Pioneer Energy Services
2014 ANNUAL REPORT
EVERY PROJECT
IS PERSONAL
SELECTED FINANCIAL DATA
(In thousands, except per share data)
2014 (3)
2013 (2)
2012
2011
2010
Revenues
Net income (loss)
Adjusted EBITDA(1)
$1,055,223
$960,186
$919,443
$715,941
$487,210
(38,018)
(35,932)
30,032
11,177
(33,261)
277,081
234,742
249,283
183,870
103,151
Income (loss) per common share - diluted
(0.60)
(0.58)
0.48
0.19
(0.62)
Total assets
1,171,589
1,229,623
1,339,776
1,172,754
841,343
Long-term debt and capital lease obligations,
excluding current installments
455,053
499,666
518,725
418,728
279,530
Shareholders’ equity
495,064
518,433
547,680
510,445
396,333
Net cash provided by operating activities
233,041
174,580
199,366
144,879
98,351
(1) For a reconciliation of the difference between this financial measure, which is not in accordance with U.S. Generally Accepted Accounting
Principles (GAAP), and the most directly comparable financial measure, which calculated in accordance with GAAP, see the last page of this
Annual Report following the Form 10-K.
(2) Includes goodwill and intangible asset impairment charges of $44.8 million ($27.1 million net of tax).
(3) Includes property and equipment impairment charges of $73.0 million ($45.3 million net of tax).
AREAS OF OPERATIONS
PIONEER’S SERVICE LINES
Corporate Headquarters
Well Servicing
Wireline Services
Drilling Services
Coiled Tubing Services
Pioneer Energy Services
2014 ANNUAL REPORT
To Our Shareholders and Employees,
2014 was a banner year for Pioneer. We broke the $1 billion mark in
revenues for the first time in our Company’s history, and each of our four
core businesses contributed meaningfully in terms of revenue growth,
profitability, service excellence and best-in-class safety performance.
Wm. Stacy Locke
President and Chief Executive Officer
While we enjoyed strong demand for our services during
base is clearly emphasizing horizontal wells over vertical wells
2014, storm clouds began brewing late in the year. The price
based on a better return on investment. As a result, we have
of oil, which was over $100 per barrel in the middle of 2014,
moved quickly to adapt to this shift in demand and in the first
fell below $90 per barrel in October and continued to decline
quarter of 2015 have sold almost all of our mechanical rigs
sharply through the remainder of the year, reaching $44 per
and other lower horsepower electric rigs. The cash proceeds
barrel in January 2015. Oil and gas operators were quick to
generated from these rig sales will help fund our five
respond by releasing drilling rigs and negotiating price
new-build, latest generation AC-powered rigs. These new
reductions for all our services.
drilling rigs are contracted for multi-year terms at very
attractive pricing and will be drilling horizontal wells in the
By late March 2015, over 800 drilling rigs in the U.S., or 45%
Eagle Ford, Permian and Bakken resource plays with quality
of the total, had been released. Rigs drilling vertical and
clients. Our strategic focus going forward will be to design
directional wells were hit first and the hardest, but rigs drilling
and build the most advanced and competitive drilling rigs for
horizontal wells in the shale and unconventional plays were
the horizontal markets.
also materially impacted. With oil prices remaining soft, more
drilling rigs are being released as we head into the second
Our eight-rig operation in Colombia is experiencing similar
quarter of 2015.
pressures as the U.S. market. Utilization and pricing are
depressed and will likely remain that way for the remainder of
We have also been quick to respond to these rapidly
the year. We have been the top-performing contractor in
changing market conditions by reducing operating expense,
Colombia for many years and remain hopeful that we will
capital outlays and continuing to de-lever our balance sheet.
continue to have opportunities in the country for years to
As Pioneer faces this difficult environment, we believe our
come.
balance sheet is healthy and we have a more resilient revenue
base through our diversified services. During 2014, we
refinanced our long-term debt, increased our revolving line of
credit, and paid down more than $50 million in outstanding
debt. The end result was an approximate $23 million per year
PRODUCTION SERVICES SEGMENT
Well Servicing
reduction of interest expense, which is about a 50%
Our well servicing business achieved record sales and
decrease, and improved financial flexibility.
DRILLING SERVICES SEGMENT
Our drilling services business performed well in 2014 with
strong demand during the first three quarters of the year;
however, the industry is evolving away from vertical wells to
horizontal wells and the steep decline in commodity prices is
intensifying this shift. The first rigs to stack when oil prices fell
were the mechanical rigs drilling vertical wells. Our client
operating margins in 2014, and we believe it is one of the best
performing in the industry. We increased our unit count by
seven rigs during 2014 and ended the year at 116 rigs. We
plan to add nine more units in 2015. Well Servicing appears to
be holding up better than our other businesses during the
weak oil price environment; however, both pricing and
utilization for this business will be negatively impacted to a
degree in 2015.
Pioneer Energy Services
2014 ANNUAL REPORT
Wireline Services
FLEET COMPOSITION
Wireline Services performed very well in 2014, achieving its
highest revenue ever and with impressive operating margins.
Well Servicing
108
109
125
116
Our wireline fleet increased by one unit to 120 during 2014,
and we took delivery of an additional eight units in first
quarter of 2015. Pricing and activity levels came under
pressure as the oil prices declined and we anticipate 2015 will
be a challenging year for wireline services.
Coiled Tubing Services
Our coiled
tubing business delivered a
remarkable
improvement in 2014. We focused our operations on key
markets and were able to deliver consistent, high-quality and
safe services. We grew our coiled tubing fleet by four units to
17 and increased our breadth of service offerings. Like
wireline, coiled tubing will face pricing and utilization
headwinds in 2015.
OUTLOOK
89
74
74
2009
2010
2011
2012
2013
2014
2015E
Wireline
120
119
120
128
105
84
63
There is no question that 2015 will be a challenging year.
However, our
industry-leading safety record and solid
reputation for quality has enabled us to attract and retain the
2009
2010
2011
2012
2013
2014
2015E
best clients in the industry through up and down cycles. Our
goal is to remain cash neutral during the current down cycle
by scaling back our cost structure and keeping a tight rein on
capital expenditures. Revenues will come down but so will
costs.
Coiled Tubing
13
13
17
17
Historically, down cycles last 12 to 18 months and, at the
present time, we don’t see this cycle being any different. Rig
count has come down rapidly, and this should cause U.S.
production growth
to slow and, perhaps, be
flat
3
10
6
month-over-month by year-end. As U.S. production growth
slows, oil pricing should begin to gradually improve, ultimately
leading to increased activity levels and later to improved
pricing for our equipment and services.
2009
2010
2011
2012
2013
2014
2015E
We are well positioned to weather the downturn and emerge
Drilling Services
Electrical rigs
Mechanical rigs
leaner, stronger and more competitive than before with a
top-quality equipment fleet, a blue chip client base, and the
financial flexibility to act quickly on opportunities that present
themselves in the next market upswing. I want to thank our
dedicated employees for their contributions in 2014 and our
shareholders for their long-standing support.
Sincerely,
Wm. Stacy Locke
71
71
30
41
30
41
64
29
35
69
36
33
62
39
23
53
37
16
2009
2010
2011
2012
2013
2014
42
38
4
2015E1
PRESIDENT AND CHIEF EXECUTIVE OFFICER
(1) At March 31, 2015, we had a marketable fleet of 37 drilling rigs.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
(Mark one)
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
Commission File Number: 1-8182
PIONEER ENERGY SERVICES CORP.
(Exact name of registrant as specified in its charter)
_____________________________________________
TEXAS
(State or other jurisdiction
of incorporation or organization)
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas
(Address of principal executive offices)
74-2088619
(I.R.S. Employer
Identification Number)
78209
(Zip Code)
Registrant’s telephone number, including area code: (855) 884-0575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $0.10 par value
Name of each exchange on which registered
NYSE
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
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
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
No
No
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act. (Check one):
Large accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant as of the last business day of the
registrant’s most recently completed second fiscal quarter (based on the closing sales price on the New York Stock Exchange (NYSE) on
June 30, 2014) was approximately $1.1 billion.
No
As of January 29, 2015, there were 63,867,955 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant’s 2015 Annual Meeting of Shareholders are incorporated by reference into Part
III of this report.
TABLE OF CONTENTS
PART I
Introductory Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
PART II
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases
of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 12.
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Shareholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . .
Item 14.
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
PART IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
1
2
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PART I
INTRODUCTORY NOTE
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
From time to time, our management or persons acting on our behalf make forward-looking statements to inform
existing and potential security holders about our company. These statements may include projections and estimates
concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending.
Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,”
“expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of
future events or outcomes. These forward-looking statements speak only as of the date on which they are first made,
which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will
specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements contained in this Annual Report on Form 10-K, including those that express a
belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements.
Such forward-looking statements appear in Item 1—“Business” and Item 3—“Legal Proceedings” in Part I of this
report; in Item 5—“Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of
Equity Securities,” Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of
Operations,” Item 7A—“Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated
Financial Statements we have included in Item 8 of Part II of this report; and elsewhere in this report. These forward-
looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and
we caution you not to place undue reliance on them. We have based these forward-looking statements on our current
expectations and assumptions about future events. While our management considers these expectations and assumptions
to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks,
contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These
risks, contingencies and uncertainties relate to, among other matters, the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
general economic and business conditions and industry trends;
levels and volatility of oil and gas prices;
the continued demand for drilling services or production services in the geographic areas where we operate;
decisions about exploration and development projects to be made by oil and gas exploration and production
companies;
the highly competitive nature of our business;
technological advancements and trends in our industry, and improvements in our competitors' equipment;
the loss of one or more of our major clients or a decrease in their demand for our services;
future compliance with covenants under our senior secured revolving credit facility and our senior notes;
operating hazards inherent in our operations;
the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry;
the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components;
the continued availability of qualified personnel;
the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth
and effectively integrate acquisitions;
the political, economic, regulatory and other uncertainties encountered by our operations, and
changes in, or our failure or inability to comply with, governmental regulations, including those relating to
the environment.
We believe the items we have outlined above are important factors that could cause our actual results to differ
materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed
many of these factors in more detail elsewhere in this report. Other unpredictable or unknown factors could also have
1
material adverse effects on actual results of matters that are the subject of our forward-looking statements. We undertake
no duty to update or revise any forward-looking statements, except as required by applicable securities laws and
regulations. We advise our security holders that they should (1) be aware that unpredictable or unknown factors not
referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense
when considering our forward-looking statements. Also, please read the risk factors set forth in Item 1A—“Risk
Factors.”
Item 1. Business
General
Pioneer Energy Services Corp. (formerly called "Pioneer Drilling Company") was incorporated under the laws
of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999,
we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from
new and used components. In March 2008, we acquired two production services companies which significantly
expanded our service offerings to include well servicing and wireline services. Through these purchases, we also
acquired fishing and rental services operations, which were subsequently sold on September 17, 2014. We also acquired
a coiled tubing services business at the end of 2011, to expand our existing production services offerings. We have
continued to invest in the growth of all our core service offerings through acquisitions and organic growth.
Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent
and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing
regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services
offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining
the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our
clients.
We currently conduct our operations through two operating segments: our Drilling Services Segment and our
Production Services Segment. The following is a description of these two operating segments. Financial information
about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial
Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form
10-K.
• Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse
group of oil and gas exploration and production companies through our six drilling divisions in the US and
internationally in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the
ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas
wells either through competitive bidding or through direct negotiations with existing or potential clients. Our
drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms
generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment
used, and the anticipated duration of the work to be performed.
Since October 2014, domestic and international oil prices have declined significantly to historically low price
levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our
long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0
million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric
drilling rigs to their estimated fair value.
Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically
the first rigs to become idle. As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower
electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end
and 15 rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts
are completed. In January and February 2015, we sold six of these drilling rigs.
2
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015, as
well as our expected count at March 31, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected at March 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
56
Drilling Rigs
Held for Sale
(9)
(12)
(18)
Drilling Rig
Fleet Count
53
47
38
As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
South Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rig Count
13
10
9
4
3
8
47
We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver
and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during
the second quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs
which we expect to sell in the near-term and considering the five new-build drilling rigs under construction,
we expect to end 2015 with a drilling fleet of 43 rigs.
As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which
are earning under term contracts. Four of our drilling rigs in Colombia are currently working under term
contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients
to diversify our client base in Colombia.
In response to the dramatic decline in oil prices during recent months, we have received early termination
notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will
be released upon completion of their current wells, all of which are expected to be completed by the end of
the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be
recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.
• Production Services Segment—Our Production Services Segment provides a range of services to exploration
and production companies, including well servicing, wireline services and coiled tubing services. Our
production services operations are concentrated in the major United States onshore oil and gas producing
regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.
On September 17, 2014, we completed the sale of our fishing and rental services operations. We provide our
services to a diverse group of oil and gas exploration and production companies. The primary production
services we offer are the following:
• Well Servicing. A range of services are required in order to establish production in newly-drilled wells
and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to
provide these necessary services, including the completion of newly-drilled wells, maintenance and
workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of
February 1, 2015, we operate 107 rigs with 550 horsepower and 10 rigs with 600 horsepower through 11
locations, mostly in the Gulf Coast states, as well as in Arkansas and North Dakota.
• Wireline Services. In order for oil and gas exploration and production companies to better understand the
reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir
3
rocks and fluids. To complete a well, the production casing must be perforated to establish a flow path
between the reservoir and the wellbore. We use our fleet of wireline units to provide these important
logging and perforating services. We provide both open and cased-hole logging services, including the
latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration
and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge
plugs. As of December 31, 2014, we have four wireline units placed as held for sale, for which we
recognized approximately $0.3 million of impairment charges to reduce their carrying values to fair value.
As of February 1, 2015, we operate a fleet of 128 wireline units through 24 locations in the Gulf Coast,
Mid-Continent and Rocky Mountain states.
• Coiled Tubing. Coiled tubing is an important element of the well servicing industry that allows operators
to continue production during service operations without shutting in the well, thereby reducing the risk
of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large
reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing
fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also
used for a number of horizontal well applications such as milling temporary plugs between frac stages.
As of February 1, 2015, our coiled tubing business consists of 12 onshore and five offshore coiled tubing
units which are currently deployed through three locations in Texas and Louisiana.
Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209.
Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge
through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed
with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report
or otherwise made part of this report.
Industry Overview
Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating
expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by
current and expected oil and natural gas prices.
In recent years, generally increasing oil prices drove industry equipment utilization and revenue rates up,
particularly in oil-producing regions and certain shale regions. Even though advancements in technology have improved
the efficiency of drilling rigs, demand remained steady, particularly for drilling rigs that are able to drill horizontally.
Beginning in October 2014, domestic and international oil prices have significantly declined to historically low price
levels. If oil prices continue to decline, or if oil and natural gas prices remain at current levels for an extended period
of time, then industry equipment utilization and revenue rates will further decrease, both domestically and in Colombia.
While drilling and production services have historically trended similarly in response to fluctuations in commodity
prices, because exploration and production companies often adjust their budgets for exploratory drilling first in response
to a shift in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than
the demand for production services which is more dependent on expenditures to sustain production.
Our business is influenced substantially by both operating and capital expenditures by exploration and production
companies. Exploration and production spending is generally categorized as either a capital expenditure or operating
expenditure.
Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to
volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of
years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove
inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a
deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely
deferred until prices are forecasted to return to an acceptable level.
4
5In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated according to a simple short-term payout criterion that is far less dependent on commodity price forecasts.Capital expenditures by exploration and production companies for the drilling of exploratory wells or new wells in proven areas are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. In contrast, because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells, which requires a range of production services, are relatively stable and more predictable. The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last three years are illustrated in the graphs below. As shown in the charts above, the trends in industry rig counts are influenced primarily by fluctuations in oil prices, which affect the levels of capital and operating expenditures made by our clients.Colombian oil prices have historically trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon its national oil company's long-term exploration and production programs.Technological advancements and trends in our industry also affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle. For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K. Competitive Strengths
Our competitive strengths include:
• One of the Leading Providers in the Most Attractive Regions. Our drilling rigs operate in many of the
most attractive producing regions in the Americas, including the Bakken, Marcellus and Eagle Ford shales,
and the Permian Basin, as well as Colombia. Our drilling rigs are located in six divisions throughout the
United States and Colombia, diversifying our geographic exposure and limiting the impact of any regional
slowdown. We believe the varied capabilities of our drilling rigs make them well suited to these areas
where the optimal rig configuration is dictated by local geology and market conditions.
• High Quality Assets. Excluding all of the drilling rigs that we expect to sell in the near-term, over 85%
of our drilling fleet was purchased or built new within the last 15 years, ten of which are AC drilling rigs
which we constructed during 2011 to 2013. Additionally, we are currently constructing five new-build
1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling
contracts in 2015. Over 90% of our drilling rigs, excluding those that we expect to sell, are capable of
drilling horizontal wells, and approximately 75% are equipped with either a walking or skidding system
for pad drilling. Over 75% of our production services assets have been built since 2007, and all of our
well servicing rigs have at least 550 horsepower. We believe that our modern and well maintained fleet
allows us to realize higher contract and utilization rates because we are able to offer our clients equipment
that is more reliable and requires less downtime than older equipment.
