases
2018
Year Ended December 31,
2017
(In thousands)
2016
$
(321,421) $
5,910 $
(318,634)
916,318
211,129
915
(41,185)
37,925
(28,958)
—
830
23,515
(1,555)
(1,470)
(69,453)
4,136
(56)
730,670
(14,211)
(641,458)
47,357
23,760
—
(584,552)
—
(161,737)
(30,589)
521,194
—
79,000
(347,000)
(4,489)
485
56,864
(781)
202,201
42,828
245,029 $
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
(41,184) $
3,172
(34,953) $
3,947
(36,551)
52,716
15,000 $
— $
—
36,241
2,932
4,311
17,228
1,226,890
(301)
28,926
6,733
6,317
$
$
$
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”), is 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. The Company’s contract drilling business operates in the continental United States and western
Canada, and the Company is pursuing contract drilling opportunities outside of North America. The Company’s pressure pumping business operates primarily in
Texas and the Mid-Continent and Appalachian regions. The Company also provides a comprehensive suite of directional drilling services in most major producing
onshore oil and gas basins in the United States, and the Company provides services that improve the statistical accuracy of horizontal wellbore placement. The
Company has other operations through which the Company provides oilfield rental tools in select markets in the United States. The Company also manufactures
and sells pipe handling components and related technology to drilling contractors, and provides electrical controls and automation to the energy, marine and mining
industries, 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. As used in these notes, “the Company” refers collectively to Patterson-UTI Energy, Inc. and its consolidated
subsidiaries. Patterson-UTI Energy, Inc. conducts its business operations through its wholly-owned subsidiaries and has no employees or independent operations.
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.
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 the Company’s contract drilling, pressure pumping, directional drilling, oilfield rentals and pipe handling components
and related technology activities are recognized as services are performed. All of the wells the Company drilled in 2018, 2017 and 2016 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.
On January 1, 2018, the Company adopted the new revenue guidance under Topic 606, Revenue from Contracts with Customers , using the modified
retrospective method for contracts that were not complete at December 31, 2017. The adoption of the new accounting standard did not have a material impact on
the Company’s consolidated financial statements, and a cumulative adjustment was not recognized. See Note 3 for additional information.
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 accounts 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 collectability. 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.
F-9
Other current assets — O ther 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 $36 million and $30 million at December 31, 2018 and 2017 , 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.
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-10
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 1 1 ).
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 Financial Accounting Standards Board (“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 expanded 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 (See Note 3).
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 adopted this new guidance effective January 1, 2019. ASC 842 requires a modified retrospective
approach to each lease that existed at the date of initial application as well as leases entered into after that date. The Company has elected to report all leases at the
beginning of the period of adoption and not restate its comparative periods. Based on the Company’s lease portfolio, the Company anticipates recognizing a right-
of-use asset and a related lease liability of approximately $35 million on its balance sheet, with an immaterial impact on the Company’s consolidated statement of
operations compared to the previous lease accounting guidance.
Practical
Expedients
Adopted
with
Topic
842
The Company has elected to adopt the following practical expedients upon the transition date to Topic 842 on January 1, 2019:
•
•
•
Transitional practical expedients package: An entity may elect to apply the listed practical expedients as a package to all the leases that commenced
before the effective date. The practical expedients are:
a)
b)
c)
The entity need not reassess whether any expired or existing contracts are or contains leases;
The entity need not reassess the lease classification for expired or existing contracts;
The entity need not reassess initial direct costs for any existing leases.
Use of portfolio approach: An entity can apply this guidance to a portfolio of leases with similar characteristics if the entity reasonably expects that the
application of the leases model to the portfolio would not differ materially from the application of the leases model to the individual leases in that
portfolio. This approach can also be applied to other aspects of the leases guidance for which lessees/lessors need to make judgments and estimates,
such as determining the discount rate and determining and reassessing the lease term.
Lease and non-lease components: As a practical expedient, a lessor may combine lease and non-lease components where the revenue recognition pattern
is the same and where the lease component, when accounted for separately, would be considered an operating lease.
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
F-11
depend on the Company’s stock price and the number of shares that vest in the case of restricted stock, restric ted 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 standards update 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.
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.
In March 2018, the FASB issued an accounting standards update to update the income tax accounting in U.S. GAAP to reflect the SEC interpretive guidance
released on December 22, 2017, when significant U.S. tax law changes were enacted with the enactment of the Tax Cuts and Jobs Act (“Tax Reform”). The
adoption of this update in March 2018 did not have a material impact on the Company’s consolidated financial statements, as the Company was already following
the SEC guidance. See Note 13 for additional information.
In August 2018, the FASB issued an accounting standards update to align the requirements for capitalizing implementation costs incurred in a hosting
arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The
amendments in the update are effective for public business entities for fiscal years beginning after December 15, 2019, with early adoption permitted. The
Company is currently evaluating the impact this new guidance will have on its 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 fracturing equipment. The oilfield rentals business acquired through the SSE merger has
a 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.
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-12
$
$
$
$
46,298
22.45
1,039,396
472,000
1,511,396
The following table represents the final 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 record ed 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 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, access to new
geographies, access to new product lines, increased scale of operations, supply chain and corporate efficiencies as well as infrastructure optimization. The acquired
goodwill was attributable to three operating segments, with $309 million to contract drilling, $121 million to pressure pumping and $6.3 million to oilfield rentals.
See Note 6 for additional information regarding goodwill.
A portion of the fair value consideration transferred has been 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
was 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, motor rentals, 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.
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
F-13
$
$
$
$
$
8,798
21.31
187,494
63,000
6,781
257,275
The following table represents the final 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 identifi able 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
44,099
327
44,426
167,590
89,685
257,275
The goodwill reflected above increased $1.0 million from the original preliminary purchase price allocation as a result of a measurement period adjustment that
related to a valuation adjustment to accounts payable and accrued liabilities.
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, access to new product lines,
favorable market trends underlying these new business lines, earnings and growth opportunities and future technology development possibilities. All of the
goodwill acquired is attributable to the directional drilling operating segment. See Note 6 for additional information regarding goodwill.
A portion of the fair value consideration transferred has been 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-14
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 the Company’s 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 accounts for substantially all of 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 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
Current Power Solutions, Inc. (“Current Power”)
2017
2016
(Unaudited)
2,738,579 $
29,584 $
0.13 $
0.13 $
1,567,141
(505,413)
(2.30)
(2.30)
$
$
$
$
During October 2018, the Company acquired Current Power. Current Power is a provider of electrical controls and automation to the energy, marine and
mining industries. This acquisition was not material to the Company’s consolidated financial statements.
Superior QC, LLC (“Superior QC”)
During February 2018, the Company acquired the business of Superior QC, including its assets and intellectual property. Superior QC is a provider of software
and services used to improve the statistical accuracy of horizontal wellbore placement. Superior QC’s measurement-while-drilling (MWD) survey fault detection,
isolation and recovery (FDIR) service is a data analytics technology to analyze MWD survey data in real-time and more accurately identify the position of a
well. This acquisition was not material to the Company’s consolidated financial statements.
Warrior Rig Ltd
During September 2016, the Company acquired 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. Revenues
ASC Topic 606 Revenue from Contracts with Customers
On January 1, 2018, the Company adopted the new revenue guidance under Topic 606, Revenue from Contracts with Customers , using the modified
retrospective method for contracts that were not complete at December 31, 2017. The adoption of the new accounting standard did not have a material impact on
the Company’s consolidated financial statements, and a cumulative adjustment was not recognized. Revenues for reporting periods beginning after January 1, 2018
are presented under Topic 606, while revenues prior to January 1, 2018 continue to be reported under previous revenue recognition requirements of Topic 605.
The Company’s contracts with customers include both long-term and short-term contracts. Services that primarily generate revenue earned for the
Company include the operating business segments of contract drilling, pressure pumping and directional drilling
F-15
that comprise the Company’ s reportable segments. The Company also derives revenues from its other operations which include the Company’s operating business
segments of oilfield rentals, oilfield technology, electrical controls and automation, and oil and natural gas working intere sts. For more information on the
Company’s business segmen ts, see Note 16 .