• Provide Services Throughout the Well Life Cycle. By offering our clients both drilling and production
services, we capture revenue throughout the life cycle of a well and diversify our business. Our Drilling
Services Segment performs work prior to initial production, and our Production Services Segment provides
services such as logging, completion, perforation, workover and maintenance throughout the productive
life of a well. We also provide certain end-of-well-life activities such as plugging and abandonment.
Drilling and production services activity have historically exhibited different degrees of demand
fluctuation, and we believe the diversity of our services reduces our exposure to decreases in demand for
any single service activity. Further, the diversity of our service offerings enables us to cross-sell our
services, benefiting our clients, allowing us to generate more business from existing clients and increasing
our profits as we expand our services within existing markets.
• Excellent Safety Record. Our 2014 total recordable incident rate was one of the lowest we have achieved
since our company's inception. Our safety program called “LiveSafe” focuses on creating an environment
where everyone is committed to and recognizes the possibility of always working without incident or
injury. We believe that by building strong relationships among our people, we can achieve an excellent
safety record. Our excellent safety record and reputation are critical to winning new business and expanding
our relationships with existing clients. Our commitment to safety helps us to keep our employees safe
and reduces our business risk.
• Experienced Management Team. We believe that important competitive factors in establishing and
maintaining long-term client relationships include having an experienced and skilled management team
and maintaining employee continuity. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President
and has over 35 years of industry experience. Our President of Drilling Services, Brian Tucker, and our
President of Production Services, Joe Eustace, have over 45 years of combined oilfield services experience.
Our management team has operated through numerous oilfield services cycles and provides us with
valuable long-term experience and a detailed understanding of client requirements. We also seek to
maximize employee continuity and minimize employee turnover by maintaining modern equipment, a
strong safety record, ongoing growth and competitive compensation. We have devoted, and will continue
to devote, substantial resources to our employee safety and training programs and maintaining low
employee turnover.
•
Longstanding and Diversified Clients. We maintain long-standing, high quality client relationships with
a diverse group of large independent oil and gas exploration and production companies including Whiting
Petroleum Corporation, which accounted for approximately 11.9% of our 2014 consolidated revenues,
6
Apache Corporation, Hess Corporation, Penn Virginia Oil & Gas, LP and Continental Resources. We also
maintain a good relationship with Ecopetrol, which accounted for approximately 9.9% of our 2014
consolidated revenues. We believe our relationships with our clients are strong and offer numerous
opportunities for future growth.
Strategy
In past years, our strategy was to become a premier land drilling and production services company through steady
and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production
services business which we operate in the most attractive drilling markets throughout the United States and in Colombia.
Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services
company, continue to expand our relationships with existing clients, expand our client base in the areas where we
currently operate and further enhance our geographic diversification through selective expansion. The key elements of
this long-term strategy are focused on our:
• Competitive Position in the Most Attractive Domestic Markets. Shale plays and non-shale oil or liquid rich
environments are increasingly important to domestic hydrocarbon production, and not all drilling rigs are
capable of successfully drilling in these unconventional opportunities. We are currently operating in the
Bakken, Marcellus and Eagle Ford shales and the Permian Basin. All of the ten drilling rigs we constructed
in 2011 to 2013 are currently operating in domestic shale and unconventional plays and we expect that our
five new-build drilling rigs currently under construction will be deployed to these regions as well. Additionally,
we have added significant capacity in recent years to our production services fleets, which we believe are well
positioned to further capitalize on shale development.
• Exposure to Oil and Liquids Rich Natural Gas Drilling Activity. We believe that our flexible drilling and
production services fleets allow us to pursue varied opportunities, enabling us to focus on a favorable mix of
natural gas, oil and liquids rich natural gas activity. With natural gas prices at historically low levels in recent
years, we intentionally increased our exposure to oil-related activities by redeploying certain of our assets into
predominately oil-producing regions. With the recent decline in oil prices, we believe our fleets are highly
capable and well positioned for deployment to whichever market is most profitable.
•
International Presence. In 2007, we began operating in Colombia after a comprehensive review of international
opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions,
political stability, and a long-term commitment to expanding national oil and gas production. Four of our
drilling rigs in Colombia are currently working under term contracts that extend through mid-2015 and we
are actively marketing our other four rigs to multiple clients to diversify our client base in Colombia.
• Growth Through Select Capital Deployment. We have historically invested in the growth of our business by
strategically upgrading our existing assets, selectively engaging in new-build opportunities, and through
selective acquisitions. We have continued to make significant investments in the growth of our business over
the past several years. We acquired a coiled tubing services business to expand our existing production services
offerings at the end of 2011. Since the beginning of 2010, we have added significant capacity to our other
production services fleets through the addition of 65 wireline units, 43 well servicing rigs and we have
constructed ten AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays.
We are currently constructing five new-build AC rigs which we expect to deliver and begin operating under
long-term drilling contracts in 2015.
With the recent decline in oil prices and the expected reductions in our rig utilization and revenue rates in 2015,
our near-term goals are to maintain a strong balance sheet and ample liquidity. Management efforts are focused on
stringent cost control measures, the liquidation of nonstrategic or under-performing assets and continued emphasis on
the execution and performance of our core businesses. We are currently executing limited organic growth through select
fleet additions which were ordered prior to the decline in oil prices. We believe these near-term goals will position us
to take advantage of future business opportunities and continue our long-term growth strategy.
7
Overview of Our Segments and Services
Drilling Services Segment
There are numerous factors that differentiate land drilling rigs, including their power generation systems and
their drilling depth capabilities. A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and
related equipment to circulate drilling fluid, blowout preventers and related equipment. Generally, drilling rigs operate
with crews of five to six persons.
Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs
may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000
horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving
depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables
to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and
circulating systems.
Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly
that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The
drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts,
clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the
main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are
being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy
developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered
into the well.
The rotating equipment from top to bottom consists of a top drive or a swivel, the kelly, and kelly bushing, the
rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the top drive or swivel and the
drill bit as the drill stem. In a top drive system, the top drive hangs from a hook at the bottom of the traveling block.
The top drive has a passageway for drilling mud to get into the drill pipe, and it has a heavy-duty electric motor connected
to a threaded drive shaft which connects to and rotates the drill pipe. In a kelly drive system, the swivel assembly
sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for
circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook
assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose,
attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that
transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole.
The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the
kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master
bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling
fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly
bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through
which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with
threaded sections on each end. Drill collars are heavier than drill pipe and both are threaded on the ends. Collars are
used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which
chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the
surface where the circulating system filters it out of the fluid.
Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated
for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used
in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the
start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these
two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well
pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from
the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem
to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the
return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are
8
usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and
excess water around the location.
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy
strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing
can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. The actual drilling depth
capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size,
weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the
amount of drill pipe and other equipment needed to drill a well.
Technological advancements and trends in our industry affect the demand for certain types of equipment. In a
continuing effort to improve our drilling rig fleet, we have installed top drives on 41 rigs (with seven additional spare
top drives available for installation), iron roughnecks on 42 rigs (with 16 additional spare iron roughnecks available
for installation), walking/skidding systems on 31 rigs and automatic catwalks on 33 rigs. These upgrades provide our
clients with drilling rigs that have more varied capabilities for drilling in unconventional plays, and they improve our
efficiency and safety.
In horizontal well drilling, operators can utilize top drives to reach formations that may not be accessible with
conventional rotary drilling. Top drives provide maximum torque and rotational control, improved well control and
better hole conditioning. In recent years, oil and gas exploration and production companies have increased the use of
"pad drilling" whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a
single pad-site location. Walking systems increase efficiency by allowing multiple wells to be drilled on the same pad
site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move
times and costs. Our walking system enables the drilling rig to move forward, backward, and side to side which affords
the operator additional flexibility.
An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the
occurrence of repetitive motion injuries and decrease drill pipe tripping time. An automated catwalk is a drill pipe
handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its
function significantly reduces pick up and lay down time, thereby decreasing operator costs for handling casing.
The following table sets forth historical information regarding utilization for our drilling rig fleet:
Average number of operating rigs for the period . . . . . . . . . . .
Average utilization rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year ended December 31,
2014
62.0
2013
68.2
2012
65.0
2011
69.3
2010
71.0
87%
84%
87%
73%
59%
As of December 31, 2014, we had 53 drilling rigs in our fleet and nine drilling rigs classified as held for sale
which were idle as of year-end. We expect to place a total of 15 additional rigs as held for sale during the first quarter
of 2015. Excluding the rigs which we expect to sell in the near-term and considering the five new-build drilling rigs
under construction, we expect to end 2015 with a drilling fleet of 43 rigs. The following is a summary of our drilling
rig counts as of December 31, 2014 and February 1, 2015, as well as our expected count at March 31, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected at March 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
56
Drilling Rigs
Held for Sale
(9)
(12)
(18)
Drilling Rig
Fleet Count
53
47
38
We believe that our drilling rigs and other related equipment are in good operating condition. Our employees
perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies
for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement
and upgrades of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be
subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately
available.
9
Our drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms
generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used,
and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a
single well and typically permit the client to terminate on short notice. We enter into longer-term drilling contracts for
our newly constructed rigs and/or during periods of high rig demand. Currently, we have contracts with original terms
of six months to four years in duration.
As of February 1, 2015, we have 29 drilling rigs earning under term contracts, which if not renewed prior to the
end of their terms, will expire as follows:
United States . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . .
Total
Term Contracts
25
4
29
Within
6 Months
13
4
17
Term Contract Expiration by Period
6 Months
to 1 Year
6
—
6
1 Year to
18 Months
4
—
4
18 Months
to 2 Years
2
—
2
2 to 4
Years
—
—
—
In response to the dramatic decline in oil prices during recent months, we have received early termination notices
for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon
completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting
in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining
term of the contracts, $0.3 million of which was recognized in 2014.
As a provider of contract land drilling services, our business and the profitability of our operations depend on
the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets
where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized
by significant changes in the levels of exploration and development activities. During periods of reduced drilling activity
or excess rig capacity, price competition tends to increase and the profitability of daywork contracts tends to decrease,
and in such a competitive price environment, we may be more inclined to enter into turnkey contracts that expose us
to greater risk of loss but which offer higher potential contract profitability.
During the last three fiscal years, our drilling contracts have primarily been for daywork drilling. The following
table presents, by type of contract, information about the total number of wells we completed for our clients during
each of the last three fiscal years.
Types of Contracts
Daywork . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Turnkey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total number of wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
1,001
106
1,107
2013
2012
970
27
997
881
11
892
Year ended December 31,
Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig and required personnel to our
client who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used.
Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a
daywork drilling contract, the client bears a large portion of the out-of-pocket drilling costs and we generally bear no
part of the usual risks associated with drilling, such as time delays and unanticipated costs.
Turnkey Contracts. Under a turnkey contract, we agree to drill a well for our client to a specified depth and under
specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well.
We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required
to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well
logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our client
only after we have performed the terms of the drilling contract in full.
10
The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This
is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally
assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery
breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations
and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify
and reduce some of the drilling risks we assume. We use the results of this analysis to evaluate the risks of a proposed
contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified
drilling personnel, risk management program, internal engineering expertise and access to proficient third-party
engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also
maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-
insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial
position and results of operations.
Production Services Segment
Well Servicing. Our well servicing rig fleet provides a range of services, including the completion of newly-
drilled wells, maintenance and workover of existing wells, and plugging and abandonment of wells at the end of their
useful lives.
Newly drilled wells require completion services to prepare the well for production. Well servicing rigs are
frequently used to complete newly drilled wells to minimize the use of higher cost drilling rigs in the completion
process. The completion process may involve selectively perforating the well casing in the productive zones to allow
oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other
downhole equipment. The completion process typically requires a few days to several weeks, depending on the nature
and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services
require less well-to-well mobilization of equipment and can provide higher operating margins than regular maintenance
work. The demand for completion services is directly related to drilling activity levels, which are sensitive to changes
in oil and gas prices.
Regular maintenance is required throughout the life of a well to sustain optimal levels of oil and gas production.
Common maintenance services include repairing inoperable pumping equipment in an oil well and replacing defective
tubing in a gas well. Our maintenance services involve relatively low-cost, short-duration jobs which are part of normal
well operating costs. The need for maintenance does not directly depend on the level of drilling activity, although it is
somewhat impacted by short-term fluctuations in oil and gas prices. Accordingly, maintenance services generally
experience relatively stable demand; however, when oil or gas prices are too low to justify additional expenditures,
operating companies may choose to temporarily shut in producing wells rather than incur additional maintenance costs.
In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or
modifications called workovers, which are typically more complex and more time consuming than maintenance
operations. Workover services include extensions of existing wells to drain new formations either through perforating
the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or
the drilling of lateral well bores to improve reservoir drainage patterns. Our well servicing rigs are also used to convert
former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation
for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement
of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive
workover operations are normally performed by a well servicing rig with additional specialized auxiliary equipment,
which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular
type of workover operation. All of our well servicing rigs are designed to perform complex workover operations. A
workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand
for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas
prices.
Well servicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of
producing in economic quantities. Many well operators bid this work on a “turnkey” basis, requiring the service company
to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation
received, and complying with state regulatory requirements. Plugging and abandonment work can provide favorable
11
operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators
must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and
abandonment work throughout our core areas of operation in conjunction with equipment provided by other service
companies.
We typically bill clients for our well servicing on an hourly basis during the period that the rig is actively working.
As of February 1, 2015, our fleet of well servicing rigs totaled 117 rigs, which we operate through 11 locations, mostly
in the Gulf Coast states, as well as in Arkansas and North Dakota. Our fleet is among the newest in the industry,
consisting of 107 rigs with 550 horsepower and 10 rigs with 600 horsepower capable of working at depths of 20,000
feet.
Wireline Services. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well. Wireline
trucks are often used in place of a well servicing rig when there is no requirement to remove tubulars from the well in
order to make repairs.
Wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise
a variety of specialized tools in and out of the wellbore. Electric wireline contains a conduit that allows signals to be
transmitted to or from tools located in the well. These tools can be used to measure pressures and temperatures as well
as the condition of the casing and the cement that holds the casing in place. In order for oil and gas exploration and
production companies to better understand the reservoirs they are drilling or producing, they require logging services
to accurately characterize reservoir rocks and fluids. We provide both open and cased-hole logging services, including
the latest pulsed-neutron technology.
Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore,
installing bridge plugs, perforating the casing in order to prepare the well for production, or cutting off pipe that is
stuck in the well so that the free section can be recovered.
As of February 1, 2015, our wireline services fleet totaled 128 wireline units, including six offshore units, which
we operate through 24 locations in Texas, Kansas, Colorado, Montana, North Dakota, Louisiana, Oklahoma and
Wyoming.
Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators
to continue production during service operations without shutting in the well, thereby reducing the risk of formation
damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural
gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation
utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications
such as milling temporary plugs between frac stages. As of February 1, 2015, our coiled tubing business consists of 12
onshore and five offshore coiled tubing units which are currently deployed through three locations in Texas and
Louisiana.
Seasonality
All our production services operations are impacted by seasonal factors. Our business can be negatively impacted
during the winter months due to inclement weather, fewer daylight hours, and holidays. Because our well servicing
rigs, wireline units and coiled tubing units are mobile, during periods of heavy snow, ice or rain, we may not be able
to move our equipment between locations.
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Clients
We provide drilling and production services to numerous major and independent oil and gas exploration and
production companies that are active in the geographic areas in which we operate. The following table shows our three
largest clients as a percentage of our total revenue for each of our last three fiscal years.
Fiscal year ended December 31, 2014
Whiting Petroleum Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ecopetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Penn Virginia Oil & Gas, LP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fiscal year ended December 31, 2013
Whiting Petroleum Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ecopetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Apache Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fiscal year ended December 31, 2012
Whiting Petroleum Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ecopetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Apache Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Revenue
Percentage
11.9%
9.9%
6.0%
12.6%
10.7%
5.9%
10.1%
9.7%
5.5%
Competition
Drilling Services Segment
We encounter substantial competition from other drilling contractors. Our primary market areas are highly
fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in
response to market conditions heightens the competition in the industry.
The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal
competitors are Helmerich & Payne, Inc., Precision Drilling Trust, Patterson-UTI Energy, Inc. and Nabors Industries,
Ltd. In addition to pricing and rig availability, we believe the following factors are also important to our clients in
determining which drilling contractors to select:
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•
•
•
•
the type and condition of each of the competing drilling rigs;
the mobility and efficiency of the rigs;
the quality of service and experience of the rig crews;
the safety records of our company;
the offering of ancillary services; and
the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and
drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our
equipment, our safety record, our ability to offer ancillary services, the experience of our rig crews and the quality of
service we provide to differentiate us from our competitors.
Drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly
from region to region at any particular time. If demand for drilling services improves in a region where we operate,
our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could
rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.
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Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities
in these areas may enable them to:
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•
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better withstand industry downturns;
compete more effectively on the basis of price and technology;
better retain skilled rig personnel; and
build new rigs or acquire and refurbish existing rigs and place them into service more quickly than us in
periods of high drilling demand.