Charges for services are considered a series of distinct services. Since each distinct service in a series would be satisfied over time if it were accounted for
separately, and the entity would measure its progress towards satisfaction using the same measure of progress for each distinct service in the series, the Company is
able to account for these integrated services as a single performance obligation that is satisfied over time.
The transaction price is the amount of consideration to which the Company expects to be entitled in exchange for transferring promised goods or services
to a customer, based on terms of the Company’s contracts with its customers. The consideration promised in a contract with a customer may include fixed amounts
and/or variable amounts. Payments received for services are considered variable consideration as the time in service will fluctuate as the services are
provided. Topic 606 provides an allocation exception, which allows the Company to allocate variable consideration to one or more distinct services promised in a
series of distinct services that form part of a single performance obligation as long as certain criteria are met. These criteria state that the variable payment must
relate specifically to the entity’s efforts to satisfy the performance obligation or transfer the distinct good or service, and allocation of the variable consideration is
consistent with the standards’ allocation objective. Since payments received for services meet both of these criteria requirements, the Company recognizes revenue
when the service is performed.
An estimate of variable consideration should be constrained to the extent that it is not probable that a significant revenue reversal in the amount of
cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Payments received for other
types of consideration are fully constrained as they are highly susceptible to factors outside the entity’s influence and therefore could be subject to a significant
revenue reversal once resolved. As such, revenue received for these types of consideration is recognized when the service is performed.
Estimates of variable consideration are subject to change as facts and circumstances evolve. As such, the Company will evaluate its estimates of variable
consideration that are subject to constraints throughout the contract period and revise estimates, if necessary, at the end of each reporting period.
The Company is a working interest owner of oil and natural gas properties located in Texas and New Mexico. The ownership terms are outlined in joint
operating agreements for each well between the operator of the wells and the various interest owners, including the Company, who are considered non-operators of
the well. The Company receives revenue each period for its working interest in the well during the period. The revenue received for the working interests from
these oil and gas properties does not fall under the scope of the new revenue standard, and therefore, will continue to be reported under current guidance ASC 932-
323 Extractive Activities – Oil and Gas, Investments – Equity Method and Joint Ventures.
Reimbursement Revenue – 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.
The Company’s disaggregated revenue recognized from contracts with customers is included in Note 16.
Accounts
Receivable
and
Contract
Liabilities
Accounts receivable is the Company’s right to consideration once it becomes unconditional. Payment terms range from 30 to 60 days.
Accounts receivable balances were $554 million and $577 million as of December 31, 2018 and 2017, respectively. These balances do not include
amounts related to the Company’s oil and gas working interests as those contracts are excluded from Topic 606. Accounts receivable balances are included in
“Accounts Receivable” in the Consolidated Balance Sheets.
The Company does not have any contract asset balances, and as such, contract balances are not presented at the net amount at a contract level. Contract
liabilities include prepayments received from customers prior to the requested services being completed. Once the services are complete and have been invoiced,
the prepayment is applied against the customer’s account to offset the accounts receivable balance. Also included in contract liabilities are payments received from
customers for the initial mobilization of newly constructed or upgraded rigs that were moved on location to the initial well site. These mobilization payments are
allocated to the overall performance obligation and amortized over the initial term of the contract. During the year ended December 31, 2018, contract liabilities
increased approximately $1.5 million due to customer payments relating to the initial mobilization of upgraded rigs and decreased approximately $1.6 million due
to amounts amortized and recorded in drilling revenue.
F-16
Contract liability balances for customer prepayments were $ 3.0 million and $9.1 million as of December 31 , 2018 and 2017, respectively. Contract
liability balances for deferred mobilization payments relating to newly constructed or upgraded rigs were $ 4.6 million and $4.7 million as of December 31 , 2018
and 2017, respectively. Contract liability balances for customer prepayments are included in “Accounts Payable” and contract liability balances for deferred
mobilization payments are included in “Accrued Liabilities” in the Consolidated Balance Sheets.
Contract
Costs
Costs incurred for newly constructed or rig upgrades based on a contract with a customer are considered capital improvements and are capitalized to
drilling equipment and depreciated over the estimated useful life of the asset.
Practical
Expedients
Adopted
with
Topic
606
The Company has elected to adopt the following practical expedients upon the transition date to Topic 606 on January 1, 2018:
•
•
•
Use of portfolio approach: An entity can apply this guidance to a portfolio of contracts (or performance obligations) with similar characteristics if
the entity reasonably expects that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from
applying this guidance to the individual contracts (or performance obligations) within that portfolio.
Excluding disclosure about transaction price: As a practical expedient, an entity need not disclose the information for a performance obligation if
either of the following conditions is met:
a)
b)
The performance obligation is part of a contract that has an original expected duration of one year or less.
The entity recognizes revenue from the satisfaction of the performance obligation.
Excluding sales taxes from the transaction price: The scope of this policy election is the same as the scope of the policy election under previous
guidance. This election provides exclusion from the measurement of the transaction price all taxes assessed by a governmental authority that are
both imposed on and concurrent with a specific revenue producing transaction and collected by the entity from a customer.
•
Costs of obtaining a contract: An entity can immediately expense costs of obtaining a contract if they would be amortized within a year.
4. Inventory
Inventory consisted of the following at December 31, 2018 and 2017 (in thousands).
Finished goods
Work-in-process
Raw materials and supplies
Inventory
5. Property and Equipment
Property and equipment consisted of the following at December 31, 2018 and 2017 (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-17
$
$
$
$
2018
2017
347
6,375
58,857
65,579
$
$
2,270
529
66,368
69,167
2018
2017
8,370,933
219,855
186,736
26,144
8,803,668
(4,801,119)
4,002,549
$
$
8,066,404
211,566
185,475
26,593
8,490,038
(4,235,308)
4,254,730
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 2018 , 2017 and 2016 (in thousands):
Depreciation and impairment expense
Amortization expense
Depletion expense
Total
$
$
2018
2017
2016
887,155
18,197
10,966
916,318
$
$
753,510
21,764
8,067
783,341
$
$
657,571
3,643
7,220
668,434
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. 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 2018, the Company identified 42 legacy non-APEX® rigs and related
equipment that would be retired. Based on the strong customer preference across the industry for super-spec drilling rigs, the Company believes the 42 rigs that
were retired had limited commercial opportunity. The Company recorded a $48.4 million charge related to this retirement. In 2017, the Company r ecorded a
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 charge as it had written down mechanical rigs that were still marketed in 2015.
The Company also periodically evaluates its pressure pumping assets, and in 2018, the Company recorded a charge of $17.4 million for the write-down of
pressure pumping equipment. The pressure pumping equipment was primarily obsolete sand handling equipment, which has been replaced with more efficient
sand solutions. 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.
Due to the decline in the market price of the Company’s common stock and the deterioration of crude oil prices in the fourth quarter of 2018, the Company
lowered its expectations with respect to future activity levels in certain of its operating segments. The Company deemed it necessary to assess the recoverability of
its contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups. The Company performed an analysis as required by ASC 360-10-35 to
assess the recoverability of the asset groups within its contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments. With respect
to these asset groups, 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 asset groups, and no impairment was indicated. Expected cash flows, on an undiscounted basis, exceeded
the carrying values of the asset groups within the contract drilling, pressure pumping, directional drilling and oilfield rentals operating segments by approximately
38%, 58%, 9% and 23%, respectively.
For the assessment performed in 2018, the expected cash flows for the Company’s asset groups included utilization , revenue and costs for the Company’s
equipment and services that were estimated based upon the Company’s existing contract backlog, as well as recent contract tenders and customer inquiries . Also,
the expected cash flows for the contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups were based on the assumption that activity
levels in all four segments would generally be lower than levels experienced in the fourth quarter of 2018, and would begin to recover in late 2019 and continue
into 2020 in response to improved oil prices. While the Company believes these assumptions with respect to future oil pricing are reasonable, actual future prices
may vary significantly from the ones that were assumed. The timeframe over which oil prices will recover is highly uncertain. Potential events that could affect
the Company’s assumptions regarding future prices and the timeframe for a recovery are affected by factors such as those described in “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.”
All of these factors are beyond the Company’s control. If the lower oil price environment experienced at the end of 2018 were to last into 2020 and beyond,
the Company’s actual cash flows would likely be less than the expected cash flows used in these assessments and could result in impairment charges in the future,
and such impairment could be material.