Production Services Segment
The market for production services is highly competitive. Competition is influenced by such factors as price,
capacity, availability of work crews, type and condition of equipment and reputation and experience of the service
provider, including safety record. We believe that an important competitive factor in establishing and maintaining long-
term client relationships is having an experienced, skilled and well-trained work force. In recent years, many of our
larger clients have placed increased emphasis on the safety performance and quality of the crews, equipment and services
provided by their contractors. We have devoted, and will continue to devote, substantial resources toward employee
safety and training programs. Although we believe clients consider all of these factors, price is generally the primary
factor in determining which service provider is awarded the work. However, we believe that many clients are willing
to pay a slight premium for the quality and safe, efficient service we provide.
The largest well servicing providers that we compete with are Key Energy Services, Basic Energy Services,
Nabors Industries, Superior Energy Services, Inc. and CC Forbes. In addition, there are numerous smaller companies
that compete in our well servicing markets.
The wireline market is dominated by Schlumberger Ltd. and Halliburton Company. These companies have a
substantially larger asset base than we do and operate in all major U.S. oil and natural gas producing basins. Other
competitors include Weatherford International, Baker Hughes, Superior Energy Services, Basic Energy Services, and
C&J Energy Services. The market for wireline services is very competitive, but historically we have competed effectively
with our competitors based on performance and strong client service.
The market for coiled tubing has increased due to the growth in deep well and horizontal drilling. Our primary
competitors in the coiled tubing services market include Schlumberger Ltd., Baker Hughes, Halliburton Company, Key
Energy Services, RPC Inc. and Superior Energy Services, Inc. In addition, numerous small companies compete in our
coiled tubing services markets in the United States.
The need for well servicing, wireline and coiled tubing services fluctuates primarily in relation to the price (or
anticipated price) of oil and natural gas, which in turn is driven by the supply of and demand for oil and natural gas.
Generally, as supply of these commodities decreases and demand increases, service and maintenance requirements
increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced
environment.
The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level
of domestic and international oil and gas exploration and development activity, as well as the equipment capacity in
any particular region. For a more detailed discussion, see Item 7—“Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
Raw Materials
The materials and supplies we use in our drilling and production services operations include fuels to operate our
equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for
any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages
of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling
equipment or supplies that we may be unable to pass on to clients. In addition, during periods of shortages, the delivery
times for equipment and supplies can be substantially longer. Any significant delays in obtaining drilling equipment
or supplies could limit our drilling operations and jeopardize our relations with clients. In addition, shortages of drilling
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equipment or supplies could delay and adversely affect our ability to obtain new contracts for our drilling rigs, which
could have a material adverse effect on our financial condition and results of operations.
Operating Risks and Insurance
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks
of:
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blowouts;
fires and explosions;
loss of well control;
collapse of the borehole;
lost or stuck drill strings; and
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
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•
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•
suspension of drilling operations;
damage to, or destruction of, our property and equipment and that of others;
personal injury and loss of life;
damage to producing or potentially productive oil and gas formations through which we drill; and
environmental damage.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However,
some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks
include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors,
we attempt to obtain contractual protection against uninsured operating risks from our clients. However, clients who
provide contractual indemnification protection may not in all cases maintain adequate insurance to support their
indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against
liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully
insured or indemnified against or the failure of a client to meet its indemnification obligations to us could materially
and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain
adequate insurance in the future at rates we consider reasonable.
Our current insurance coverage includes property insurance on our rigs, drilling equipment, production services
equipment and real property. Our insurance coverage for property damage to our rigs, drilling equipment and production
services equipment is based on our estimates of the cost of comparable used equipment to replace the insured property.
The policy provides for a deductible on drilling rigs of $500,000 per occurrence ($750,000 deductible for rigs with an
insured value greater than $10 million), and a deductible on production services equipment of $250,000 per occurrence.
Our third-party liability insurance coverage is $101 million per occurrence and in the aggregate, with a deductible of
$250,000 per occurrence. We also carry insurance coverage for pollution liability up to $20 million with a deductible
of $500,000. We believe that we are adequately insured for public liability and property damage to others with respect
to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of
well disasters, extensive fire damage or damage to the environment.
In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey
contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface,
redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million, $10 million, $15 million or
$20 million, subject to a deductible of $150,000 or $250,000, depending on the area in which the well is drilled and its
target depth. This policy also provides care, custody and control insurance, with a limit of $1 million, subject to a
$100,000 deductible.
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Employees
We currently have approximately 3,400 employees. The majority of our employees work in operations for our
Drilling Services Segment and Production Services Segment and are primarily compensated on an hourly basis. The
number of employees in operations fluctuates depending on the utilization of our drilling rigs, well servicing rigs,
wireline units and coiled tubing units at any particular time. None of our employment arrangements are subject to
collective bargaining arrangements.
Our operations require the services of employees having the technical training and experience necessary to achieve
proper operational standards. As a result, our operations depend, to a considerable extent, on the continuing availability
of such personnel. Although we have not encountered material difficulty in hiring and retaining employees in our
operations, shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of
personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training
and experience to adequately operate our equipment, our operations could be materially and adversely affected. While
we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant
increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or
both. The occurrence of either of these events for a significant period of time could have a material adverse effect on
our financial condition and results of operations.
Facilities
We lease our corporate office facilities located at 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas 78209.
We conduct our business operations through 66 other real estate locations, of which we own 15, in the United States
(Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, Wyoming, Mississippi, Arkansas, Louisiana
and Kansas) and internationally in Colombia. These real estate locations are primarily used for regional offices and
storage and maintenance yards.
Governmental Regulation
Our operations are subject to stringent federal, state and local laws, rules and regulations governing the protection
of the environment and human health and safety. Some of those laws, rules and regulations relate to the disposal of
hazardous substances, oilfield waste and other waste materials and restrict the types, quantities and concentrations of
those substances that can be released into the environment. Several of those laws also require removal and remedial
action and other cleanup under certain circumstances, commonly regardless of fault. Our operations routinely involve
the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Planning,
implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil,
natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling,
storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In
addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject
to special protective measures and which may expose us to additional operating costs and liabilities for accidental
discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects
of applicable laws and regulations.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource
Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability
Act, or CERCLA, the Safe Drinking Water Act, or SDWA, the federal Outer Continental Shelf Lands Act, the
Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes
that impose the requirements described above and provide for civil, criminal and administrative penalties and other
sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection
Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and
Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous
materials we use in our operations to employees, state and local government authorities and local citizens. In addition,
CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault
or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or
threatened release of hazardous substances into the environment. These persons include the current owner or operator
of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies
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that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be
joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused,
includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the
liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal
injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent change. Failure to comply with
governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party
to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating
from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent
requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory
noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not
anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have
been introduced in the United States and international regions in which we operate that are focused on restricting the
emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations
Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol,
which has been ratified in Colombia, which is a location where we provide drilling services), the Regional Greenhouse
Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the
Western United States.
The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily
through the development of greenhouse gas cap and trade programs. In addition, more than one-third of the states
already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be
regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the
Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse
gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain
greenhouse gases from motor vehicles contribute to the atmospheric concentrations of greenhouse gases and hence to
the threat of climate change.
Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse
gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of
greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for
greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting
of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration
construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to
apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first
subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases
from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require
operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are
hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into
the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment
at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers.
On June 2, 2014, the EPA issued a proposed rule to limit carbon dioxide emissions from existing electric utility
generating units. Under the EPA's current proposal, nationwide emissions of carbon dioxide from the power sector
would be cut by up to 30% from the 2005 baseline by the year 2030. The required emission reductions would vary
state-by-state, and the proposed rule provides each State flexibility in determining how the emission reductions would
be achieved.
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On January 14, 2015, the EPA announced that it plans to implement additional steps to reduce methane and VOC
emissions from the oil and gas industry. Proposed regulations are planned for the summer of 2015 and are expected to
address new and modified oil and gas sources, but may also be extended to certain existing sources located in areas
not meeting federal standards for ozone.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as
initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions
would impact our business, any such future laws and regulations could result in increased compliance costs or additional
operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding
greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition,
these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our clients
operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of
operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation
patterns as a result of climate change will have a material impact on our operations.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of
certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.
Several proposals are being considered by the EPA and other federal agencies that, if implemented, would impose
additional requirements on the practice of hydraulic fracturing. Several states are considering legislation to regulate
hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction
requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic
fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to concerns
regarding potential environmental and physical impacts, including groundwater and drinking water impacts, as well
as whether such activities may cause minor earthquakes.
The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal
Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground
injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel
and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic
fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time to
time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the
effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to
require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would
make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of
the potential environmental impacts of hydraulic fracturing. A Progress Report was issued by the EPA in May 2014;
peer review of the information provided in the Progress Report is underway. In addition, in April 2012, the EPA issued
the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to
significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise
escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural
gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured
gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must
be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from
compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September
23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for
recently constructed, modified or reconstructed storage tanks to install emission controls. On December 19, 2014, the
EPA published a final rule clarifying certain aspects of the new rules. On January 14, 2015, the EPA announced that it
plans to propose and implement new regulations to further reduce methane and VOC emissions from the oil and gas
industry. It is also possible that the EPA will propose additional amendments to its existing oil and gas regulations.
These rules may require a number of modifications to our clients’ and our own operations, including the installation
of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our
clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and
results of operations.
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The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from
hydraulic fracturing activities and plans to propose these standards by early 2015. The U.S. Department of the Interior
has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of
fracturing fluid constituents and has conducted hearings on a possible rule to reduce flaring and venting associated
with oil and gas operations on public lands.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances
that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure
of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas
production. Moreover, public debate over hydraulic fracturing and shale gas production continued to see strong public
opposition, and has resulted in delays of well permits in some areas.
On June 30, 2014, the State of New York’s Court of Appeals upheld the right of individual municipalities in the
State of New York to ban hydraulic fracturing using zoning restrictions. In December 2014, New York State Governor
Cuomo announced that hydraulic fracturing will be permanently banned in the state. Similarly situated municipalities
in other states may seek to ban or restrict resource extraction operations within their borders using zoning restrictions,
which could adversely affect the ability of resource extraction enterprises to operate in certain parts of the country, and
thus adversely affect demand for our services, which may in turn adversely affect our future results of operations.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition,
including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or
regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas,
including from the developing shale plays, incurred by our clients. The adoption of any federal, state or local laws or
the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause
a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and
well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash
flows.
In addition, our business depends on the demand for land drilling and production services from the oil and gas
industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally,
by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations
may in the future add significantly to our operating costs or those of our clients, or otherwise directly or indirectly
affect our operations.
Our wireline operations involve the use of radioactive isotopes along with other nuclear, electrical, acoustic, and
mechanical devices. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory
Commission and specified agencies of certain states. Additionally, we use high explosive charges for perforating casing
and formations, and we use various explosive cutters to assist in wellbore cleanout. Such operations are regulated by
the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses
or other approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and
approvals when necessary and believe that we are in substantial compliance with these federal requirements.
Among the services we provide, we operate as a motor carrier for the transportation of our own equipment and
therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These
regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier
operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including
testing and specification of equipment and product handling requirements. The trucking industry is subject to possible
regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating
practices or by changing the demand for common or contract carrier services or the cost of providing truckload services.
Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service
regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder
devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of
Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror
federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
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From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or
local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers.
We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Available Information
Our Website address is www.pioneeres.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports, are available free of charge through our Website as soon
as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities
and Exchange Commission. The public may read and copy these materials at the Securities and Exchange Commission’s
Public Reference Room at 100 F Street, N.E., Washington, DC 20549. For additional information on the operations of
the Securities and Exchange Commission’s Public Reference Room, please call 1-800-SEC-0330. In addition, the
Securities and Exchange Commission maintains an Internet site at www.sec.gov that contains reports, proxy and
information statements and other information regarding issuers that file electronically. We have also posted on our
Website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our
Board; Code of Business Conduct and Ethics; Corporate Governance Guidelines; and Company Contact Information.
Information on our website is not incorporated into this report or otherwise made part of this report.
Item 1A. Risk Factors
The information set forth in this Item 1A should be read in conjunction with the rest of the information included
in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
in Item 7 and the financial statements and related notes this report contains. While we attempt to identify, manage and
mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level
of risk and uncertainty will always be present. Additional risks and uncertainties that are not presently known to us or
that we currently believe are immaterial also may negatively impact our business, financial condition or operating
results.
Set forth below are various risks and uncertainties that could adversely impact our business, financial condition,
results of operations and cash flows.
Risks Relating to the Oil and Gas Industry
We derive all our revenues from companies in the oil and gas exploration and production industry, a historically
cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
As a provider of contract land drilling services and oil and gas production services, our business depends on the
level of exploration and production activity in the geographic markets where we operate. The oil and gas exploration
and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration
and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly
affect the levels of those activities. Oil and gas prices have been volatile historically and, we believe, will continue to
be so in the future. Worldwide political, economic, and military events as well as natural disasters have contributed to
oil and gas price volatility historically, and are likely to continue to do so in the future. Many factors beyond our control
affect oil and gas prices, including:
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the foreign supply of oil and gas;
the cost of exploring for, producing and delivering oil and gas;
the discovery rate of new oil and gas reserves;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
the levels of oil and gas storage;
the ability of oil and gas exploration and production companies to raise capital;
economic conditions in the United States and elsewhere;
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actions by the Organization of Petroleum Exporting Countries, which we refer to as OPEC;
political instability in the Middle East and other major oil and gas producing regions;
governmental regulations, both domestic and foreign;
domestic and foreign tax policy;
• weather conditions in the United States and elsewhere;
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the pace adopted by foreign governments for the exploration, development and production of their national
reserves;
the price of foreign imports of oil and gas; and
the overall supply and demand for oil and gas.
As a result of the recent declines in oil prices that began in late 2014 and have continued into 2015, our clients will
likely reduce spending on exploration and production projects, resulting in a decrease in demand for our services.
Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the
level of worldwide drilling and production services activities. Reduced demand for oil and natural gas generally results
in lower prices for these commodities and often impacts the economics of planned drilling projects and ongoing
production projects, resulting in the curtailment, reduction, delay or postponement of such projects for an indeterminate
period of time. When drilling and production activity and spending declines, both dayrates and utilization historically
decline as well.
In recent months, beginning in October 2014, oil prices worldwide have dropped significantly. If the current
depressed oil and natural gas prices persist for a prolonged period, or further decline, oil and gas exploration and
production companies are likely to cancel or curtail their drilling programs and lower production spending on existing
wells, thereby reducing demand for our services.
Any prolonged reduction in the overall level of exploration and development activities, whether resulting from
changes in oil and gas prices or otherwise, could materially and adversely affect us by negatively impacting:
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our revenues, cash flows and profitability;
the fair market value of our drilling rig fleet and production services equipment;
our ability to maintain or increase our borrowing capacity;
our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that
capital;
the collectability of our receivables; and
our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand
for our services.
If any of the foregoing were to occur, it could have a material adverse effect on our business and financial results.
Risks Relating to Our Business
Reduced demand for or excess capacity of drilling services or production services could adversely affect our
profitability.
Our profitability in the future will depend on many factors, but largely on pricing and utilization rates for our
drilling and production services. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs,
whether through new construction or refurbishment, could decrease the dayrates and utilization rates for our drilling
services, which would adversely affect our revenues and profitability. An increase in supply of well servicing rigs,
wireline units and coiled tubing units, without a corresponding increase in demand, could similarly decrease the pricing
and utilization rates of our production services, which would adversely affect our revenues and profitability.
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We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
We encounter substantial competition from other drilling contractors and other oilfield service companies. Our
primary market areas are highly fragmented and competitive. The fact that drilling and production services equipment
are mobile and can be moved from one market to another in response to market conditions heightens the competition
in the industry and may result in an oversupply of equipment in an area. Contract drilling companies and other oilfield
service companies compete primarily on a regional basis, and the intensity of competition may vary significantly from
region to region at any particular time. If demand for drilling or production services improves in a region where we
operate, our competitors might respond by moving in suitable rigs and production services equipment from other
regions. An influx of equipment from other regions could rapidly intensify competition, reduce profitability and make
any improvement in demand for drilling or production services short-lived.
Most drilling services contracts and production services contracts are awarded on the basis of competitive bids,
which also results in price competition. In addition to pricing and equipment availability, we believe the following
factors are also important to our clients in determining which drilling services or production services provider to select:
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the type and condition of each of the competing drilling rigs, well servicing rigs, wireline units and coiled
tubing units;
the mobility and efficiency of the equipment;
the quality of service and experience of the crews;
the safety record of the company providing the services;
the offering of ancillary services; and
the ability to provide drilling and production services equipment adaptable to, and personnel familiar
with, new technologies and drilling and production techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our
equipment, our safety record, our ability to offer ancillary services, the experience of our crews and the quality of
service we provide to differentiate us from our competitors. This strategy is less effective when lower demand for
drilling and production services intensifies price competition and makes it more difficult for us to compete on the basis
of factors other than price. In all of the markets in which we compete, an oversupply of drilling rigs or production
services equipment can cause greater price competition, which can reduce our profitability.
We face competition from many competitors with greater resources.
Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities
in these areas may enable them to:
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better withstand industry downturns;
compete more effectively on the basis of price and technology;
retain skilled personnel; and
build new rigs or acquire and refurbish existing rigs and place them into service more quickly than us in
periods of high drilling demand.
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry affect the demand for certain types of equipment. In recent
years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or
lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for
drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of
horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby
improving the productivity of exploration and production activities. This trend has resulted in significantly reduced
demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further
reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted
by the industry downturn and are typically the first rigs to become idle.
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Although we take measures to ensure that we use advanced technologies for drilling and production services
equipment, changes in technology or improvements in our competitors’ equipment could make our equipment less
competitive or require significant capital investments to keep our equipment competitive, which could have an adverse
effect on our financial condition and operating results.
We derive a significant portion of our revenue from a limited number of major clients, and our business, financial
condition and results of operations could be materially adversely affected if we are unable to maintain relationships
with these clients, or if their demand for our services decreases.
In the past, we have derived a significant portion of our revenue from a limited number of major clients. For the
years ended December 31, 2014, 2013 and 2012, our drilling and production services to our top three clients accounted
for approximately 28%, 29%, and 25%, respectively, of our revenue, and in 2014, 2013 and 2012, one client, Whiting
Petroleum Company, accounted for 12%, 13% and 10%, respectively, of our revenue. The loss of one or more of our
major clients, or their decrease in demand for our services, could have a material adverse effect on our business, financial
condition and results of operations.
Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
Our indebtedness is primarily a result of the two production services businesses that we acquired in 2008 and the
acquisition of Go-Coil in 2011. At February 1, 2015, our total debt balance of $450.1 million primarily consists of $300
million outstanding under our Senior Notes and $150 million outstanding under our Revolving Credit Facility. At
February 1, 2015, we had borrowing availability of $181.5 million under our Revolving Credit Facility.
Our current and future indebtedness could have important consequences, including:
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limiting our ability to use operating cash flow in other areas of our business because we must dedicate a
substantial portion of these funds to make principal and interest payments on our indebtedness;
• making us more vulnerable to a downturn in our business, our industry or the economy in general as a
substantial portion of our operating cash flow could be required to make principal and interest payments
on our indebtedness, making it more difficult to react to changes in our business, industry and market
conditions;
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which
we operate;
impairing our ability to make investments and obtain additional financing for working capital, capital
expenditures, acquisitions or other general corporate purposes;
limiting our ability to obtain additional financing that may be necessary to operate or expand our business;
putting us at a competitive disadvantage to competitors that have less debt; and
increasing our vulnerability to rising interest rates.
We anticipate that our cash generated by operations, proceeds from the expected sales of certain non-strategic
assets and our ability to borrow under the currently unused portion of our Revolving Credit Facility should allow us
to meet our routine financial obligations for at least the next twelve months. However, our ability to make payments
on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future.
This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions,
competition in the markets where we operate, the impact of legislative and regulatory actions on how we conduct our
business and other factors, all of which are beyond our control. If our business does not generate sufficient cash flow
from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such
as:
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refinancing or restructuring our debt;
selling assets;
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reducing or delaying acquisitions or capital investments, such as refurbishments of our rigs and related
equipment; or
seeking to raise additional capital.
However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable
terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations.
If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal
and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our Revolving
Credit Facility or other instruments governing any future indebtedness, we could be in default under the terms of our
Revolving Credit Facility or such instruments. In the event of a default, the lenders under our Revolving Credit Facility
could elect to declare all the loans made under such facility to be due and payable together with accrued and unpaid
interest and terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into
bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business,
financial condition, results of operations and prospects.
Our Revolving Credit Facility and our Senior Notes impose significant covenants on us that may affect our ability
to successfully operate our business.
Our Revolving Credit Facility limits our ability to take various actions, such as:
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limitations on the incurrence of additional indebtedness;
restrictions on investments, capital expenditures, mergers or consolidations, asset dispositions,
acquisitions, transactions with affiliates and other transactions without the lenders’ consent; and
limitation on dividends and distributions.
In addition, our Revolving Credit Facility requires us to maintain certain financial covenants and to satisfy certain
financial conditions, which may require us to reduce our debt or take some other action in order to comply with them.
The Indenture governing our Senior Notes limits our and certain of our subsidiaries’ ability to:
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pay dividends on stock;
repurchase stock or redeem subordinated debt or make other restricted payments;
incur, assume or guarantee additional indebtedness or issue disqualified stock;
create liens on the our assets;
enter into sale and leaseback transactions;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
enter into transactions with affiliates; and
enter into new lines of business.
The failure to comply with any of these covenants would cause an event of default under our Revolving Credit
Facility or our Senior Notes. An event of default, if not waived, could result in acceleration of the outstanding
indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able
to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available
on terms that are acceptable to us. These covenants could also limit our ability to obtain future financing, make needed
capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary
corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of
the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility and our Senior Notes.
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Unexpected cost overruns on our turnkey drilling jobs could adversely affect our financial position and our results
of operations.
We have historically derived a portion of our revenues from turnkey drilling contracts, and we expect turnkey
contracts will continue to represent a component of our future revenues. The occurrence of uninsured or under-insured
losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and
results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our client to a specified depth
and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as
most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such
as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not
receive progress payments and are paid by our client only after we have performed the terms of the drilling contract in
full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on
a daywork basis because we must assume most of the risks associated with drilling operations that the operator generally
assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns,
abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel.
In addition, since we are only paid by our clients after we have performed the terms of the drilling contract in full, our
liquidity can be affected by the number of turnkey contracts that we enter into.
Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey drilling
operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks,
which could have an adverse effect on our financial condition and results of operations.
Our operations involve operating hazards, which, if not insured or indemnified against, could adversely affect our
results of operations and financial condition.
Our operations are subject to the many hazards inherent in the drilling and well servicing industries, including
the risks of:
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blowouts;
cratering;
fires and explosions;
loss of well control;
collapse of the borehole;
damaged or lost drilling equipment; and
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
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suspension of operations;
damage to, or destruction of, our property and equipment and that of others;
personal injury and loss of life;
damage to producing or potentially productive oil and gas formations through which we drill; and
environmental damage.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However,
some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks
include, among other things, pollution liability in excess of relatively low limits. Depending on competitive conditions
and other factors, we attempt to obtain contractual protection against uninsured operating risks from our clients.
However, clients who provide contractual indemnification protection may not in all cases maintain adequate insurance
or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or
indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our
operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure
of a client to meet its indemnification obligations to us could materially and adversely affect our results of operations
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and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider
reasonable.
We could be adversely affected if shortages of equipment, supplies or personnel occur.
From time to time there have been shortages of drilling and production services equipment and supplies during
periods of high demand which we believe could recur. Shortages could result in increased prices for drilling and
production services equipment or supplies that we may be unable to pass on to clients. In addition, during periods of
shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our
obtaining drilling and production services equipment or supplies could limit drilling and production services operations
and jeopardize our relations with clients. In addition, shortages of drilling and production services equipment or supplies
could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse
effect on our financial condition and results of operations.
Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate
supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue
providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.
Our operations require the services of employees having the technical training and experience necessary to achieve
the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability
of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss
of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of
training and experience to adequately operate our equipment, our operations could be materially and adversely affected.
A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in
wage rates, or both. The occurrence of either of these events for a significant period of time could have a material
adverse effect on our financial condition and results of operations.
Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable
acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing
for targeted acquisitions and the potential for increased leverage or debt service requirements.
As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of
complementary assets and businesses. Our acquisition strategy in general, and our recent acquisitions in particular,
involve numerous inherent risks, including:
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unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired
businesses, including environmental liabilities;
difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
limitations on our ability to properly assess and maintain an effective internal control environment over
an acquired business in order to comply with applicable periodic reporting requirements;
potential losses of key employees and clients of the acquired businesses;
risks of entering markets in which we have limited prior experience; and
increases in our expenses and working capital requirements.
The process of integrating an acquired business may involve unforeseen costs and delays or other operational,
technical and financial difficulties that may require a disproportionate amount of management attention and financial
and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into
our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse
effect on our financial condition and results of operations.
In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we
have funded business acquisitions and the growth of our rig fleet through a combination of debt and equity financing.
We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or
convertible securities in connection with such acquisitions. Debt service requirements could represent a significant
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burden on our results of operations and financial condition and the issuance of additional equity or convertible securities
could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing on
satisfactory terms.
Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable
acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.
Our cash and cash equivalents and short term investments could be adversely affected if the financial institutions
in which we hold our cash and cash equivalents fail.
We maintain cash balances at third-party financial institutions in excess of the Federal Deposit Insurance
Corporation insurance limit. While we monitor the cash balances in the operating accounts and adjust the balances as
appropriate, we may incur a loss to the extent such loss exceeds the insurance limitation, and there could be a material
impact on our business, if one of more of the financial institutions with which we deposit fails or is subject to other
adverse conditions in the financial or credit markets and bank regulators elect to impose losses on uninsured depositors.
To date, we have experienced no loss or lack of access to our invested cash or cash equivalents. However, we can
provide no assurance that access to our invested cash and cash equivalents will not be impacted by adverse conditions
in the financial and credit markets.
Our international operations are subject to political, economic and other uncertainties not encountered in our
domestic operations.
Our international operations are subject to political, economic and other uncertainties not generally encountered
in our U.S. operations which include, among potential others:
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risks of war, terrorism, civil unrest and kidnapping of employees;
employee strikes, work stoppages, labor disputes and other slowdowns;
expropriation, confiscation or nationalization of our assets;
renegotiation or nullification of contracts;
foreign taxation, such as the tax for equality and the net-worth tax recently enacted in Colombia;
the inability to repatriate earnings or capital due to laws limiting the right and ability of foreign subsidiaries
to pay dividends and remit earnings to affiliated companies;
changing political conditions and changing laws and policies affecting trade and investment;
concentration of clients;
regional economic downturns;
the overlap of different tax structures;
the burden of complying with multiple and potentially conflicting laws;
the risks associated with the assertion of foreign sovereignty over areas in which our operations are
conducted;
the risks associated with any lack of compliance with the Foreign Corrupt Practices Act of 1977 ("FCPA")
or other anti-corruption laws;
the risks associated with fluctuating currency values, hard currency shortages and controls of foreign
currency exchange;
difficulty in collecting international accounts receivable; and
potentially longer payment cycles.
Our international operations are concentrated in Colombia and currently all of our drilling contracts are with one
client, Ecopetrol. We believe our relationship with Ecopetrol is good; however, the loss of this large client could have
an adverse effect on our business, financial condition and result of operations.
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Additionally, we may be subject to foreign governmental regulations favoring or requiring the awarding of
contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular
jurisdiction. These regulations could adversely affect our ability to compete.
We are committed to doing business in accordance with applicable anti-corruption laws and our code of conduct
and ethics. We are subject, however, to the risk that our employees and agents may take action determined to be in
violation of anti-corruption laws, including the FCPA or other similar laws. Any violation of the FCPA or other applicable
anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of
operations in certain jurisdictions and might materially adversely affect our business, results of operations or financial
condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further,
detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and
attention of our senior management.
Our operations are subject to various laws and governmental regulations that could restrict our future operations
and increase our operating costs.
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations,
including laws and regulations governing:
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environmental quality;
pollution control;
remediation of contamination;
preservation of natural resources;
transportation, and
• worker safety.
Our operations are subject to stringent federal, state and local laws, rules and regulations governing the protection
of the environment and human health and safety. Some of those laws, rules and regulations relate to the disposal of
hazardous substances, oilfield waste and other waste materials and restrict the types, quantities and concentrations of
those substances that can be released into the environment. Several of those laws also require removal and remedial
action and other cleanup under certain circumstances, commonly regardless of fault. Our operations routinely involve
the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Planning,
implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil,
natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling,
storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In
addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject
to special protective measures and which may expose us to additional operating costs and liabilities for accidental
discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects
of applicable laws and regulations.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource
Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability
Act, or CERCLA, the Safe Drinking Water Act, or SDWA, the federal Outer Continental Shelf Lands Act, the
Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes
that impose the requirements described above and provide for civil, criminal and administrative penalties and other
sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection
Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and
Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous
materials we use in our operations to employees, state and local government authorities and local citizens. In addition,
CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault
or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or
threatened release of hazardous substances into the environment. These persons include the current owner or operator
of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies
that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be
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joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused,
includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the
liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal
injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent change. Failure to comply with
governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party
to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating
from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent
requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory
noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not
anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have
been introduced in the United States and international regions in which we operate that are focused on restricting the
emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations
Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol,
which has been ratified in Colombia, which is a location where we provide drilling services), the Regional Greenhouse
Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the
Western United States.
The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily
through the development of greenhouse gas cap and trade programs. In addition, more than one-third of the states
already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be
regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the
Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse
gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain
greenhouse gases from motor vehicles contribute to the atmospheric concentrations of greenhouse gases and hence to
the threat of climate change.
Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse
gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of
greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for
greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting
of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration
construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to
apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first
subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases
from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require
operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are
hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into
the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment
at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers.
On June 2, 2014, the EPA issued a proposed rule to limit carbon dioxide emissions from existing electric utility
generating units. Under the EPA's current proposal, nationwide emissions of carbon dioxide from the power sector
would be cut by up to 30% from the 2005 baseline by the year 2030. The required emission reductions would vary
state-by-state, and the proposed rule provides each State flexibility in determining how the emission reductions would
be achieved.
On January 14, 2015, the EPA announced that it plans to implement additional steps to reduce methane and VOC
emissions from the oil and gas industry. Proposed regulations are planned for the summer of 2015 and are expected to
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address new and modified oil and gas sources, but may also be extended to certain existing sources located in areas
not meeting federal standards for ozone.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as
initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions
would impact our business, any such future laws and regulations could result in increased compliance costs or additional
operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding
greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition,
these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our clients
operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of
operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation
patterns as a result of climate change will have a material impact on our operations.
In addition, our business depends on the demand for land drilling and production services from the oil and gas
industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally,
by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations
may in the future add significantly to our operating costs or those of our clients, or otherwise directly or indirectly
affect our operations.
Our wireline operations involve the use of radioactive isotopes along with other nuclear, electrical, acoustic, and
mechanical devices. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory
Commission and specified agencies of certain states. Additionally, we use high explosive charges for perforating casing
and formations, and we use various explosive cutters to assist in wellbore cleanout. Such operations are regulated by
the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses
or other approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and
approvals when necessary and believe that we are in substantial compliance with these federal requirements.
Among the services we provide, we operate as a motor carrier for the transportation of our own equipment and
therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These
regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier
operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including
testing and specification of equipment and product handling requirements. The trucking industry is subject to possible
regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating
practices or by changing the demand for common or contract carrier services or the cost of providing truckload services.
Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service
regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder
devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of
Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror
federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or
local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers.
We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating
restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our drilling and well
servicing activities and could adversely affect our financial position, results of operations and cash flows.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of
certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.
Several proposals are being considered by the EPA and other federal agencies that, if implemented, would impose
additional requirements on the practice of hydraulic fracturing. Several states are considering legislation to regulate
hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction
requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic
30
fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to concerns
regarding potential environmental and physical impacts, including groundwater and drinking water impacts, as well
as whether such activities may cause minor earthquakes.
The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal
Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground
injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel
and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic
fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time to
time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the
effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to
require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would
make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of
the potential environmental impacts of hydraulic fracturing. A Progress Report was issued by the EPA in May 2014;
peer review of the information provided in the Progress Report is underway. In addition, in April 2012, the EPA issued
the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to
significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise
escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural
gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured
gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must
be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from
compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September
23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for
recently constructed, modified or reconstructed storage tanks to install emission controls. On December 19, 2014, the
EPA published a final rule clarifying certain aspects of the new rules. On January 14, 2015, the EPA announced that it
plans to propose and implement new regulations to further reduce methane and VOC emissions from the oil and gas
industry. It is also possible that the EPA will propose additional amendments to its existing oil and gas regulations.
These rules may require a number of modifications to our clients’ and our own operations, including the installation
of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our
clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and
results of operations.
The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from
hydraulic fracturing activities and plans to propose these standards by early 2015. The U.S. Department of the Interior
has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of
fracturing fluid constituents and has conducted hearings on a possible rule to reduce flaring and venting associated
with oil and gas operations on public lands.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances
that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure
of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas
production. Moreover, public debate over hydraulic fracturing and shale gas production continued to see strong public
opposition, and has resulted in delays of well permits in some areas.