The Company concluded that no triggering events occurred during the years ended December 31, 2017 or 2016 with respect to its asset groups based on the
Company’s results of operations for the years ended December 31, 2017 and 2016, management’s expectations of operating results in future periods and the
prevailing commodity prices at the time.
F-18
6 . Goodwill and Intangible Assets
Goodwill — Goodwill by operating segment as of December 31, 2018 and 2017 and changes for the years then ended are as follows (in thousands):
Balance December 31, 2016
Goodwill acquired
Balance December 31, 2017
Goodwill acquired
Measurement period adjustment
Impairment
Balance December 31, 2018
Contract
Drilling
Pressure
Pumping
Directional
Drilling
Other
Operations
$
$
86,234
308,826
395,060
—
—
—
395,060
$
$
—
121,444
121,444
—
—
(121,444)
—
$
$
—
88,685
88,685
—
1,000
(89,685)
—
$
$
—
6,284
6,284
9,412
—
—
15,696
$
$
Total
86,234
525,239
611,473
9,412
1,000
(211,129)
410,756
There were no accumulated impairment losses related to goodwill in the contract drilling segment or other operations as of December 31, 2018 or 2017.
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 impairment testing purposes, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing
are 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 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.
Due to the decline in the market price of the Company’s common stock and the deterioration of crude oil prices in the fourth quarter of 2018, the Company
lowered its expectations with respect to future activity levels in certain of its operating segments. The Company performed a quantitative impairment assessment
of its goodwill as of December 31, 2018. In completing the assessment, the fair value of each reporting unit was estimated using the income valuation
method. The estimate of fair value for 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 the Company’s contract drilling, pressure pumping, directional drilling and
oilfield rentals reporting units, such as future oil and natural gas prices and projected demand for the Company’s services, and assumptions related to discount rates
and long-term growth rates.
Based on the results of the goodwill impairment test as of December 31, 2018, the fair value of the contract drilling and oilfield rentals reporting units exceeded
their carrying values by approximately 16% and 14%, respectively, and management concluded that no impairment was indicated in its contract drilling and oilfield
rentals reporting units; however, impairment was indicated in its pressure pumping and directional drilling reporting units. The Company recognized an
impairment charge of $211 million associated with the impairment of all of the goodwill in its pressure pumping and directional drilling reporting units.
While management believes the assumptions used with respect to future oil pricing are reasonable, actual future prices may vary significantly from the ones that
were assumed. The timeframe over which oil prices will recover is highly uncertain. If the lower oil price environment experienced at the end of 2018 were to last
into 2020 and beyond, the Company’s actual cash flows would likely be less than the expected cash flows used in these assessments and could result in additional
impairment charges in the future and such impairment could be material.
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.
Intangible Assets — In 2018, intangible assets were recorded in the Company’s directional drilling operating segment with the acquisition of Superior QC
and in other operations with the acquisition of Current Power. 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). 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:
F-19
Customer relationships
Customer relationships
Developed technology
Favorable drilling contracts
Internal use software
Segment
Directional drilling
Other operations
Directional drilling
Contract drilling
Directional drilling
Weighted Average
Useful Life
(in years)
3.00
7.00
10.00
0.83
5.00
Due to the decline in the market price of the Company’s common stock and the deterioration of crude oil prices in the fourth quarter of 2018, the
Company lowered its expectations with respect to activity levels in certain of its operating segments. The Company deemed it necessary to assess the
recoverability of its contract drilling, pressure pumping, directional drilling and oilfield rentals asset groups. The assessments of recoverability of the asset groups
included the respective intangible assets, and no impairment was indicated. See Note 5 for additional information.
The Company concluded that no triggering events necessitating an impairment assessment of the intangible assets had occurred in 2017 or 2016.
The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2018 and 2017 are as follows (in thousands):
Customer relationships
Developed technology
Favorable drilling contracts
Internal use software
Gross Carrying
Amount
$
$
28,000
55,772
22,500
482
106,754
$
2018
Accumulated
Amortization
$
2017
Accumulated
Amortization
$
Net Carrying
Amount
Gross Carrying
Amount
Net Carrying
Amount
(10,719) $
(6,533)
(22,500)
(118)
(39,870) $
17,281
49,239
—
364
66,884
$
$
26,200
48,000
22,500
482
97,182
$
(1,943) $
(1,137)
(18,482)
(21)
(21,583) $
24,257
46,863
4,018
461
75,599
Amortization expense on intangible assets of approximately $18.3 million, $24.3 million and $3.6 million for the years ended December 31, 2018, 2017 and
2016, respectively. The remaining amortization expense associated with finite-lived intangible assets is expected to be as follows (in thousands):
Year ending December 31,
2019
2020
2021
2022
2023
Thereafter
Total
7. Accrued Expenses
Accrued expenses consisted of the following at December 31, 2018 and 2017 (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
F-20
$
$
2018
2017
$
$
58,160
83,772
25,318
9,531
15,774
2,403
40,988
235,946
$
$
14,664
12,721
5,931
5,909
5,834
21,825
66,884
50,438
80,751
29,332
10,816
7,558
16,101
31,628
226,624
8 . Long-Term Debt
2018 Credit Agreement — On March 27, 2018, the Company entered into an amended and restated credit agreement (the “Credit Agreement”) among the
Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, swing line lender and lender, each of the other
lenders and letter of credit issuers party thereto, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Syndication Agents, Royal Bank of Canada,
as Documentation Agent and Wells Fargo Securities, LLC, The Bank of Nova Scotia and U.S. Bank National Association, as Co-Lead Arrangers and Joint Book
Runners.
The Credit Agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $600 million, including a letter
of credit facility that, at any time outstanding, is limited to $150 million and a swing line facility that, at any time outstanding, is limited to $20 million. Subject to
customary conditions, the Company may request that the lenders’ aggregate commitments be increased by up to $300 million, not to exceed total commitments of
$900 million. The maturity date under the Credit Agreement is March 27, 2023. The Company has the option, subject to certain conditions, to exercise two one-
year extensions of the maturity date.
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. The applicable margin on LIBOR rate loans varies from 1.00% to 2.00% and the applicable margin on base rate
loans varies from 0.00% to 1.00%, in each case determined based upon the Company’s credit rating. A letter of credit fee is payable by the Company 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 varies from 0.10% to 0.30% based on the Company’s credit rating.
No subsidiaries of the Company are currently required to be a guarantor under the Credit Agreement. However, if any subsidiary guarantees or incurs debt
in excess of the Priority Debt Basket (as defined in the Credit Agreement), such subsidiary is required to become a guarantor under the Credit Agreement.
The Credit Agreement contains representations, warranties, affirmative and negative covenants and events of default and associated remedies that the Company
believes are customary for agreements of this nature, including certain restrictions on the ability of the Company and each subsidiary of the Company to incur debt
and grant liens. If the Company’s credit rating is below investment grade, the Company will become subject to a restricted payment covenant, which would require
the Company to have a Pro Forma Debt Service Coverage Ratio (as defined in the Credit Agreement) greater than or equal to 1.50 to 1.00 immediately before and
immediately after making any restricted payment. The Credit Agreement also requires that the Company’s total debt to capitalization ratio, expressed as a
percentage, not exceed 50%. 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 end of the most recently ended fiscal quarter.
As of December 31, 2018, the Company had no amounts outstanding under the revolving credit facility. The Company had $81,000 in letters of credit
outstanding under the revolving credit facility at December 31, 2018 and, as a result, had available borrowing capacity of approximately $600 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, 2018, the Company had $58.4 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.
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.
No subsidiaries of the Company currently guarantee payment under the Credit Agreement.
F-21
S eries A & B S enior 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 pr ivate 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 amount 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. No subsidiaries of the Company are currently required to
be a guarantor 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, 2018.
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 3.95% Senior
Notes due 2028 (the “2028 Notes”). 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 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.
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 Company’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. No subsidiaries of the Company are currently required to
be a guarantor under the 2028 Notes. If subsidiaries of the Company guarantee the 2028 Notes in the future, such guarantees (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.
The Company, at its option, may redeem the Notes in whole or in 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 in 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.