On June 30, 2014, the State of New York’s Court of Appeals upheld the right of individual municipalities in the
State of New York to ban hydraulic fracturing using zoning restrictions. In December 2014, New York State Governor
Cuomo announced that hydraulic fracturing will be permanently banned in the state. Similarly situated municipalities
in other states may seek to ban or restrict resource extraction operations within their borders using zoning restrictions,
which could adversely affect the ability of resource extraction enterprises to operate in certain parts of the country, and
thus adversely affect demand for our services, which may in turn adversely affect our future results of operations.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition,
including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or
regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas,
31
including from the developing shale plays, incurred by our clients. The adoption of any federal, state or local laws or
the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause
a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and
well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash
flows.
Our operations are subject to the risk of cyber attacks that could have a material adverse effect on our consolidated
results of operations and consolidated financial condition.
Our information technology systems are subject to possible breaches and other threats that could cause us harm.
If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by,
among other things, loss or damage of intellectual property, proprietary information, or customer data; interruption of
business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could
have a material adverse effect on our business, financial condition and result of operations.
Risks Relating to Our Capitalization and Organizational Documents
We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation
of the price of our common stock will provide a return to our shareholders.
We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to
fund our working capital needs, reduce debt and fund growth opportunities. Any future dividends will be at the discretion
of our board of directors after taking into account various factors it deems relevant, including our financial condition
and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations
Code and other applicable laws and by our Revolving Credit Facility and Senior Notes. Our debt arrangements include
provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes
or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences
over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of
one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock.
For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or
on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption
rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the
common stock.
Provisions in our organizational documents could delay or prevent a change in control of our company even if that
change would be beneficial to our shareholders.
The existence of some provisions in our organizational documents could delay or prevent a change in control of
our company even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws
contain provisions that may make acquiring control of our company difficult, including:
•
•
•
•
provisions regulating the ability of our shareholders to nominate candidates for election as directors or
to bring matters for action at annual meetings of our shareholders;
limitations on the ability of our shareholders to call a special meeting and act by written consent;
provisions dividing our board of directors into three classes elected for staggered terms; and
the authorization given to our board of directors to issue and set the terms of preferred stock.
Item 1B. Unresolved Staff Comments
Not applicable.
32
Item 2.
Properties
For a description of our significant properties, see “Business—General” and “Business—Facilities” in Item 1 of
this report. We believe that we have sufficient properties to conduct our operations and that our significant properties
are suitable for their intended use.
Item 3. Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes
or claims related to our business activities, including workers' compensation claims and employment-related disputes.
In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material
adverse effect on our financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
33
PART II
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of
Equity Securities
As of January 29, 2015, 63,867,955 shares of our common stock were outstanding, held by 367 shareholders of
record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of
our common stock.
Our common stock trades on the New York Stock Exchange under the symbol “PES.” The following table sets
forth, for each of the periods indicated, the high and low sales prices per share:
Fiscal year ended December 31, 2014
First Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fiscal year ended December 31, 2013
First Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Low
High
$
$
7.72
12.11
13.70
4.22
7.16
6.53
6.50
7.05
12.95
17.54
18.38
13.06
9.88
8.50
7.74
8.74
The last reported sales price for our common stock on the New York Stock Exchange on January 29, 2015 was
$4.10 per share.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund
our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of
directors after taking into account various factors it deems relevant, including our financial condition and performance,
cash needs, income tax consequences and the restrictions imposed by the Texas Business Organizations Code and other
applicable laws and our Revolving Credit Facility and Senior Notes. Our debt arrangements include provisions that
generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred
stock outstanding.
We did not make any unregistered sales of equity securities during the quarter ended December 31, 2014. The
following table provides information relating to our repurchase of common shares during the quarter ended
December 31, 2014:
Period
October 1—October 31 . . . . . . .
November 1—November 30 . . .
December 1—December 31 . . . .
Total . . . . . . . . . . . . . . . . . . . . . .
Total Number of
Shares Purchased
(1)
Average Price Paid
per Share
(2)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans or Programs
104
$
— $
$
$
317
421
12.41
—
5.79
7.43
—
—
—
—
—
—
—
—
(1) The shares indicated consist of shares of our common stock tendered by employees to the Company during the
three months ended December 31, 2014, to satisfy the employees’ tax withholding obligations in connection with
the vesting of restricted stock unit awards, which we repurchased based on the fair market value on the date the
relevant transaction occurred.
(2) The calculation of the average price paid per share does not give effect to any fees, commissions or other costs
associated with the repurchase of such shares.
34
PIONEER ENERGY SERVICES
Form 10-K
RR Donnelley ProFile
TX8724AM029489
V11_6_13
baysk0at
2-Apr-2015 10:48 EST
MAR
DAL
867678 10-K 39
DTP
PDF
2.0*
1C
35Performance GraphThe following graph compares, for the periods from December 31, 2009 to December 31, 2014, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the NYSE Composite Index and a peer group index that includes five companies that provide contract drilling services and/or production services. The companies that comprise the peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Basic Energy Services, Inc., Precision Drilling Trust and Key Energy Services. The comparison assumes that $100 was invested on December 31, 2009 in our common stock, the companies that compose the NYSE Composite Index and the peer group index, and further assumes all dividends were reinvested. Item 6.
Selected Financial Data
The following information derives from our audited financial statements. This information should be reviewed
in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in
Item 7 of this report and the financial statements and related notes this report contains.
Statement of Operations Data:
Year ended December 31,
2014 (1)
2013 (2)
2012
2011
2010
(In thousands, except per share amounts)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,055,223
23,984
Income (loss) from operations. . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . .
(49,322)
Net earnings (loss) applicable to common
$ 960,186
(6,229)
(55,778)
$ 919,443
81,811
46,386
$ 715,941
57,458
20,833
$ 487,210
(18,572)
(47,558)
stockholders . . . . . . . . . . . . . . . . . . . . . . . .
Earnings (loss) per common share-basic. . . . $
Earnings (loss) per common share-diluted . . $
(38,018)
(35,932)
(0.60) $
(0.60) $
(0.58) $
(0.58) $
30,032
0.49
0.48
$
$
11,177
0.19
0.19
Other Financial Data: . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . $ 233,041
Net cash used in investing activities . . . . . . .
(151,918)
Net cash provided by (used in) financing
activities . . . . . . . . . . . . . . . . . . . . . . . . . . .
(73,584)
Capital expenditures . . . . . . . . . . . . . . . . . . . $ 188,121
$ 174,580
(150,676)
$ 199,366
(361,231)
$ 144,879
(307,484)
(20,252)
125,420
99,401
379,272
226,791
237,787
12,762
135,151
$
$
$
(33,261)
(0.62)
(0.62)
98,351
(129,481)
2014
2013
2012
2011
2010
As of December 31,
(In thousands)
Balance Sheet Data:
Working capital . . . . . . . . . . . . . . . . . . . . . . . $ 121,882
856,541
Property and equipment, net . . . . . . . . . . . . .
Long-term debt and capital lease
obligations, excluding current
installments . . . . . . . . . . . . . . . . . . . . . . . .
Shareholders’ equity . . . . . . . . . . . . . . . . . . .
Total assets. . . . . . . . . . . . . . . . . . . . . . . . . . .
455,053
495,064
1,171,589
$ 118,547
937,657
$
62,236
1,014,340
$ 129,932
793,956
$
76,142
655,508
499,666
518,433
1,229,623
518,725
547,680
1,339,776
418,728
510,445
1,172,754
279,530
396,333
841,343
(1) The statement of operations and other financial data for the year ended December 31, 2014 reflect the impact of
impairment charges on our property and equipment of $73.0 million.
(2) The statement of operations and other financial data for the year ended December 31, 2013 reflect the impact of
a goodwill impairment charge of $41.7 million and an intangible asset impairment charge of $3.1 million.
36
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Statements we make in the following discussion that express a belief, expectation or intention, as well as those
that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions.
Our actual results, performance or achievements, or industry results, could differ materially from those we express in
the following discussion as a result of a variety of factors, including general economic and business conditions and
industry trends, levels and volatility of oil and gas prices, the continued demand for drilling services or production
services in the geographic areas where we operate, decisions about exploration and development projects to be made
by oil and gas exploration and production companies, the highly competitive nature of our business, technological
advancements and trends in our industry and improvements in our competitors' equipment, the loss of one or more of
our major clients or a decrease in their demand for our services, future compliance with covenants under our senior
secured revolving credit facility and our senior notes, operating hazards inherent in our operations, the supply of
marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, the continued
availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of
qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions,
manage growth and effectively integrate acquisitions, the political, economic, regulatory and other uncertainties
encountered by our operations, and changes in, or our failure or inability to comply with, governmental regulations,
including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this
report, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note
to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect
us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on
actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak
only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-
looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that
they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking
statements and (2) use caution and common sense when considering our forward-looking statements.
Company Overview
Pioneer Energy Services Corp. (formerly called "Pioneer Drilling Company") was incorporated under the laws
of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999,
we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from
new and used components. In March 2008, we acquired two production services companies which significantly
expanded our service offerings to include well servicing and wireline services. Through these purchases, we also
acquired fishing and rental services operations, which were subsequently sold on September 17, 2014. We also acquired
a coiled tubing services business at the end of 2011, to expand our existing production services offerings. We have
continued to invest in the growth of all our core service offerings through acquisitions and organic growth.
Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent
and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing
regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services
offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining
the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our
clients.
37
Business Segments
We currently conduct our operations through two operating segments: our Drilling Services Segment and our
Production Services Segment. The following is a description of these two operating segments. Financial information
about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial
Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on
Form 10-K.
• Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse
group of oil and gas exploration and production companies through our six drilling divisions in the US and
internationally in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the
ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas
wells either through competitive bidding or through direct negotiations with existing or potential clients. Our
drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms
generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment
used, and the anticipated duration of the work to be performed.
Since October 2014, domestic and international oil prices have declined significantly to historically low price
levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our
long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0
million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric
drilling rigs to their estimated fair value.
As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs,
which includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we
expect to place as held for sale during the first quarter of 2015, after their current contracts are completed. In
January and February 2015, we sold six of these drilling rigs.
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015, as well
as our expected count at March 31, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected at March 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
56
Drilling Rigs
Held for Sale
(9)
(12)
(18)
Drilling Rig
Fleet Count
53
47
38
As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
South Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appalachia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rig Count
13
10
9
4
3
8
47
We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver
and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during
the second quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs
which we expect to sell in the near-term and considering the five new-build drilling rigs under construction,
we expect to end 2015 with a drilling fleet of 43 rigs.
As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which
are earning under term contracts. Four of our drilling rigs in Colombia are currently working under term
38
contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients
to diversify our client base in Colombia.
In response to the dramatic decline in oil prices during recent months, we have received early termination
notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will
be released upon completion of their current wells, all of which are expected to be completed by the end of
the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be
recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.
• Production Services Segment—Our Production Services Segment provides a range of services to exploration
and production companies, including well servicing, wireline services and coiled tubing services. Our
production services operations are concentrated in the major United States onshore oil and gas producing
regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.
On September 17, 2014, we completed the sale of our fishing and rental services operations. We provide our
services to a diverse group of oil and gas exploration and production companies. The primary production
services we offer are the following:
• Well Servicing. A range of services are required in order to establish production in newly-drilled wells
and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to
provide these necessary services, including the completion of newly-drilled wells, maintenance and
workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of
February 1, 2015, we operate 107 rigs with 550 horsepower and 10 rigs with 600 horsepower through 11
locations, mostly in the Gulf Coast states, as well as in Arkansas and North Dakota.
• Wireline Services. In order for oil and gas exploration and production companies to better understand the
reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir
rocks and fluids. To complete a well, the production casing must be perforated to establish a flow path
between the reservoir and the wellbore. We use our fleet of wireline units to provide these important
logging and perforating services. We provide both open and cased-hole logging services, including the
latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration
and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge
plugs. As of December 31, 2014, we have four wireline units placed as held for sale, for which we
recognized approximately $0.3 million of impairment charges to reduce their carrying values to fair value.
As of February 1, 2015, we operate a fleet of 128 wireline units through 24 locations in the Gulf Coast,
Mid-Continent and Rocky Mountain states.
• Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows
operators to continue production during service operations without shutting in the well, thereby reducing
the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled
on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts,
through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled
tubing is also used for a number of horizontal well applications such as milling temporary plugs between
frac stages. As of February 1, 2015, our coiled tubing business consists of 12 onshore and five offshore
coiled tubing units which are currently deployed through three locations in Texas and Louisiana.
Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209.
Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge
through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed
with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report
or otherwise made part of this report.
39
Market Conditions in Our Industry
Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating
expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by
current and expected oil and natural gas prices.
In recent years, generally increasing oil prices drove industry equipment utilization and revenue rates up,
particularly in oil-producing regions and certain shale regions. Even though advancements in technology have improved
the efficiency of drilling rigs, demand remained steady, particularly for drilling rigs that are able to drill horizontally.
Beginning in October 2014, domestic and international oil prices have significantly declined to historically low price
levels. If oil prices continue to decline, or if oil and natural gas prices remain at current levels for an extended period
of time, then industry equipment utilization and revenue rates will further decrease, both domestically and in Colombia.
While drilling and production services have historically trended similarly in response to fluctuations in commodity
prices, because exploration and production companies often adjust their budgets for exploratory drilling first in response
to a shift in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than
the demand for production services which is more dependent on expenditures to sustain production. We expect an
increase in pricing pressure and a highly competitive production services environment in 2015, but we believe our
high-quality equipment and services are well positioned to compete.
Our business is influenced substantially by both operating and capital expenditures by exploration and production
companies. Exploration and production spending is generally categorized as either a capital expenditure or operating
expenditure.
Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to
volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of
years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove
inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a
deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely
deferred until prices are forecasted to return to an acceptable level.
In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures
for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure
projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual
obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary
operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated
according to a simple short-term payout criterion that is far less dependent on commodity price forecasts.
Capital expenditures by exploration and production companies for the drilling of exploratory wells or new wells
in proven areas are more directly influenced by current and expected oil and natural gas prices and generally reflect
the volatility of commodity prices. In contrast, because existing oil and natural gas wells require ongoing spending to
maintain production, expenditures by exploration and production companies for the maintenance of existing wells,
which requires a range of production services, are relatively stable and more predictable.
40
PIONEER ENERGY SERVICES
Form 10-K
RR Donnelley ProFile
TX8724AM029489
V11_6_13
baysk0at
2-Apr-2015 10:48 EST
MAR
DAL
867678 10-K 45
DTP
PDF
2.0*
1C
41The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last three years are illustrated in the graphs below. As shown in the charts above, the trends in industry rig counts are influenced primarily by fluctuations in oil prices, which affect the levels of capital and operating expenditures made by our clients. Colombian oil prices have historically trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon its national oil company's long-term exploration and production programs. Technological advancements and trends in our industry also affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle.For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.Liquidity and Capital ResourcesSources of Capital ResourcesOur principal liquidity requirements have been for working capital needs, debt service, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $34.9 million as of December 31, 2014), cash generated from operations, including payments from the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”). In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of February 1, 2015, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity and/or debt offerings, as appropriate, to meet our liquidity needs.In March 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that were set to mature in 2018 (the "2010 Senior Notes"), the net proceeds from which were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. In November 2011, we issued an additional $175 million of senior
notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7
million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition
of our coiled tubing business in December 2011. In March 2014, we issued $300 million of unregistered senior notes
with a coupon interest rate of 6.125% that are due in 2022 (the “2014 Senior Notes”), the net proceeds from which,
combined with cash on hand, were used to fund the repayment of $300 million of aggregate principal amount of 2010
and 2011 Senior Notes in March and May 2014. In October 2014, we redeemed the remaining $125.0 million in
aggregate principal amount of the 2010 and 2011 Senior Notes, primarily funded by proceeds from our revolving credit
facility and through cash on hand.
Our Revolving Credit Facility, as amended on September 22, 2014, provides for a senior secured revolving credit
facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $350 million,
all of which matures in September 2019. In addition, at our request, and with the lenders' consent, the aggregate
commitments of the lenders under the Revolving Credit Facility may be increased up to an additional $100 million
provided that no default exists, all representations and warranties are true and correct, and compliance with financial
covenants as set forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. As
of February 1, 2015, we had $150 million outstanding under our Revolving Credit Facility and $18.5 million in
committed letters of credit, which resulted in borrowing availability of $181.5 million under our Revolving Credit
Facility. There are no limitations on our ability to access this borrowing capacity provided there is no default, all
representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit
Facility is maintained. Additional information regarding these covenants is provided in the Debt Requirements section
below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and
other general corporate purposes.
We currently expect that cash and cash equivalents, cash generated from operations, including payments from
the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets and available borrowings
under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.
Uses of Capital Resources
For the years ended December 31, 2014 and 2013, our primary uses of capital resources were for property and
equipment additions which consisted of the following (amounts in thousands):
Drilling Services Segment:
Routine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Discretionary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fleet additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Drilling Services Segment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production Services Segment:
Routine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discretionary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fleet additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Production Services Segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used for purchases of property and equipment. . . . . . . . . . . . . . . . . . . . . .