F-22
Upon the occurrence of a change of control, as defi ned 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 repurc hase 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 $4.6 million in debt issuance costs in connection with the 2018 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 . The Company incurred approximately $1.6 million in debt issuance costs in connection with the 2028 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 $2.0 million, $2.6 million and $4.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amortization of debt issuance
costs for the year ended December 31, 2018 includes $317,000 of debt issuance costs related to commitments by lenders under the Company’s previous credit
agreement who did not participate in the 2018 Credit Agreement. 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, 2018 (in thousands):
Year ending December 31,
2019
2020
2021
2022
2023
Thereafter
Total
$
$
—
300,000
—
300,000
—
525,000
1,125,000
9. Commitments, Contingencies and Other Matters
Commitments – As of December 31, 2018, the Company maintained letters of credit in the aggregate amount of $58.5 million primarily 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, 2018, no amounts had been drawn
under the letters of credit.
As of December 31, 2018, the Company had commitments to purchase major equipment and make investments totaling approximately $107 million for its
drilling, pressure pumping, directional drilling and oilfield rentals businesses.
The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. The
agreements expire in years 2019 through 2022 and in 2043. As of December 31, 2018, the remaining obligation under these agreements was approximately
$114 million, of which approximately $24.7 million relates to purchases required during 2019. In the event 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.
Contingencies – The Company’s operations are subject to many hazards inherent in the businesses in which it operates, including inclement weather, blowouts,
explosions, 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. An accident or other
event resulting in significant environmental or property damage, or injuries or fatalities involving the Company’s employees or other persons could also trigger
investigations by federal, state or local authorities. Such an accident or other event could cause the Company to incur substantial expenses in connection with the
investigation, remediation and resolution, as well as cause lasting damage to the Company’s reputation, loss of customers and an inability to obtain insurance.
F-23
Any contractual right to indemnification that the Company may have for any such risk may be unenforceable or limited due to negligent or will ful 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” expressl y 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 disput e, 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 indemnif ication 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 equipment 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 cybersecurity 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. Lawsuits have been filed in the District Court for Pittsburg County, Oklahoma in connection with the five individuals who lost their lives and one of the
Company’s employees who was injured in the accident. The lawsuits have been consolidated for discovery purposes under Cause No. CJ-2018-60 (the
“Litigation”). These lawsuits allege various causes of action against the Company including negligence, gross negligence, knowledge that injury or death was
substantially certain, acting with purpose, recklessness, wrongful death and survival, and the plaintiffs seek an unspecified amount of damages, including punitive
or exemplary damages, costs, interest, and other relief. The Company disputes the plaintiffs’ allegations and intends to continue to defend itself vigorously. 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 the Litigation. However, if
this accident 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 other 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, cash flows or results of operations.
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 supersed es 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 term ination 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) pro viding 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 such t
ermination 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 noti ce 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 Go od 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.
10. 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, 2018 , 2017 and 2016 as follows:
2018
Paid on March 22, 2018
Paid on June 21, 2018
Paid on September 20, 2018
Paid on December 20, 2018
Total cash dividends
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
Per Share
Total
(in thousands)
0.02
0.04
0.04
0.04
0.14
0.02
0.02
0.02
0.02
0.08
0.10
0.02
0.02
0.02
0.16
$
$
$
$
$
$
4,443
8,832
8,685
8,629
30,589
3,326
4,269
4,271
4,449
16,315
14,712
2,953
2,953
2,961
23,579
$
$
$
$
$
$
On February 6, 2019, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.04 per share to be paid on
March 21, 2019 to holders of record as of March 7, 2019. 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 authorized purchases of up to $200 million of the Company’s
common stock in open market or privately negotiated transactions. On July 25, 2018, the Company’s Board of Directors approved an increase of the authorization
under the stock buyback program to allow for $250 million of future share repurchases. 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. There is no expiration date associated with the buyback program. As of December 31, 2018, the Company had remaining
authorization to purchase approximately $150 million of the Company’s outstanding common stock under the stock buyback program. Shares of stock purchased
under the plan are held as treasury shares. On February 6, 2019, the Company’s Board of Directors approved another increase of the authorization under the stock
buyback program to allow for $250 million of share repurchases.
The Company acquired shares of stock from directors during 2017 and 2016 and from employees during 2018, 2017, and 2016 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 and restricted stock units.
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, 2018, 2017 and 2016 were as follows (dollars in thousands):
Treasury shares at beginning of period
Purchases pursuant to stock buyback program
Acquisitions pursuant to long-term incentive plan
Treasury shares at end of period
2018
2017
2016
Shares
43,802,611
9,331,131
567,354
53,701,096
$
Cost
918,711
150,497
11,240
$ 1,080,448
Shares
43,392,617
5,503
404,491
43,802,611
$
$
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
F-26
11 . Stock-based Compensation
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 include equity instruments in the form of stock options, restricted stock or restricted stock units that have
included service conditions and, in certain cases, performance conditions. The Company’s share-based awards also include share-settled performance unit
awards. Share-settled performance unit awards are accounted for as equity awards. 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.
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 under 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 common stock 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, 2018 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
—
6,203,695
3,268,500
2,471,800
—
• 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, 2018, 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.
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 years ended December 31, 2018 or 2017. Weighted-average assumptions used to estimate grant date fair
values for stock options granted during the year ended December 31, 2016 is as follows:
Volatility
Expected term (in years)
Dividend yield
Risk-free interest rate
F-27
2016
35.11%
5.00
2.05%
1.40%
Stock option activity for the year ended December 31, 2018 follows:
Outstanding at beginning of year
Exercised
Expired
Outstanding at end of year
Exercisable at end of year
Shares
Weighted-average
exercise price
6,037,150
(40,000)
(496,000)
5,501,150
5,362,269
$
$
$
$
$
20.35
12.12
29.01
19.63
19.66
Options outstanding at December 31, 2018 have no intrinsic value and a weighted-average remaining contractual term of 4.05 years. Options exercisable at
December 31, 2018 have no intrinsic value and a weighted-average remaining contractual term of 3.96 years. Additional information with respect to options
granted, vested and exercised during the years ended December 31, 2018, 2017 and 2016 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)
2018
2017
2016
NA
NA
$
$
$
1,954
—
$
$
4,565
209
$
$
4.90
4,729
366
As of December 31, 2018, options to purchase 138,881 shares were outstanding and not vested. All of these non-vested options are expected to ultimately vest.
Additional information as of December 31, 2018 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 (in thousands)
$
$
—
7.45 years
2.45 years
1.09 years
673
Restricted Stock— For all restricted stock awards made 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, 2018 follows:
Non-vested restricted stock outstanding at beginning of year
Vested
Forfeited
Non-vested restricted stock outstanding at end of year
Shares
1,530,338
(1,085,743)
(8,371)
436,224
$
$
$
$
Weighted-
average Grant
Date Fair Value
21.41
21.41
21.60
21.41
As of December 31, 2018, approximately 423,000 million shares of non-vested restricted stock outstanding are expected to vest. Additional information as of
December 31, 2018 with respect to these non-vested shares follows:
Aggregate intrinsic value
Weighted-average remaining vesting period
Unrecognized compensation cost
$4.4 million
1 year
$6.9 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. Forfeitable dividend equivalents are accrued on certain
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.
F-28
Restricted stock unit activity for the year ended December 31, 2018 follows:
Non-vested restricted stock units outstanding at beginning of year
Granted
Granted in connection with acquisitions
Vested (1)
Forfeited
Non-vested restricted stock units outstanding at end of year
Time
Based
Performance
Based
Weighted-average
Grant Date Fair
Value
1,223,273
1,726,865
204,222
(413,858)
(137,894)
2,602,608
114,000
—
359,315
(38,000)
—
435,315
$
$
$
$
$
$
19.80
19.15
16.99
19.65
19.43
18.95
(1) All of the performance-based restricted stock units that vested during 2018 were granted in 2017.
As of December 31, 2018, approximately 2.9 million non-vested restricted stock units outstanding are expected to vest. Additional information as of December
31, 2018 with respect to these non-vested restricted stock units follows:
Aggregate intrinsic value
Weighted-average remaining vesting period
Unrecognized compensation cost
$29.7 million
2.3 year
$44.2 million
Performance Unit Awards. The Company has granted share-settled performance unit awards to certain employees (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 achievement 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 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, then 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 using linear
interpolation for levels of achievement between these points.
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. The performance criteria for this extended period was not met and therefore
there was no payout under the 2013 awards.
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 and April 2018, 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 2013-2018 is set forth below:
Target number of shares
2018
Performance
Unit Awards
310,700
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
F-29
As noted above, there was no payout under the 2013 Performance Units. The 2014 Performance Units settled with a negative total shareholder return, so there
was no payout under such Performance Units. In April 2018, 381,200 shares were issued to settle the 2015 Performance Units. The Performance Units granted in
2016, 2017, and 2018 have not reached the end of their respective performance periods.
Because the Performance Units are share-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
2018
Performance
Unit Awards
8,004
$
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
$
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, 2018
Year ended December 31, 2017
Year ended December 31, 2016
2018
Performance
Unit Awards
2,001
$
NA
NA
2017
Performance
Unit Awards
1,927
$
1,284
$
NA
2016
Performance
Unit Awards
1,285
$
1,285
$
963
$
2015
Performance
Unit Awards
338
$
1,351
$
1,351
$
2014
Performance
Unit Awards
NA
449
1,796
$
$
2013
Performance
Unit Awards
NA
NA
464
$
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.
12. Leases
The Company incurred rent expense of $105.2 million, $48.9 million and $25.3 million for the years ended December 31, 2018, 2017 and 2016,
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,
2018 are as follows (in thousands):
Year ending December 31,
2019
2020
2021
2022
2023
Thereafter
Total
$
$
11,408
9,069
6,543
4,625
2,663
6,552
40,860
F-30
1 3 . Income Taxes
Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2018, 2017 and 2016 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:
2018
2017
2016
$
$
(3,954)
(35,081)
(39,035)
$
(42)
(335,106)
(335,148)
1,704
(11,147)
(9,443)
(2,552)
5,043
2,491
(215)
4,511
4,296
(3,108)
249
(2,859)
(4,802)
(41,185)
(45,987)
$
(3,365)
(330,346)
(333,711)
$
$
(24,777)
(134,592)
(159,369)
(257)
(14,163)
(14,420)
(368)
(3,405)
(3,773)
(25,402)
(152,160)
(177,562)
The difference between the statutory federal income tax rate and the effective income tax rate for the years ended December 31, 2018, 2017 and 2016 is
summarized as follows:
Statutory tax rate
State income taxes - net of the federal income tax benefit
Goodwill impairment
Permanent differences
Tax effects of tax reform
Share-based payments
Acquisition related differences
Valuation allowance
State deferred tax remeasurement
Other differences, net
Effective tax rate
2018
2017
2016
21.0%
1.2
(6.9)
(0.6)
(1.3)
(0.1)
—
(3.7)
2.3
0.6
12.5%
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%
The effective tax rate decreased by approximately 89.3% to 12.5% for 2018 compared to 2017. This was primarily due to Tax Reform, which resulted in a
66.7% increase in the 2017 effective tax rate due to the remeasurement of the U.S. deferred taxes and a 14% decrease in the 2018 effective tax rate due to the
change in U.S. federal corporate tax rate. Also impacting the 2018 effective tax rate are certain goodwill impairment charges, which are not deductible for tax
purposes, and valuation allowances being established against deferred tax assets in certain state and non-U.S. jurisdictions. The goodwill impairment and valuation
allowances resulted in a 6.9% and 3.7% decrease in the effective tax rate, respectively. These decreases were partially offset by a 2.3% increase in the effective tax
rate following the remeasurement of deferred tax assets and liabilities for state tax purposes.
Tax Reform includes, among other things, a reduction of the U.S. federal corporate tax rate from 35% to 21% for tax years beginning 2018, a mandatory deemed
repatriation tax on foreign earnings, repeal of the corporate alternative minimum tax, expensing of certain capital investments, and reducing the amount of
executive pay that will be tax deductible. Tax Reform also makes fundamental changes to the taxation of multinational entities, including a shift from worldwide
taxation with deferral to a hybrid territorial system, a minimum tax on certain low-taxed foreign earnings, and new measures to deter base erosion and promote
export sales from the United States. For December 31, 2017, the Company recorded provisional amounts for certain enactment-date effects of Tax Reform by
applying the guidance in Staff Accounting Bulletin 118 (“SAB 118”) because the Company had not yet completed its enactment-date accounting for these effects.
In 2017, the Company recorded approximately $219 million of tax benefit related to the enactment-date effects of Tax Reform that related solely to adjusting
deferred tax assets and liabilities to the new U.S. federal corporate tax rate at which they are expected to reverse. After the filing of the Company’s 2017 income tax
returns in the fourth quarter of 2018, the Company completed its accounting for all of the enactment-date income tax effects of Tax Reform. As a result, the
Company recognized $4.6 million of tax expense as an adjustment to the provisional amounts recorded at December 31, 2017 and included these adjustments as a
component of income tax expense. The changes to 2017 enactment-date provisional amounts decreased the effective tax rate in 2018 by 1.3%.
F-31
For Tax Reform, the one-time transition tax is based on the Company’s total post-1986 earnings and profits ( “ E&P ” ), the tax on which it previously deferred
from U.S. income taxes under U.S. law. At December 31, 2017, the Company estimated an E&P deficit for each of its foreign subsidiaries and therefore did not rec
ord any additional taxes for the one-time transition tax. Upon further analysis of Tax Reform, along with notices and regulations issued and proposed by the U.S.
Department of the Treasury and the Internal Revenue Service, the Company finalized its calcula tions of the transition tax liability for its 2017 income tax filings
during the fourth quarter of 2018. The final transition tax computation resulted in approximately $13.7 million of Section 965 income inclusion which was
completely offset by 2017 net o perating losses .
At December 31, 2017, the Company remeasured its U.S. deferred tax assets and liabilities based on the tax rates at which they were expected to reverse in the
future and recorded a provisional tax benefit of approximately $219 million. Upon further analysis of certain aspects of Tax Reform along with the filing of the
Company’s 2017 income tax returns, the Company adjusted its December 31, 2017 provisional estimate on the remeasurement of U.S. deferred tax assets and
liabilities by recording additional tax expense of $1.7 million, which is included as a component of income tax expense.
Effective 2018, Tax Reform also subjects a U.S. shareholder to tax on global intangible low-taxed income (“GILTI”) earned by certain foreign subsidiaries.
Guidance from the FASB allows an entity to make an accounting policy election to either recognize deferred taxes for temporary basis differences expected to
reverse as GILTI in future years or to provide for the tax expense related to GILTI in the year the tax is incurred as a period expense only. The Company has
elected to account for GILTI in the year the tax is incurred. In 2018, the Company was not subject to the tax imposed by the GILTI provisions.
In addition to the introduction of GILTI, Tax Reform introduced a new provision called the base erosion and anti-abuse tax (“BEAT”), which is aimed at
preventing or reducing U.S. tax base erosion. The BEAT provisions eliminate the deductions for certain base-erosion payments made to related foreign
corporations and imposes a new minimum tax if greater than regular tax. In 2018, the Company was not subject to the minimum tax imposed by the BEAT
provisions.
Prior to Tax Reform, the Company had elected to permanently reinvest unremitted earnings in Canada effective January 1, 2010, and it intends to do so for the
foreseeable future. If the Company were to repatriate earnings, in the form of dividends or otherwise, it might be subject to certain income taxes (subject to an
adjustment for foreign tax credits) and withholding taxes payable.
The tax effect of significant temporary differences representing deferred tax assets and liabilities at December 31, 2018 and 2017 are as follows (in thousands):
Deferred tax assets:
Net operating loss carryforwards
Tax credits
Expense associated with stock options and restricted stock
Workers' compensation allowance
Other
Allowance to reduce deferred tax asset to expected realizable value
Total deferred tax assets
Deferred tax liabilities:
Property and equipment basis difference
Other
Total deferred tax liabilities
Net deferred tax liability
2018
2017
$
$
324,389 $
6,404
13,375
19,900
22,423
386,491
(13,232)
373,259
(669,196)
(10,224)
(679,420)
(306,161) $
275,402
9,053
12,126
19,323
25,891
341,795
—
341,795
(678,093)
(10,663)
(688,756)
(346,961)
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 deferred tax assets is dependent upon the generation of future taxable
income during the periods in which those temporary differences become deductible. The Company considers carryback availability, the scheduled reversal of
deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. In 2018, the Company recorded $13.2 million of
valuation allowances against its net deferred tax assets, with $4.9 million relating to certain state jurisdictions, $8.1 million relating to a Canadian subsidiary and
$0.2 million relating to operations outside of North America. These valuation allowances were recorded due to a change in judgment as to the realizability of these
assets in future tax years.