Net impact of accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
2013
$
43,403
24,340
34,618
102,361
22,927
21,854
28,236
73,017
175,378
12,743
188,121
$
39,276
35,569
41,679
116,524
23,053
20,092
5,687
48,832
165,356
(39,936)
125,420
Our Drilling Services Segment incurred $37.8 million and $12.3 million of costs, including accruals for capital
expenditures, on the construction of our new-build drilling rigs during the years ended December 31, 2014 and 2013,
respectively. Additionally, during the year ended December 31, 2014, we performed significant upgrade projects to
various rigs in our drilling fleet including, among others, the installation of five additional walking systems, three
42
additional automatic catwalks and one additional top drive, the upgrade of one drilling rig to higher horsepower, and
we upgraded four rigs with higher horsepower mud pumps. During the year ended December 31, 2013, we performed
significant upgrade projects to various rigs in our drilling fleet including, among others, the installation of four additional
automatic catwalks and two additional walking systems, the upgrade of two drilling rigs to higher horsepower and we
upgraded four rigs with higher horsepower mud pumps. In connection with drilling equipment upgrades and the
construction of new-build drilling rigs, we capitalized $0.7 million and $0.9 million of interest costs during the years
ended December 31, 2014 and 2013, respectively.
Our Production Services Segment acquired six wireline units, seven well servicing rigs and four coiled tubing
units during the year ended December 31, 2014. During the year ended December 31, 2013, we acquired three wireline
units and one well servicing rig.
Currently, we expect to spend approximately $165 million to $180 million on capital expenditures during 2015.
We expect the total capital expenditures for 2015 will be allocated approximately 70% for our Drilling Services Segment
and approximately 30% for our Production Services Segment. Our planned capital expenditures for the year ending
December 31, 2015 include the remaining payments for five new-build drilling rigs, nine well servicing rigs, eight
wireline units, routine capital expenditures and certain drilling equipment which was ordered in 2014 but requires long
lead-time orders. Actual capital expenditures may vary depending on the timing of commitments and payments, as well
as the level of new-build and other expansion opportunities that meet our strategic and return on capital employed
criteria. We expect to fund capital expenditures in 2015 from operating cash flow in excess of our working capital
requirements, including payments from the early terminations of drilling contracts, proceeds from sales of certain non-
strategic assets and from borrowings under our Revolving Credit Facility, if necessary.
Working Capital
Our working capital was $121.9 million at December 31, 2014, compared to $118.5 million at December 31,
2013. Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.8 at December 31,
2014 compared to 2.0 at December 31, 2013.
Our operations have historically generated cash flows sufficient to meet our requirements for debt service and
normal capital expenditures. However, our working capital requirements could increase during periods when new-build
rig construction projects are in progress or when higher percentages of our drilling contracts are turnkey contracts.
43
The changes in the components of our working capital were as follows (amounts in thousands):
Cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Receivables:
34,924
$
27,385
$
7,539
December 31,
2014
December 31,
2013
Change
Trade, net of allowance for doubtful accounts. . . . . . . . . . . . . . . . .
Unbilled receivables. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance recoveries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . .
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses:
Payroll and related employee costs . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance premiums and deductibles . . . . . . . . . . . . . . . . . . . . . . . .
Insurance claims and settlements. . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Working capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
136,161
38,002
10,900
5,138
10,998
14,117
9,909
8,925
269,074
64,305
27
3,315
40,058
12,829
10,900
5,432
10,326
147,192
115,908
49,535
8,607
2,310
13,092
13,232
—
9,311
239,380
43,718
2,847
699
30,020
10,940
8,607
12,275
11,727
120,833
20,253
(11,533)
2,293
2,828
(2,094)
885
9,909
(386)
29,694
20,587
(2,820)
2,616
10,038
1,889
2,293
(6,843)
(1,401)
26,359
121,882
$
118,547
$
3,335
The increase in cash and cash equivalents during the year ended December 31, 2014 is primarily due to $233.0
million of cash provided by operating activities, $15.1 million of proceeds from the sale of our fishing and rental services
operations and $8.4 million of proceeds from the sale of assets, partially offset by $175.4 million used for purchases
of property and equipment and $73.6 million of cash used in our financing activities.
The net increase in our total trade and unbilled receivables as of December 31, 2014 as compared to December 31,
2013 is primarily the result of the increase in consolidated revenues of $44.9 million, or 19%, for the quarter ended
December 31, 2014 as compared to the quarter ended December 31, 2013, and due to the timing of the billing and
collection cycles for long-term drilling contracts in Colombia.
The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued
expenses as of December 31, 2014 as compared to December 31, 2013 is primarily due to an increase in our insurance
company's reserve for workers' compensation claims in excess of our deductibles.
The increase in income taxes and other receivables as of December 31, 2014 as compared to December 31, 2013
is primarily due to the movement of $1.5 million in prepaid taxes associated with our Colombian operations from
noncurrent to current receivables, as we expect to utilize them in the near term, as well as a $1.4 million receivable
from the settlement of litigation in our favor.
The current portion of our long-term debt as of December 31, 2013 was primarily related to short-term financing
for insurance premiums which were repaid in 2014.
The increase in accounts payable as of December 31, 2014 as compared to December 31, 2013 is due to an
increase in our accruals for capital expenditures as of December 31, 2014 as compared to December 31, 2013, and due
to the 18% increase in our operating costs for the quarter ended December 31, 2014 as compared to the quarter ended
December 31, 2013.
44
The increase in deferred revenues as of December 31, 2014 as compared to December 31, 2013 is primarily
related to prepayments made related to ongoing drilling contracts and the deferral of early termination fees on one term
contract.
As of December 31, 2014, our consolidated balance sheet reflects assets held for sale of $9.9 million, which
represents the fair value of nine drilling rigs, four wireline units, two real estate properties and other drilling equipment.
The increase in accrued payroll and employee related costs as of December 31, 2014 as compared to December 31,
2013 is primarily due to higher accruals for our 2014 annual bonuses at above target achievement levels, as compared
to 2013 bonuses which were earned at an amount below the target level, as well as an increase due to timing of pay
periods.
The increase in insurance premiums and deductibles as of December 31, 2014 as compared to December 31,
2013 is primarily due to an increase in our accrual for workers compensation insurance costs resulting from an increase
in our estimated liability for the deductibles under these policies.
The decrease in accrued interest expense as of December 31, 2014 as compared to December 31, 2013 is primarily
due to the repayment of $425 million of our 2010 and 2011 Senior Notes in 2014 with proceeds from our Revolving
Credit Facility and our 2014 Senior Notes which incur interest at a lower rate.
The decrease in other accrued expenses as of December 31, 2014 as compared to December 31, 2013 is primarily
due to a decrease in the Colombian equity tax obligation and a decrease in property taxes due to the timing of payments,
partially offset by an increase in our sales tax accrual.
Long-term Debt and Other Contractual Obligations
The following table includes information about the amount and timing of our contractual obligations at
December 31, 2014 (amounts in thousands):
Payments Due by Period
Contractual Obligations
Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Interest on debt . . . . . . . . . . . . . . . . . . . .
Purchase commitments . . . . . . . . . . . . . .
Operating leases . . . . . . . . . . . . . . . . . . .
Incentive compensation and severance . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total
455,080
155,553
114,717
14,934
13,701
753,985
Within 1 Year
27
$
22,130
90,846
4,441
7,757
125,201
$
2 to 3 Years
53
44,254
23,871
5,991
5,944
80,113
$
$
4 to 5 Years
155,000
43,231
—
2,993
—
201,224
$
$
Beyond 5 Years
300,000
$
45,938
—
1,509
—
347,447
$
At December 31, 2014, debt obligations consist of $300 million of principal amount outstanding under our Senior
Notes, $155.0 million outstanding under our Revolving Credit Facility and $0.1 million of other debt outstanding. The
$155.0 million outstanding under our Revolving Credit Facility is due at maturity on September 22, 2019. However,
we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital
is sufficient. The $300 million principal amount outstanding under our 2014 Senior Notes will mature on March 15,
2022.
Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 2.4% interest rate
that was in effect at December 31, 2014, and (2) the outstanding balance of $155.0 million at December 31, 2014 to
be paid at maturity on September 22, 2019. Interest payment obligations on our 2014 Senior Notes are calculated based
on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year.
Purchase commitments primarily relate to components ordered for our new-build drilling rigs, purchases of other
new equipment and equipment upgrades. The total estimated cost, excluding capitalized interest, for the five new-build
drilling rigs is approximately $125 million, of which $37.2 million has already been incurred, and $59.7 million of
which is reflected in the purchase commitments table above. In addition, $42.7 million of the purchase commitments
in the table above represent obligations for well servicing rigs and other drilling equipment that were ordered during
2014, but which require long lead-time orders.
45
Operating leases consist of lease agreements for office space, operating facilities, equipment and personal property.
Incentive compensation is payable to our employees, generally contingent upon their continued employment
through the date of each respective award's payout.
Debt Requirements
The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset
dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of
credit exposure. There are no limitations on our ability to access the $350 million borrowing capacity provided there
is no default, all representations and warranties are true and correct, and compliance with financial covenants under
the Revolving Credit Facility is maintained. At December 31, 2014, we were in compliance with our financial covenants
under the Revolving Credit Facility. Our total consolidated leverage ratio was 1.8 to 1.0, our senior consolidated leverage
ratio was 0.7 to 1.0, and our interest coverage ratio was 6.7 to 1.0. The financial covenants contained in our Revolving
Credit Facility include the following:
• A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;
• A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that
cannot exceed 2.50 to 1.00;
• A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and
•
If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our
minimum asset coverage ratio cannot be less than 1.00 to 1.00.
The Revolving Credit Facility does not restrict capital expenditures as long as (a) no event of default exists under
the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital
expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the
senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00.
If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater
than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure
threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding
fiscal year up to $30 million.
At December 31, 2014, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore,
we were not subject to the capital expenditure threshold restrictions listed above.
The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence
of additional debt, investments, liens, dividends, acquisitions, prepayments of indebtedness, asset dispositions, mergers
and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily
restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including
without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to
certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency,
judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit
agreement and change of control.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets
(including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-
tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets
of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer
Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital
and other general corporate purposes.
46
In addition to the financial covenants under our Revolving Credit Facility, the Indenture governing our Senior
Notes both contain certain restrictions generally on our ability to:
•
•
•
•
•
•
•
•
•
pay dividends on stock, repurchase stock, redeem subordinated indebtedness or make other restricted
payments and investments;
incur, assume or guarantee additional indebtedness or issue preferred or disqualified stock;
create liens on our assets;
enter into sale and leaseback transactions;
sell or transfer assets;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to any other person;
enter into transactions with affiliates; and
enter into new lines of business.
If we experience a change of control (as defined in the Indenture), we will be required to make an offer to each
holder of the Senior Notes to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the
principal amount of each Senior Note, plus accrued and unpaid interest, if any to the date of repurchase. If we engage
in certain asset sales, within 365 days of such sale we will be required to use the net cash proceeds from such sale, to
the extent we do not reinvest those proceeds in our business, to make an offer to repurchase the Senior Notes at a price
equal to 100% of the principal amount of each Senior Note, plus accrued and unpaid interest to the repurchase date.
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by
our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate
our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries
do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy,
liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of
its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In
the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted
subsidiaries under the Indenture will not guarantee the Senior Notes.
Our Senior Notes are not subject to any sinking fund requirements. As of December 31, 2014, there were no
restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance
with all covenants pertaining to our Senior Notes.
47
Results of Operations
Statements of Operations Analysis—Year Ended December 31, 2014 Compared with the Year Ended
December 31, 2013
The following table provides information about our operations for the years ended December 31, 2014 and 2013
(amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
Year ended December 31,
2014
2013
Drilling Services Segment:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Services Segment margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Average number of drilling rigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utilization rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenues per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Average operating costs per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Services Segment margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . $
516,473
345,862
170,611
62.0
87%
19,602
26,348
17,644
8,704
Production Services Segment:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production Services Segment margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
538,750
340,102
198,648
Combined:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,055,223
685,964
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
369,259
Combined margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
277,081
$
$
$
$
$
$
$
$
$
528,327
351,630
176,697
68.2
84%
20,977
25,186
16,763
8,423
431,859
277,625
154,234
960,186
629,255
330,931
234,742
Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs.
Production Services Segment margin represents production services revenue less production services operating costs.
We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for
evaluating financial performance, although they are not measures of financial performance under GAAP. However,
Drilling Services Segment margin and Production Services Segment margin are common measures of operating
performance used by investors, financial analysts, rating agencies and Pioneer’s management. Drilling Services Segment
margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures
reported by other companies.
Adjusted EBITDA represents income (loss) before interest income (expense), taxes, depreciation, amortization,
loss on extinguishment of debt and impairments. We use this non-GAAP measure, together with our GAAP financial
metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial
objectives. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our
operating performance and makes it easier to compare our results with those of other companies within our industry.
Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an
indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does
not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled
measures reported by other companies.
48
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net
income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in
the following table.
Reconciliation of combined margin and Adjusted EBITDA to net loss:
Combined margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of fishing and rental services operations . . . . . . . . . . . . . . . . . .
Gain on settlement of litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
2013
(amounts in thousands)
$
369,259
(103,385)
(1,445)
10,702
5,254
(3,304)
277,081
(183,376)
(73,025)
(38,781)
(31,221)
11,304
(38,018) $
330,931
(94,183)
(767)
—
—
(1,239)
234,742
(187,918)
(54,292)
(48,310)
—
19,846
(35,932)
Our Drilling Services Segment’s revenues decreased by $11.9 million, or 2%, during 2014 as compared to 2013,
resulting primarily from a decrease in revenue days of 7%, partially offset by an increase in revenues per day of 5%,
or $1,162 per day. Our Drilling Services Segment’s operating costs decreased by $5.8 million, or 2%, during 2014 as
compared to 2013, primarily resulting from a decrease in revenue days, partially offset by higher operating costs per
day which increased by 5%, or $881 per day. Revenue days decreased primarily due to the sale of eight drilling rigs in
October 2013, some of which had been earning a standby dayrate during 2013, and due to lower utilization in Colombia
where we experienced downtime primarily due to client delays in preparing well sites during the first half of 2014.
Overall decreases in revenues and operating costs were partially offset by an increase in domestic revenues and operating
costs per day during 2014.
Our average revenues per day increased by 5% or $1,162 per day, while our average operating costs per day
increased by 5% or $881 per day, during 2014, as compared to 2013. Our average revenues and operating costs per
day increased primarily due to increased turnkey work performed during 2014 as well as higher labor costs during 2014
which are reimbursed by the client, resulting in higher average revenues and operating costs per day.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling
rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain
higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in
higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts.
During the years ended December 31, 2014 and 2013, we completed 106 and 27 turnkey contracts, respectively,
representing 6% and 3% of our total drilling revenues for each year, respectively. During 2014, we experienced an
increase in demand for turnkey programs using lower horsepower rigs to drill a series of surface holes on pad sites.
Our Production Services Segment's revenues increased by $106.9 million, or 25%, during 2014, as compared to
2013, while operating costs increased by $62.5 million, or 23%. The increases in our Production Services Segment's
revenues and operating costs are primarily a result of the increased demand for our services. The number of wireline
jobs we completed increased by 3% during 2014, as compared to 2013. The total rig hours for our well servicing fleet
increased by 12%, during 2014, as compared to 2013. Our coiled tubing utilization increased to 51% during 2014 from
47% during 2013. Increased pricing for these services also contributed to the increase in revenues, which was primarily
due to a greater mix of higher priced jobs performed in our wireline and coiled tubing businesses. The greater mix of
49
higher cost wireline and coiled tubing jobs performed also resulted in the increase in operating costs during 2014, as
compared to 2013.
Our general and administrative expense increased by approximately $9.2 million, or 10%, during 2014, as
compared to 2013, primarily due to an increase in payroll and compensation related expenses as we are projecting
higher incentive compensation based on our company's performance, as well as $1.9 million of severance costs.
In September 2014, we sold our fishing and rental services operations for total consideration of $16.1 million,
resulting in a net pretax gain of $10.7 million.
We recorded gains of $5.3 million related to settlements of litigation in our favor related to non-compete
agreements during the year ended December 31, 2014.
Our other expense of $3.3 million for 2014 is primarily related to net foreign currency loss recognized for our
Colombian operations due to the rise in the value of the U.S. dollar relative to the Colombian peso.
Our depreciation and amortization expenses decreased by $4.5 million during 2014 as compared to 2013, primarily
as a result of the sales of equipment during 2013, as well as the impairment charge to write down coiled tubing intangible
assets to fair value as of June 30, 2013.
During the year ended December 31, 2014, we recorded $71.0 million of impairment charges to reduce the
carrying values of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value. This
impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it is a reflection of
the overall downturn in our industry, drop in oil prices in the fourth quarter of 2014 and decline in our projected future
cash flows. Additionally, we recorded $2.0 million of impairment charges during the year ended December 31, 2014
to reduce the carrying values of certain other assets, which were placed as held for sale during the year, to their estimated
fair values, based on expected sales price.