For income tax purposes, the Company has approximately $1.3 billion of gross federal net operating losses, approximately $24.7 million of gross Canadian net
operating losses and approximately $735 million of post-apportionment state net operating losses
F-32
as of December 31, 2018, before valuatio n allowances. The majority of Federal net operating losses will expire in varying amounts, if unused, between 2034 and
2037. Federal net operating losses generated in 2018 can be carried forward indefinitely. Canadian net operating losses will expire in varying amounts, if unused,
between 2036 and 2038. State net operating losses will expire in varying amounts, if unused, between 2023 and 2038 .
As of December 31, 2018, 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, 2018, the tax years ended December 31, 2013 through December 31, 2017 are open for
examination by U.S. taxing authorities. As of December 31, 2018, the tax years ended December 31, 2012 through December 31, 2017 are open for examination by
Canadian taxing authorities.
14. Earnings Per 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 income (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, performance units and restricted stock units. The dilutive effect of stock options, performance units 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, 2018, 2017 and 2016, 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
2018
2017
2016
$
$
(321,421)
—
(321,421)
$
$
5,910
(170)
5,740
$
$
(318,634)
—
(318,634)
218,643
198,447
146,178
Basic net income (loss) per common share
$
(1.47)
$
0.03
$
(2.18)
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
$
(321,421)
$
5,740
$
(318,634)
218,643
—
218,643
198,447
1,435
199,882
146,178
—
146,178
Diluted net income (loss) per common share
$
(1.47)
$
0.03
$
(2.18)
Potentially dilutive securities excluded as anti-dilutive
9,762
3,289
9,057
15. Employee Benefits
The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses of approximately $14.3 million in 2018,
$8.7 million in 2017 and $4.4 million in 2016 for the Company’s contributions to the plan.
F-33
16 . Business Segments
At December 31, 2018, the Company had three reportable 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 and has a separate management team that reports 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, 2018, the
Company had 252 marketed land-based drilling rigs in the continental United States and western Canada.
For the years ended December 31, 2018, 2017 and, 2016, contract drilling revenue earned in Canada was $9.3 million, $13.7 million and $15.6 million,
respectively. Additionally, long-lived assets within the contract drilling segment located in Canada totaled $26.2 million and $52.0 million as of December 31,
2018 and 2017, 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. Substantially all of the revenue in the pressure pumping segment is from well stimulation services (such as hydraulic fracturing) 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. The Company also provides cementing services through its pressure pumping segment. 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. Substantially all of the revenue in the directional drilling segment is from directional drilling, downhole performance motors and measurement-
while-drilling services, which are sold as a bundle.
Major Customer — During 2018 and 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. These revenues in 2016 were earned in both
the Company’s contract drilling and pressure pumping businesses.
F-34
The following tables summarize selected financial information relating to the Company’s business segments (in thousands):
Revenues:
Contract drilling
Pressure pumping
Directional drilling
Other operations (1)
Elimination of intercompany revenues (2)
Total revenues
Income (loss) before income taxes:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate
Other operating income, net (3)
Interest income
Interest expense
Other
Loss before income taxes
Identifiable assets:
Contract drilling
Pressure pumping
Directional drilling
Other operations
Corporate (4)
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
2018
Year Ended December 31,
2017
2016
1,432,012 $
1,573,396
209,275
131,028
(18,714)
3,326,997 $
1,041,492 $
1,200,311
45,580
76,781
(7,480)
2,356,684 $
(33,115) $
(77,328)
(117,497)
(18,221)
(93,585)
17,569
5,597
(51,578)
750
(367,408) $
(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)
3,817,638 $
921,237
239,341
177,374
314,276
5,469,866 $
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
571,607 $
250,010
45,317
41,512
7,872
916,318 $
394,595 $
173,848
35,929
34,660
2,426
641,458 $
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 )
( 2 )
( 3 )
( 4 )
Other operations includes the Company’s oilfield rentals business, pipe handling components and related technology business, the electrical controls and automation
business, the oil and natural gas working interests and the Middle East/North Africa activities.
In 2018 and 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.
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-related expenses and settlements, net of insurance reimbursements and certain research and development expenses.
Corporate assets primarily include cash on hand and certain property and equipment.
F-35
17 . 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, 2018
and 2017, 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
2018
2017
$
$
191,457 $
38,425
22,698
252,580
(7,551)
245,029 $
13,860
106,849
21,479
142,188
(99,360)
42,828
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, 2018, 2017 or 2016. No expense for bad debts was recognized in 2018, 2017 or 2016.
18. 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, 2018 and 2017 is set forth below (in thousands):
Borrowings under Credit Agreement:
Revolving credit facility
3.95% Senior Notes
4.97% Series A Senior Notes
4.27% Series B Senior Notes
Total debt
December 31, 2018
December 31, 2017
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
$
$
—
525,000
300,000
300,000
1,125,000
$
$
—
482,488
300,043
293,900
1,076,431
$
$
268,000
—
300,000
300,000
868,000
$
$
268,000
—
303,966
295,616
867,582
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 value of the 3.95% Senior Notes at December 31, 2018 is based on discounted cash flows associated with the notes using the market rate of interest at
December 31, 2018 of 5.07%. The fair value estimate of the 3.95% Senior Notes is considered a Level 1 fair value estimate in the fair value hierarchy of fair value
accounting. The fair values of the Series A Notes and Series B Notes at December 31, 2018 and 2017 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 4.97% at December 31, 2018 and 4.46% at December 31, 2017. For the Series B Notes, the current market rates used in measuring this fair value were 4.92%
at December 31, 2018 and 4.64% at December 31, 2017. 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-36
1 9 . Quarterly Financial Information (in thousands, except per share amounts) (unaudited)
2018
Operating revenues
Operating loss
Net loss
Net loss per common share:
Basic
Diluted
2017
Operating revenues
Operating loss
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
1 st
Quarter
2 nd
Quarter
3 rd
Quarter
4 th
Quarter
809,164 $
(22,102)
(34,417)
854,418 $
(9,004)
(10,713)
867,478 $
(80,281)
(75,042)
795,937
(210,790)
(201,249)
(0.16) $
(0.16) $
(0.05) $
(0.05) $
(0.34) $
(0.34) $
(0.93)
(0.93)
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
$
$
$
$
$
$
F-37
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Description
Year Ended December 31, 2018
Deducted from asset accounts:
Allowance for doubtful accounts
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
(1)
Consists of uncollectible accounts written off.
Beginning
Balance
Charged to
Costs and
Expenses
Deductions (1)
Ending
Balance
(In thousands)
2,323 $
— $
(11) $
2,312
3,191 $
— $
(868) $
2,323
3,545 $
— $
(354) $
3,191
$
$
$
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 13, 2019
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 13, 2019.
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/ Tiffany Thom Cepak
Tiffany Thom Cepak
/s/ Michael W. Conlon
Michael W. Conlon
/s/ Curtis W. Huff
Curtis W. Huff
/s/ Terry H. Hunt
Terry H. Hunt
/s/ Janeen S. Judah
Janeen S. Judah
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
Director
PATTERSON-UTI ENERGY, INC.
2014 LONG-TERM INCENTIVE PLAN
(As Amended and Restated Effective June 29, 2017)
SHARE-SETTLED
PERFORMANCE SHARE AWARD AGREEMENT
____________, 20__
Exhibit 10.15
1.
Performance
Share
Award
. The Compensation Committee (the “ Committee ”) of the Board of Directors of Patterson-
UTI Energy, Inc., a Delaware corporation (the “ Company ”), 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 ”), hereby awards to _________________ (the “ Grantee ”), effective as of the Date of Award set forth above, a
Performance Share Award (the “ Award ”) on the terms and conditions as set forth in this agreement (this “ Agreement ”).