During the year ended December 31, 2013, we recorded $44.8 million of impairment charges to reduce the
goodwill and intangible asset carrying values of our coiled tubing reporting unit, which were originally recorded in
connection with the acquisition of Go-Coil, L.L.C. on December 31, 2011. On June 30, 2013, we performed an
impairment analysis that led us to conclude that there would be no remaining implied value attributable to our goodwill
and accordingly, we recorded a non-cash charge of $41.7 million for the full impairment of our goodwill. In addition,
we performed an intangible asset impairment analysis on June 30, 2013, which resulted in a non-cash impairment
charge of $3.1 million to reduce our intangible asset carrying value of client relationships. These impairment charges
did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in
certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting
unit.
Our interest expense decreased by $9.5 million during 2014, as compared to 2013, primarily due to the repayment
of 2010 and 2011 Senior Notes which incurred interest at a higher rate than the 2014 Senior Notes which we issued in
March 2014.
Our loss on debt extinguishment during the year ended December 31, 2014 represents the tender and redemption
premiums and the write-off of net unamortized debt discount and debt issuance costs associated with the 2010 and 2011
Senior Notes that were redeemed in 2014.
Our effective income tax rate for the year ended December 31, 2014 was 23%, which is lower than the federal
statutory rate in the United States, primarily due to the effect of foreign currency translation, other permanent differences,
valuation allowance and the impact of state income taxes. Items such as non-deductible expenses and state income
taxes had a reverse effect on the income tax rate due to the negative pre-tax earnings.
50
Statements of Operations Analysis—Year Ended December 31, 2013 Compared with the Year Ended
December 31, 2012
The following table provides information about our operations for the years ended December 31, 2013 and 2012
(amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
Year ended December 31,
2013
2012
Drilling Services Segment:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Services Segment margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Average number of drilling rigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utilization rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenue days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average revenues per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Average operating costs per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Services Segment margin per day . . . . . . . . . . . . . . . . . . . . . . . . . . $
Production Services Segment:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production Services Segment margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Combined:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combined margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
528,327
351,630
176,697
68.2
84%
20,977
25,186
16,763
8,423
431,859
277,625
154,234
960,186
629,255
330,931
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
234,742
$
$
$
$
$
$
$
$
$
498,867
333,846
165,021
65.0
87%
20,728
24,067
16,106
7,961
420,576
252,775
167,801
919,443
586,621
332,822
249,283
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net
income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in
the following table.
Year ended December 31,
2013
2012
(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net income (loss):
Combined margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt (expense) recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (expense) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
$
330,931
(94,183)
(767)
(1,239)
234,742
(187,918)
(54,292)
(48,310)
19,846
(35,932) $
332,822
(85,603)
440
1,624
249,283
(164,717)
(1,131)
(37,049)
(16,354)
30,032
51
Our Drilling Services Segment’s revenues increased by $29.5 million, or 6%, during 2013 as compared to 2012,
resulting primarily from an increase in revenues per day of 5%, or $1,119 per day, as well as an increase in revenue
days of 1%. Our Drilling Services Segment’s operating costs increased by $17.8 million, or 5%, during 2013 as compared
to 2012, primarily resulting from higher operating costs per day which increased by 4%, or $657 per day, and partially
due to an increase in revenue days.
The increases in our Drilling Services Segment's revenues and operating costs per day were primarily due to
increased utilization in Colombia, where our revenues and costs per day are higher than our domestic drilling rigs, as
well as the deployment of all our new-build drilling rigs into areas of the U.S. which experience higher revenues and
costs per day, due to higher demand. We deployed seven of our new-build drilling rigs during the second half of 2012,
with the remaining three in the first quarter of 2013. The overall increases in revenues and operating costs were partially
offset by a slight decrease in utilization for our domestic drilling rigs, despite an increase in revenue days attributable
to the operations of our new-build drilling rigs during 2013.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling
rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain
higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in
higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts.
During the years ended December 31, 2013 and 2012, we completed 27 and 11 turnkey contracts, respectively,
representing 3% and 3% of our total drilling revenues for each year, respectively.
Our Production Services Segment's revenues increased by $11.3 million, or 3%, during 2013, as compared to
2012, while operating costs increased by $24.9 million, or 10%.
The increase in our Production Services Segment's revenues is primarily due to increased rig hours and pricing
in our well servicing operations due to higher demand for these services during 2013, as compared to 2012, while the
overall increase was partially offset by a decrease in revenues from our coiled tubing operations. The total rig hours of
our well servicing fleet increased by 7% for the year ended December 31, 2013, partly due to expansion of our fleet
during 2012 and 2013, while pricing increased by approximately 4%, as compared to 2012. Revenues from our coiled
tubing operations decreased as a result of increased competition in the coiled tubing market and our utilization decreased
from 59% in 2012 to 47% in 2013.
The increase in our Production Services Segment's operating costs is primarily due to an increase in our operating
costs for our wireline operations which incurred higher average costs per job during 2013, as compared to 2012, as
well as an increase in costs for our well servicing operations which experienced higher demand during 2013, as compared
to 2012. The number of wireline jobs we completed during 2013 was only 1% higher than the number we completed
in 2012, while our average cost per job increased by approximately 11%. The increase in our average cost per wireline
job during 2013 was primarily due to a greater mix of higher cost jobs performed during the year, as compared to 2012.
We also experienced some increase in labor costs in our Production Services Segment during 2013.
Our general and administrative expense increased by approximately $8.6 million, or 10% during 2013, as
compared to 2012, primarily due to the overall expansion of our business in recent years. During 2012, we expanded
our well servicing and wireline fleets by approximately 21% and 14%, respectively, and deployed ten new-build drilling
rigs during late 2012 and early 2013. The overall expansion of our business increased our general and administrative
expense for the year ended December 31, 2013, as compared to 2012, including an increase of $7.0 million in payroll
and compensation related expenses primarily resulting from the additional cost of personnel which we have hired over
the recent years to support our growth.
Our bad debt recovery for the year ended December 31, 2012 related to the collection of $0.5 million for an
account receivable which had been written off prior to 2011.
Our other expense of $1.2 million and other income of $1.6 million for the years ended December 31, 2013 and
2012, respectively, is primarily related to foreign currency exchange gains and losses recognized for our Colombian
operations.
52
Our depreciation and amortization expenses increased by $23.2 million during 2013 as compared to 2012, as a
result of our expansion in both our drilling and production services segments. The addition of our new-build drilling
rigs that went into service in late 2012 and early 2013 resulted in an increase of approximately $12.1 million during
the year ended December 31, 2013, as compared to 2012, while the remaining increase is primarily due to the expansion
of our well servicing, wireline and coiled tubing fleets in 2012 and 2013.
We recorded impairment charges on our property and equipment of $9.5 million for the year ended December 31,
2013 in association with our decision to place eight of our mechanical drilling rigs and other production services
equipment as held for sale. During the year ended December 31, 2012, we recorded impairment charges on our property
and equipment of $1.1 million in association with our decision to retire two mechanical drilling rigs, with most of their
components to be used as spare parts, as well as two wireline units and other wireline equipment.
During the year ended December 31, 2013, we recorded $44.8 million of impairment charges to reduce the
goodwill and intangible asset carrying values of our coiled tubing reporting unit, which were originally recorded in
connection with the acquisition of Go-Coil on December 31, 2011. On June 30, 2013, we performed an impairment
analysis that led us to conclude that there would be no remaining implied value attributable to our goodwill and
accordingly, we recorded a non-cash charge of $41.7 million for the full impairment of our goodwill. In addition, we
performed an intangible asset impairment analysis on June 30, 2013, which resulted in a non-cash impairment charge
of $3.1 million to reduce our intangible asset carrying value of client relationships. These impairment charges did not
have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain
coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
Our interest expense increased by $11.3 million for the year ended December 31, 2013, as compared to the year
ended December 31, 2012, primarily due to less capitalized interest during the year ended December 31, 2013, as
compared to 2012, associated with the capital expenditures for our new-build drilling rigs and for upgrades to our
drilling rig fleet.
Our effective income tax rate for the year ended December 31, 2013 was 36%, which is slightly higher than the
federal statutory rate in the United States, due to the impact of state income taxes, and partially offset by the effect of
foreign translation, the impact of lower effective tax rates in foreign jurisdictions and other permanent differences.
Inflation
Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and
production services increases and the availability of personnel is scarce. With the increase in demand from 2010 through
2011 and the resulting tightening of labor markets, we had a wage rate increase of approximately 10% across multiple
drilling divisions in January 2012. We experienced modest wage rate increases in our Production Services Segment
during 2013 and 2014.
Costs for equipment repairs and maintenance, upgrades and new equipment construction are also impacted by
inflationary pressures when the demand for drilling services increases. We estimate that we experienced an increase in
these costs of approximately 5% to 10% during 2012 and 2013 and a more moderate increase during 2014.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Revenue and Cost Recognition—Our Drilling Services Segment earns revenues by drilling oil and gas wells for
our clients under daywork or turnkey contracts, which usually provide for the drilling of a single well. Drilling contracts
for individual wells are usually completed in less than 60 days. We recognize revenues on daywork contracts for the
days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey contracts on the
percentage-of-completion method based on our estimate of the number of days to complete each contract. All of our
revenues are recognized net of applicable sales taxes.
53
Our management has determined that it is appropriate to use the percentage-of-completion method to recognize
revenue on our turnkey contracts. Although our turnkey contracts do not have express terms that provide us with rights
to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method
because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-
progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress
even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the
event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would
be subject to negotiations with the client and the possibility of litigation.
If a client defaults on its payment obligation to us under a turnkey contract, we would need to rely on applicable
law to enforce our lien rights, because our turnkey contracts do not expressly grant to us a security interest in the work
we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling
work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-
on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available
in applicable courts to recover the fair value of our work-in-progress under a turnkey contract.
The risks to us under a turnkey contract are substantially greater than on a contract drilled on a daywork basis.
Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed
by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns
and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations
and personnel operations.
We accrue estimated contract costs on turnkey contracts for each day of work completed based on our estimate
of the total costs to complete the contract divided by our estimate of the number of days to complete the contract.
Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations
of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating
cost overruns on our turnkey contracts could have a material adverse effect on our financial position and results of
operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract
are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was
not completed prior to the release of our financial statements.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other
equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight
line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which
a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses
are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.
With most long-term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients
if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally,
these revenues are billed and collected over the remaining term of the contract, as the rig is placed on standby rather
than fully released from the contract, and thus may go back to work at the client's decision any time before the end of
the contract. Some of our drilling contracts contain "make-whole" provisions whereby if we are able to secure additional
work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new
contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the
terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates
exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront
early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs
placed on standby or from the early termination of long-term drilling contracts are deferred and recognized as the
amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.
Our Production Services Segment earns revenues for well servicing, wireline services and coiled tubing services
pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that
include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market
rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably
assured.
54
Long-lived tangible and intangible assets—We evaluate for potential impairment of long-lived tangible and
intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate
a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an
adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include
significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. In
performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual
disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified.
For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash
flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment,
we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig
assets and for our Colombian drilling rig assets as a group. If the sum of the estimated future undiscounted net cash
flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group.
The amount of an impairment charge would be measured as the difference between the carrying amount and the fair
value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain
and require management judgment.
Since October 2014, domestic and international oil prices have declined significantly to historically low price
levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived
assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment
charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated
fair value. Additionally, we recorded $2.0 million of impairment charges during the year ended December 31, 2014 to
reduce the carrying values of certain other assets, which were placed as held for sale during the year, to their estimated
fair values, based on expected sales price.
As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which
includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as
held for sale during the first quarter of 2015, after their current contracts are completed. With the significant decline
in oil prices over the recent months, we performed impairment testing on all the mechanical and lower horsepower
drilling rigs in our fleet. In order to estimate our future undiscounted cash flows from the use and eventual disposition
of these assets, we incorporated probabilities of selling these rigs in the near term, versus working them at a significantly
reduced expected rate of utilization through the end of their remaining useful lives. Our testing indicated that the carrying
value of these assets was more than our estimated undiscounted cash flows, resulting in a total impairment of $71.0
million to reduce the carrying value of these assets to their estimated fair value of $34.0 million, which was based on
market appraisals, which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and
Disclosures. This impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it
is a reflection of the overall downturn in our industry, drop in oil prices in the fourth quarter of 2014 and decline in our
projected future cash flows. We also performed an impairment test on our drilling rigs in Colombia. Our net book value
in these rigs was $87.5 million as of December 31, 2014 and our analysis indicated that no impairment exists.
The most significant assumptions used in our analysis are the expected margin per day and utilization, as well
as the estimated proceeds upon any future sale or disposal of the rig. Although we believe the assumptions and estimates
used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the
analysis and resulting conclusions.
If the demand for our drilling services remains at current levels or declines further and any of our rigs become
idle for an extended amount of time, then our estimated cash flows may further decrease, and the probability of a near
term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.
Deferred taxes—We provide deferred taxes for the basis differences in our property and equipment between
financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards,
employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax
reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and
methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets.
For financial reporting purposes, we depreciate the various components of our drilling rigs, well servicing rigs, wireline
units and coiled tubing units over 1 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules
55
require that we depreciate drilling rigs, well servicing rigs, wireline units and coiled tubing units over 5 years. Therefore,
in the first 5 years of our ownership of a drilling rig, well servicing rig, wireline unit or coiled tubing unit, our tax
depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation
difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins
to reverse.
Accounting estimates—Material estimates that are particularly susceptible to significant changes in the near term
relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts,
our determination of depreciation and amortization expenses, our estimates of fair value for impairment evaluations,
our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and
workers’ compensation insurance, and our estimate of compensation related accruals.
We consider the recognition of revenues and costs on turnkey contracts to be critical accounting estimates. For
these types of contracts, we recognize revenues and accrue estimated costs based on our estimate of the number of days
to complete each contract and our estimate of the total costs to complete the contract. Revenues and costs during a
reporting period could be affected for contracts in progress at the end of a reporting period which have not been
completed before our financial statements for that period are released.
Our initial cost estimates for turnkey contracts do not include cost estimates for risks such as stuck drill pipe or
loss of circulation. When we encounter, during the course of our drilling operations, conditions unforeseen in the
preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss
on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire
amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract,
in our consolidated statement of operations for that reporting period. However, our actual costs could substantially
exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout
on contracts still in progress subsequent to the release of the financial statements.
We believe that our experienced management team, our knowledge of geologic formations in our areas of
operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make
reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for
cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey
contracts takes such risks into consideration. We are more likely to encounter losses on turnkey contracts in periods in
which revenue rates are lower for all types of contracts. However, during periods of reduced demand for drilling rigs,
our overall profitability on turnkey contracts has historically exceeded our profitability on daywork contracts.
We incurred a total loss of $1.2 million on 13 of the 106 turnkey contracts which were initiated and completed
during the year ended December 31, 2014. During the year ended December 31, 2013, we experienced a loss of
approximately $17,000 on one turnkey contract completed and we did not experience a loss on any of the turnkey
contracts completed during 2012. As of December 31, 2014, we had $0.8 million of unbilled receivables related to four
turnkey contracts that were in progress at year-end, which were completed prior to the issuance of these financial
statements.
We estimate an allowance for doubtful accounts based on the creditworthiness of our clients as well as general
economic conditions. We evaluate the creditworthiness of our clients based on commercial credit reports, trade
references, bank references, financial information, production information and any past experience we have with the
client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In
some instances, we require new clients to establish escrow accounts or make prepayments. We had an allowance for
doubtful accounts of $2.5 million at December 31, 2014.
Our determination of the useful lives of our depreciable assets, which directly affects our determination of
depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property
and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our
drilling, production, transportation and other equipment on a straight-line method over useful lives that we have
estimated and that range from 1 to 25 years. We record the same depreciation expense whether a drilling rig, well
servicing rig, wireline unit or coiled tubing unit is idle or working. Our estimates of the useful lives of our drilling,
56
production, transportation and other equipment are based on our more than 45 years of experience in the oilfield services
industry with similar equipment.
With the significant decline in oil prices over the recent months, we performed impairment testing on all the
mechanical and lower horsepower drilling rigs in our fleet. In order to estimate our future undiscounted cash flows
from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near
term, versus working them at a significantly reduced expected rate of utilization through the end of their remaining
useful lives. The most significant assumptions used in our analysis are the expected margin per day and utilization, as
well as the estimated proceeds upon any future sale or disposal of the rig. Although we believe the assumptions and
estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially
impact the analysis and resulting conclusions.
As of December 31, 2014, we had $87.3 million of deferred tax assets related to foreign and domestic net operating
loss and AMT credit carryforwards available to reduce future taxable income. In assessing the realizability of our
deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the
jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating
losses and we expect to apply the net operating losses against the current year taxable income and taxable income that
we have estimated in future periods.
Our accrued insurance premiums and deductibles as of December 31, 2014 include accruals for costs incurred
under the self-insurance portion of our health insurance of approximately $3.4 million and our workers’ compensation,
general liability and auto liability insurance of approximately $9.0 million. We have stop-loss coverage of $200,000
per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our
workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability
insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation
that is based on industry and our company's historical claim development data, and we accrue the costs of administrative
services associated with claims processing.