1.1
1.2
General Performance Criteria . The Award provides the Grantee an opportunity to receive Shares based upon
the Company’s total stockholder return for the Performance Period (as that term is defined below) as compared
with the total stockholder returns of the peer index companies set forth on Exhibit A (the “ Peer Index
Companies ”) for such period. Total shareholder return for the Company will be measured based on $100
invested in the Company’s common stock on the first day of the Performance Period, with dividends reinvested.
Issuance of Shares Upon Achievement of [Positive Total Shareholder Return and] Performance Criteria as of the
Final Day of the Performance Period . If (a) the Company’s total stockholder return (dividends during the
Performance Period, if any, are assumed to be reinvested) for the three-year period (the “ Performance Period ”)
ending _________, 20___ (the “ Final Day of the Performance Period ”), [is positive and] equals or exceeds the
25 th percentile of the total stockholder returns of the Peer Index Companies for the Performance Period, (b) a
Change in Control of the Company has not occurred on or before the Final Day of the Performance Period, and
(c) the Grantee remains in the active employ of the Company through the Final Day of the Performance Period,
then the Company shall issue to the Grantee the number of Shares determined as follows:
(i)
(ii)
if the Company’s total stockholder return for the Performance Period is equal to the 50 th percentile
rank of the Company’s total stockholder return for the Performance Period as compared to the total
stockholder returns of the Peer Index Companies, _________ Shares (the “ Target Amount ”);
if the Company’s total stockholder return for the Performance Period is equal to or greater than the 25
th percentile rank of the Company’s total stockholder return for the Performance Period as compared
to the total stockholder returns of the Peer Index Companies but less than the 50 th
percentile, one half times the Target Amount plus the product of one half times the Target Amount
multiplied by the quotient obtained by dividing the difference of the percentile rank achieved for the
Performance Period (expressed as a percentage) minus 25 percent (25%) by 25 percent (25%) ( i.e. ,
(0.5 x Target Amount) + [(0.5 x Target Amount) x ((percentile rank (%) – 0.25)/0.25)]); or
E.g., assume that the Target Amount of the Award is 10,000 Shares and the total stockholder
return of the Company for the Performance Period as compared to the total stockholder returns of
the Peer Index Companies ranks in the 40 th percentile. The total amount of Shares issuable to the
Grantee under the Award would be 8,000 Shares, which is determined as follows: (0.5 x 10,000)
+ [(0.5 x 10,000) x ((40% - 25%)/25%)] = 5,000+ [5,000 x (15%/25%)] = 5,000+[5,000 x 60%] =
5,000+ 3,000= 8,000.
(iii)
if the Company’s total stockholder return achieved for the Performance Period is greater than the 50 th
percentile rank of the Company’s total stockholder return for the Performance Period as compared to
the total stockholder returns of the Peer Index Companies but less than the 75 th percentile, the Target
Amount plus the product of the Target Amount multiplied by the quotient obtained by dividing the
difference of the percentile rank achieved for the Performance Period (expressed as a percentage)
minus 50 percent (50%) by 25 percent (25%) ( i.e. , (Target Amount) + [(Target Amount) x
((percentile rank (%) – 0.50)/0.25)]); or
E.g. , assume that the same facts as the example above in clause (iii) except that the total
stockholder return of the Company for the Performance Period as compared to the total
stockholder returns of the Peer Index Companies ranks in the 60 th percentile. The total amount of
Shares issuable to the Grantee under the Award would be 14,000 Shares, which is determined as
follows: (10,000) + [(10,000) x ((60% - 50%)/25%)] = 10,000+ [10,000 x (10%/25%)] = 10,000+
[10,000 x 40%] = 10,000 + 4,000= 14,000.
(iv)
if the Company’s total stockholder return for the Performance Period is equal to or greater than the 75
th percentile rank of the Company’s total stockholder return for the Performance Period as compared
to the total stockholder returns of the Peer Index Companies, two times the Target Amount.
1.3
[ Issuance of Shares Upon Achievement of Negative or Zero Total Shareholder Return and Performance Criteria
as of the Final Day of the Performance Period . If (a) the Company’s total stockholder return (dividends during
the Performance Period, if any, are assumed to be reinvested) for the Performance Period, is negative or zero and
equals or exceeds the 25 th percentile of the total stockholder returns of the Peer Index Companies for the
Performance Period, (b) a Change in Control of the Company has not occurred on or before the Final Day of the
Performance Period, and (c) the Grantee remains in the active employ of the Company through
the Final Day of the Performance Period, then the Company shall issue to the Grantee the number of Shares
equal to 50 percent (50%) of the number of Shares the Grantee would have received pursuant to Section 1.2 had
the total stockholder return for the Performance Period been positive.]
1.4
1.5
Forfeiture . Notwithstanding any other provision of this Agreement to the contrary, the Award pursuant to this
Agreement shall lapse and be forfeited on the Final Day of the Performance Period if (a) the Company’s total
stockholder return for the Performance Period is less than the 25 th percentile of the total stockholder returns of
the Peer Index Companies for the Performance Period and (b) a Change in Control of the Company has not
occurred on or before the Final Day of the Performance Period.
Committee Determination . Pursuant to Articles 4 and 9 of the Plan, the Committee shall have the discretion to
calculate the total stockholder returns for the Performance Period for the Peer Index Companies, including the
Company, and to determine the formula to achieve such calculations.
The Committee’s determinations with respect to the Performance Period for purposes of this Agreement shall be
binding upon all persons. The Committee may not increase the Shares issuable under this Agreement. The
Committee may, in its sole discretion, make such adjustments as it deems necessary and appropriate, if any, in
the composition of the group of Peer Index Companies to address the merger or consolidation of any company in
the Peer Index Companies as of the date hereof with another company, an acquisition or disposition of a
significant portion of such company’s businesses or assets as it exists on the date hereof, or any other
extraordinary event occurring in relation to such company during the term of this Agreement.
Prior to an issuance of Shares made pursuant to Section 1.2 [or Section 1.3] and as provided in Section 2 or
Section 3.4, the Compensation Committee of the Board of Directors of the Company shall determine if the
performance criteria for such issuance has been satisfied and, to the extent such performance criteria has been
satisfied, shall certify in writing that such performance criteria has been satisfied.
2.
3.
TIME OF ISSUANCE OF SHARES . For purposes of this Agreement, unless otherwise provided under the Plan or
Section 3.4 of this Agreement, the Company shall cause the Shares to be issued to the Grantee pursuant to Section 1.2 [or
Section 1.3] on or before the 75th day following the Final Day of the Performance Period. Any Shares issued pursuant to
this Agreement will be issued to the Grantee or, if issuable pursuant to Section 3.3, the Grantee’s legal representative or
the Grantee’s estate, and thereafter the Grantee or, if applicable, the Grantee’s estate and heirs, executors, administrators
and the Grantee’s legal representatives shall have no further rights with respect to the Award or this Agreement.
TERMINATION OF EMPLOYMENT/CHANGE IN CONTROL. The following provisions will apply in the event
the Grantee’s employment with the Company terminates,
or a Change in Control of the Company (as defined below) occurs, before the Final Day of the Performance Period.
3.1
Definitions . For purposes of this Agreement, the following terms shall have the meanings ascribed to them
under this Section:
(i)
(ii)
(iii)
The Grantee will have a “ Disability ” if the Grantee qualifies for long-term disability benefits under a
long-term disability program sponsored by the Company in which executive officers participate
generally or, if the Company does not sponsor such a long-term disability program, the Grantee is
unable to engage in any substantial gainful activity by reason of any medically determinable physical
or mental impairment which can be expected to result in death or can be expected to last for a
continuous period of not less than 12 months.
“ Retirement ” means the voluntary termination of the Grantee’s employment relationship with the
Company (i) on or after the date on which the Grantee attains age 55 and (ii) on or after the date on
which the sum of the Grantee’s age and number of full years of service total 70.
A “ Change in Control of the Company ” shall mean the occurrence of any of the following after the
Grant Date and prior to the date on which the Award is forfeited in accordance with Section [1.3][1.4]
or Section 3.2:
(1)
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 subclause (1) of this Section 3.1(iii), 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 subclause (3) of this
Section 3.1(iii); or
(2)
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
(3)
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
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.
3.2
Termination Generally . Except as specified in Section 3.3 and 3.4 below, all of the Grantee’s rights in this
Agreement, including all rights to the Award granted to the Grantee, will lapse and be completely forfeited on
the date the Grantee’s
3.3
3.4
employment terminates if the Grantee’s employment with the Company terminates on or before the Final Day of
the Performance Period for Shares issuable pursuant to Section 1.2 [or Section 1.3] , if any, for any reason other
than death, Disability or Retirement.
Death, Disability or Retirement . Notwithstanding any other provision of this Agreement to the contrary, if the
Grantee’s employment with the Company terminates due to the Grantee’s death, Disability, or Retirement after
the completion of at least one month of the Performance Period and on or before the Final Day of the
Performance Period for Shares issuable pursuant to Section 1.2 [or Section 1.3], if any, then the Company will
cause Shares to be issued to the Grantee, at such time as provided in Section 2, an amount equal to the product of
(1) and (2) where (1) is the amount the Grantee would have received under this Agreement if the Grantee’s
employment with the Company had not been terminated due to the Grantee’s death, Disability or Retirement
before such Final Day of the Performance Period and (2) is a fraction, the numerator of which is the number of
days from the beginning of the Performance Period through the date of the Grantee’s death, or the Grantee’s
termination of employment with the Company due to a Disability or Retirement up to a maximum of 1095 days
and the denominator of which is 1095.
Change in Control . Notwithstanding anything in the Agreement to the contrary, the Company (or its successor)
will cause to be issued to the Grantee immediately preceding a Change in Control of the Company a number of
Shares in an amount equal to the Target Amount, and thereafter the Company (or its successor) will have no
further obligations to the Grantee pursuant to this Agreement; provided, however , that this Section 3.4 shall not
apply if the Grantee is the Covered Person or forms part of the Covered Person below 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.
4.
5.
[DIVIDEND EQUIVALENTS . No Dividend Equivalents shall be paid with respect to any Shares during the
Performance Period.]
TAX WITHHOLDING . To the extent that the grant, vesting or issuance of Shares under the Agreement results in
income to the Grantee for federal, state or local income, employment, excise or other tax purposes with respect to which
the Company or any of its Subsidiaries has a withholding obligation, the Grantee shall deliver to the Company or such
Subsidiary at the time of such receipt or lapse, as the case may be, such amount of money as the Company or such
Subsidiary may require to meet its obligation under applicable tax laws or regulations. If the Grantee fails to do so, the
Company or its Subsidiary is authorized to withhold from wages or other amounts otherwise payable to such Grantee the
minimum statutory withholding taxes as may be required by law or to take such other action as may be necessary to satisfy
such withholding obligations. Subject to restrictions that the Committee, in its sole discretion, may impose, the Grantee
may satisfy such obligation for the payment of such taxes by tendering previously acquired Shares (either actually or by
attestation, valued at their then Fair Market Value) that have been owned for a period of at least six months (or such other
period to avoid accounting charges against the
6.
7.
8.
9.
Company’s earnings), or by directing the Company to retain Shares (up to the Grantee’s minimum required tax
withholding rate or such other rate that will not trigger a negative accounting impact) otherwise deliverable under this
Agreement. The Company shall not be obligated to issue any Shares granted hereunder until all applicable federal, state
and local income, employment, excise or other tax withholding requirements have been satisfied.
SECTION 409A. This Award is subject to the payment timing and other restrictions set forth in Section 13.14 of the Plan.
TRANSFER RESTRICTIONS. The Award 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 pursuant to
this Agreement. 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 Grantee may assign or transfer the Award granted hereby pursuant to a qualified domestic relations order (as
defined in Section 414(p) of the Code, 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 Grantee’s spouse, children or
grandchildren (including any adopted and stepchildren and grandchildren), or (iii) a trust for the benefit of the Grantee 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
provided further that the Grantee shall remain bound by the terms and conditions of the Plan. Further, the Shares granted
hereby that are no longer subject to forfeiture 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 Grantee agrees (i) that the Company may
refuse to cause the transfer of the 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 the
Shares.
CAPITAL ADJUSTMENTS AND REORGANIZATIONS . The existence of the Award shall not affect in any way the
right or power of the Company 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.
PERFORMANCE SHARE AWARD DOES NOT AWARD ANY RIGHTS OF A STOCKHOLDER . The Grantee
shall not have the voting rights or any of the other rights, powers or privileges of a holder of the stock of the Company
with respect to the Award that are awarded hereby. Only after the Shares are issued in exchange for the Grantee’s rights
under this Agreement will the Grantee have all of the rights of a shareholder with respect to such Shares issued in
exchange for such rights.
10.
11.
12.
13.
14.
15.
16.
EMPLOYMENT RELATIONSHIP. For purposes of this Agreement, the Grantee shall be considered to be in the
employment of the Company as long as the Grantee has an employment relationship with the Company and any of its
Subsidiaries. The Committee shall determine any questions as to whether and when there has been a termination of such
employment relationship, and the cause of such termination, under the Plan, and the Committee’s determination shall be
final and binding on all persons.
NOT AN EMPLOYMENT AGREEMENT . This Agreement is not an employment agreement, and no provision of this
Agreement shall be construed or interpreted to guarantee the right to remain employed by the Company or any Affiliate for
any specified term.
LIMIT OF LIABILITY . Under no circumstances will the Company or an Affiliate be liable for any indirect, incidental,
consequential or special damages (including lost profits) of any form incurred by any person, whether or not foreseeable
and regardless of the form of the act in which such a claim may be brought, with respect to the Plan.
COMPANY LIABLE FOR ISSUANCE OF SHARES. Except as specified in Section 3.4, the Company is liable for the
issuance of any Shares that become issuable under this Agreement.
SECURITIES ACT LEGEND. The Grantee consents to the placing on the certificate for the Shares of an appropriate
legend restricting resale or other transfer of the Shares except in accordance with all applicable securities laws and rules
thereunder, as well as any legend under Section 13.5 of the Plan as determined by the Committee.
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.
MISCELLANEOUS . This Agreement is awarded pursuant to and is subject to all of the provisions of the Plan, including
amendments to the Plan, if any. Capitalized terms that are not defined herein shall have the meanings ascribed to such
terms in the Plan.
[SIGNATURE PAGE TO FOLLOW]
In accepting the Performance Share Award set forth in this Agreement the Grantee accepts and agree to be bound by all the terms
and conditions of the Plan and this Agreement.
PATTERSON-UTI ENERGY, INC.
By:
Name:
Title:
(“GRANTEE”)
EXHIBIT A
Peer Index
The Peer Index Companies shall be [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, Inc., Oil States International, Inc., Precision Drilling
Corporation, Rowan Companies plc, Superior Energy Services, Inc., TechnipFMC plc, Transocean Ltd., Unit Corporation
and Weatherford International plc], as such group of companies may be adjusted pursuant to Section [1.4][1.5].
Subsidiaries of the Registrant
Exhibit 21.1
Name
Ambar Lone Star Fluid Services LLC
Current Power Solutions, Inc.
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) B.V.
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, Inc.
Patterson-UTI International (India) B.V.
Patterson-UTI International (Kuwait) Limited
Patterson-UTI Management Services, LLC
PTL Prop Solutions, L.L.C.
Seventy Seven Energy LLC
Seventy Seven Land Company LLC
Seventy Seven Operating LLC
Superior QC, 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
Texas
Delaware
Delaware
Oklahoma
Oklahoma
Texas
Texas
Dubai Multi Commodities Centre
Kingdom of Saudi Arabia
Nova Scotia
Texas
Delaware
Dubai International Financial Centre
The Netherlands
British Virgin Islands
The Netherlands
The Netherlands
Delaware
The Netherlands
British Virgin Islands
Delaware
Oklahoma
Delaware
Oklahoma
Oklahoma
Delaware
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), Form S-4 (No. 333-226453)
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
13, 2019 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 13, 2019
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 13, 2019
/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 13, 2019
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, 2018, 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 13, 2019
/s/ C. Andrew Smith
C. Andrew Smith
Chief Financial Officer
February 13, 2019