Our stock-based compensation expense includes estimates for certain of our long-term incentive compensation
plans which have performance-based award components dependent upon our performance over a set performance
period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates
which affect our stock-based compensation expense, employee related accruals and equity. The accruals are adjusted
based on actual achievement levels at the end of the pre-determined performance periods.
Recently Issued Accounting Standards
Discontinued Operations. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting
Standards Update (ASU) No. 2014-08, Discontinued Operations (Topic 360): Reporting Discontinued Operations and
Disclosures of Disposals of Components of an Entity. This update, among other things, raises the threshold for a disposal
to qualify for discontinued operations accounting and requires additional disclosures about disposals. We chose early
adoption of this guidance beginning July 1, 2014.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition
standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single
comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when
promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity
expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning
with our first quarterly filing in 2017. We are currently evaluating the potential impact of this guidance, but at this time,
do not expect that the adoption of this new standard will have a material effect on our financial position or results of
operations.
57
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
We are subject to interest rate market risk on our variable rate debt. As of December 31, 2014, we had $155.0
million outstanding under our Revolving Credit Facility, which is our only variable rate debt. The impact of a hypothetical
1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or
decrease, respectively, in interest expense of approximately $1.6 million, and a corresponding increase or decrease,
respectively, in net income of approximately $1.0 million during the year ended December 31, 2014. This potential
increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an
immediate across-the-board interest rate increase or decrease as of January 1, 2014.
Foreign Currency Risk
While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter
into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates
and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement
accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected
by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative
financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso
currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses,
profit, and assets and liabilities in our consolidated financial statements.
The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in
foreign currency losses of $5.8 million for the year ended December 31, 2014.
58
Item 8.
Financial Statements and Supplementary Data
PIONEER ENERGY SERVICES CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013 . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012. . . . . . . . .
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2014, 2013 and 2012.
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
60
62
63
64
65
66
59
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer Energy Services Corp.:
We have audited the accompanying consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries
as of December 31, 2014 and 2013, and the related consolidated statements of operations, shareholders’ equity, and
cash flows for each of the years in the three-year period ended December 31, 2014. These consolidated financial
statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Pioneer Energy Services Corp. and subsidiaries as of December 31, 2014 and 2013, and the results
of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, in
conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 2014,
based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated February 17, 2015 expressed an unqualified
opinion on the effectiveness of the Company’s internal control over financial reporting.
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting
for discontinued operations in 2014 due to the adoption of Accounting Standards Update No. 2014-08, Reporting
Discontinued Operations and Disclosures of Disposals of Components of an Entity.
/s/ KPMG LLP
San Antonio, Texas
February 17, 2015
60
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer Energy Services Corp.:
We have audited Pioneer Energy Services Corp.'s internal control over financial reporting as of December 31,
2014, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Energy Services Corp.’s management is
responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit
also included performing such other procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, Pioneer Energy Services Corp. maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework
(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries as of December 31,
2014 and 2013, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of
the years in the three-year period ended December 31, 2014, and our report dated February 17, 2015 expressed an
unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 17, 2015
61
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
2014
December 31,
2013
(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Receivables:
34,924
$
27,385
136,161
Trade, net of allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . .
38,002
Unbilled receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,900
Insurance recoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,138
Income taxes and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,998
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14,117
Inventory. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,909
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,925
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
269,074
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,702,273
Property and equipment, at cost. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
845,732
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
856,541
Net property and equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,223
Intangible assets, net of accumulated amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,753
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,998
Total assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,171,589
115,908
49,535
8,607
2,310
13,092
13,232
—
9,311
239,380
1,724,124
786,467
937,657
32,194
1,156
19,236
$ 1,229,623
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Current portion of long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses:
$
64,305
27
3,315
Payroll and related employee costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance premiums and deductibles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance claims and settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies (Note 12)
Shareholders’ equity:
40,058
12,829
10,900
5,432
10,326
147,192
455,053
69,578
4,702
676,525
Preferred stock, 10,000,000 shares authorized; none issued and outstanding . . .
Common stock $.10 par value; 100,000,000 shares authorized; 63,820,126 and
62,534,636 shares outstanding at December 31, 2014 and 2013, respectively.
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock, at cost; 317,103 and 219,304 shares at December 31, 2014 and
(3,030)
2013, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19,223
Accumulated earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
495,064
Total shareholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and shareholders’ equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,171,589
6,414
472,457
—
See accompanying notes to consolidated financial statements.
62
43,718
2,847
699
30,020
10,940
8,607
12,275
11,727
120,833
499,666
84,636
6,055
711,190
—
6,275
456,812
(1,895)
57,241
518,433
$ 1,229,623
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
2014
2013
2012
(in thousands, except per share data)
$
516,473
538,750
1,055,223
$
528,327
431,859
960,186
498,867
420,576
919,443
Revenues:
Drilling services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Production services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs and expenses: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense (recovery) . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of fishing and rental services operations . . . . .
Gain on litigation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (expense) income:
Interest expense, net of interest capitalized. . . . . . . . . . . . . .
Loss on extinguishment of debt. . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . .
Income tax (expense) benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . .
345,862
340,102
183,376
103,385
1,445
73,025
(10,702)
(5,254)
1,031,239
23,984
(38,781)
(31,221)
(3,304)
(73,306)
(49,322)
11,304
351,630
277,625
187,918
94,183
767
54,292
—
—
966,415
(6,229)
(48,310)
—
(1,239)
(49,549)
(55,778)
19,846
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(38,018) $
(35,932) $
Income (loss) per common share—Basic . . . . . . . . . . . . . . . . . . . $
(0.60) $
(0.58) $
Income (loss) per common share—Diluted . . . . . . . . . . . . . . . . . $
(0.60) $
(0.58) $
Weighted average number of shares outstanding—Basic. . . . . . .
Weighted average number of shares outstanding—Diluted . . . . .
63,161
63,161
62,213
62,213
See accompanying notes to consolidated financial statements.
63
333,846
252,775
164,717
85,603
(440)
1,131
—
—
837,632
81,811
(37,049)
—
1,624
(35,425)
46,386
(16,354)
30,032
0.49
0.48
61,780
62,762
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Shares
Amount
Common
Treasury Common
Treasury
Additional
Paid In
Capital
Accumulated
Earnings
Total
Shareholders'
Equity
(In thousands)
Balance as of December 31, 2011 . . .
61,877
(95) $ 6,188
$
(904) $ 442,020
$
63,141
$
510,445
Net income . . . . . . . . . . . . . . . . . . . . .
Exercise of options and related
income tax effect . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . .
Income tax effect of stock option
forfeitures and expirations . . . . . . .
Issuance of restricted stock . . . . . . . .
Stock-based compensation expense. .
—
172
—
—
117
—
—
—
(40)
—
—
—
—
17
—
—
12
—
—
—
(360)
—
—
—
—
676
—
(449)
(12)
7,319
30,032
30,032
—
—
—
—
—
693
(360)
(449)
—
7,319
Balance as of December 31, 2012 . . .
62,166
(135) $ 6,217
$ (1,264) $ 449,554
$
93,173
$
547,680
Net loss. . . . . . . . . . . . . . . . . . . . . . . .
Exercise of options and related
income tax effect . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . .
Income tax effect of restricted stock
vesting . . . . . . . . . . . . . . . . . . . . . .
Income tax effect of stock option
forfeitures and expirations . . . . . . .
Issuance of restricted stock . . . . . . . .
Stock-based compensation expense. .
—
271
—
—
—
316
—
—
—
(85)
—
—
—
—
—
27
—
—
—
31
—
—
—
(631)
—
—
—
—
—
(35,932)
(35,932)
1,239
—
(265)
(56)
(31)
6,371
—
—
—
—
—
—
1,266
(631)
(265)
(56)
—
6,371
Balance as of December 31, 2013 . . .
62,753
(220) $ 6,275
$ (1,895) $ 456,812
$
57,241
$
518,433
Net loss. . . . . . . . . . . . . . . . . . . . . . . .
Exercise of options and related
income tax effect . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . .
Income tax effect of stock option
forfeitures and expirations . . . . . . .
Issuance of restricted stock . . . . . . . .
Stock-based compensation expense. .
—
929
—
—
455
—
—
—
(97)
—
—
—
—
93
—
—
46
—
—
—
(1,135)
—
—
—
—
(38,018)
(38,018)
8,275
—
(201)
(46)
7,617
—
—
—
—
—
8,368
(1,135)
(201)
—
7,617
Balance as of December 31, 2014 . . .
64,137
(317) $ 6,414
$ (3,030) $ 472,457
$
19,223
$
495,064
See accompanying notes to consolidated financial statements.
64
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
2014
Year ended December 31,
2013
(in thousands)
2012
(38,018) $
(35,932) $
30,032
Cash flows from operating activities:
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . .
Write-off of obsolete inventory . . . . . . . . . . . . . . . . . . . . . . .
Gain on dispositions of property and equipment . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . . .
Amortization of debt issuance costs, discount and premium .
Gain on sale of fishing and rental services operations . . . . . .
Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . .
Impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other long-term assets . . . . . . . . . . . . . . . . . . . . . .
Change in other long-term liabilities . . . . . . . . . . . . . . . . . . .
Changes in current assets and liabilities:
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
Purchases of property and equipment . . . . . . . . . . . . . . . . . .
Proceeds from sale of fishing and rental services operations.
Proceeds from sale of property and equipment . . . . . . . . . . .
Proceeds from insurance recoveries . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Debt repayments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of debt . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tender premium costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from exercise of options . . . . . . . . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) financing activities . . . . . . . . . . .
183,376
1,445
331
(1,729)
7,617
2,669
(10,702)
31,221
73,025
(14,761)
2,958
(1,352)
(11,993)
(1,068)
(55)
7,037
2,616
424
233,041
(175,378)
15,090
8,370
—
(151,918)
(490,025)
440,000
(9,239)
(21,553)
8,368
(1,135)
(73,584)
Net increase (decrease) in cash and cash equivalents. . . . . . . . . . . . . .
Beginning cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7,539
27,385
34,924
Supplementary disclosure:
Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income tax paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
43,690
5,012
Noncash investing and financing activity:
Change in capital expenditure accruals . . . . . . . . . . . . . . . . . $
12,743
$
$
$
$
See accompanying notes to consolidated financial statements.
65
187,918
801
152
(1,421)
6,371
3,095
—
—
54,292
(22,125)
(5,741)
(1,928)
(16,168)
(1,273)
3,729
(166)
(3,181)
6,157
174,580
164,717
76
—
(1,199)
7,319
2,985
—
—
1,131
13,303
(3,865)
(1,173)
(12,807)
(927)
(1,266)
2,431
(86)
(1,305)
199,366
(165,356)
—
13,836
844
(150,676)
(364,324)
—
3,093
—
(361,231)
(60,874)
40,000
(13)
—
1,266
(631)
(20,252)
3,652
23,733
27,385
46,274
3,154
$
$
$
(874)
100,000
(58)
—
693
(360)
99,401
(62,464)
86,197
23,733
44,317
731
(39,936) $
14,948
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Business
Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent
and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing
regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services
offshore in the Gulf of Mexico.
Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration
and production companies through our six drilling divisions in the US and internationally in Colombia. In addition to
our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.
We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct
negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a
daywork or turnkey basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling
conditions, the type of equipment used, and the anticipated duration of the work to be performed.
Since October 2014, domestic and international oil prices have declined significantly to historically low price
levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived
assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment
charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated
fair value.
Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically
the first rigs to become idle. As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower
electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end and 15
rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts are completed.
In January and February 2015, we sold six of these drilling rigs. (See Note 14, Subsequent Events.)
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
Drilling Rigs
Held for Sale
(9)
(12)
Drilling Rig
Fleet Count
53
47
As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
South Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rig Count
13
10
9
4
3
8
47
We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and
begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second
quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs which we expect to sell
in the near-term and considering the five new-build drilling rigs under construction, we expect to end 2015 with a
drilling fleet of 43 rigs.
66
As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which are
earning under term contracts. Four of our drilling rigs in Colombia are currently working under term contracts that
extend through mid-2015 and we are actively marketing our other four rigs to multiple clients to diversify our client
base in Colombia.
In response to the dramatic decline in oil prices during recent months, we have received early termination notices
for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon
completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting
in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining
term of the contracts, $0.3 million of which was recognized in 2014.
Our Production Services Segment provides a range of services to exploration and production companies, including
well servicing, wireline services and coiled tubing services. Our production services operations are concentrated in the
major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the
Gulf Coast, both onshore and offshore. As of February 1, 2015, we have a fleet of 117 well servicing rigs consisting
of 107 rigs with 550 horsepower and 10 rigs with 600 horsepower, all of which are currently operating or are being
actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 128 wireline units
and 17 coiled tubing units. On September 17, 2014, we completed the disposition of our fishing and rental services
operations.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of Pioneer Energy Services Corp. and
our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The
accompanying consolidated financial statements have been prepared in accordance with accounting principles generally
accepted in the United States of America.
In preparing the accompanying consolidated financial statements, we make various estimates and assumptions
that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses
we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ
significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near
term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful
accounts, our determination of depreciation and amortization expenses, our estimates of fair value for impairment
evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our
health and workers’ compensation insurance, and our estimate of compensation related accruals.
In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred
after December 31, 2014, through the filing of this Form 10-K, for inclusion as necessary.
Drilling Contracts
Our drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms
generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used,
and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a
single well and typically permit the client to terminate on short notice. We enter into longer-term drilling contracts for
our newly constructed rigs and/or during periods of high rig demand. Currently, we have contracts with original terms
of six months to four years in duration.
67
As of February 1, 2015, we have 29 drilling rigs earning under term contracts, which if not renewed prior to the
end of their terms, will expire as follows:
United States . . . . . . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Term Contract Expiration by Period
Total
Term Contracts
25
4
29
Within
6 Months
6 Months
to 1 Year
13
4
17
6
—
6
1 Year to
18 Months
4
—
4
18 Months
to 2 Years
2
—
2
In response to the dramatic decline in oil prices during recent months, we have received early termination notices
for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon
completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting
in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining
term of the contracts, $0.3 million of which was recognized in 2014.
Foreign Currencies
Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and
liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect
at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from
remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are
included in other income or expense.
Revenue and Cost Recognition
Drilling Services—Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients
under daywork or turnkey contracts, which usually provide for the drilling of a single well. Drilling contracts for
individual wells are usually completed in less than 60 days. We recognize revenues on daywork contracts for the days
completed based on the dayrate each contract specifies. We recognize revenues from our turnkey contracts on the
percentage-of-completion method based on our estimate of the number of days to complete each contract. All of our
revenues are recognized net of applicable sales taxes.
Our management has determined that it is appropriate to use the percentage-of-completion method to recognize
revenue on our turnkey contracts. Although our turnkey contracts do not have express terms that provide us with rights
to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method
because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-
progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress
even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the
event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would
be subject to negotiations with the client and the possibility of litigation.
If a client defaults on its payment obligation to us under a turnkey contract, we would need to rely on applicable
law to enforce our lien rights, because our turnkey contracts do not expressly grant to us a security interest in the work
we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling
work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-
on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available
in applicable courts to recover the fair value of our work-in-progress under a turnkey contract.
The risks to us under a turnkey contract are substantially greater than on a contract drilled on a daywork basis.
Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed
by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns
and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations
and personnel operations.
68
We accrue estimated contract costs on turnkey contracts for each day of work completed based on our estimate
of the total costs to complete the contract divided by our estimate of the number of days to complete the contract.
Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations
of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating
cost overruns on our turnkey contracts could have a material adverse effect on our financial position and results of
operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract
are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was
not completed prior to the release of our financial statements.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other
equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight
line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which
a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses
are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.
With most long-term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients
if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally,
these revenues are billed and collected over the remaining term of the contract, as the rig is placed on standby rather
than fully released from the contract, and thus may go back to work at the client's decision any time before the end of
the contract. Some of our drilling contracts contain "make-whole" provisions whereby if we are able to secure additional
work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new
contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the
terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates
exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront
early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs
placed on standby or from the early termination of long-term drilling contracts are deferred and recognized as the
amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.
The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-
term portions of deferred mobilization costs for certain drilling contracts. The liabilities “deferred revenues” and “other
long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling
contracts and amounts collected on contracts in excess of revenues recognized, including amounts collected for early
terminations of long-term drilling contracts. As of December 31, 2014 we had $3.3 million and $1.2 million of current
deferred revenues and costs, respectively. Our deferred mobilization costs and revenues primarily relate to prepayments
of long-term drilling contracts in the US. Amortization of deferred mobilization revenues was $4.6 million, $5.3 million
and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Production Services—Our Production Services Segment earns revenues for well servicing, wireline services and
coiled tubing services pursuant to master services agreements based on purchase orders, contracts or other arrangements
with the client that include fixed or determinable prices. Production services jobs are generally short-term and are
charged at current market rates. Production service revenue is recognized when the service has been rendered and
collectability is reasonably assured.
Concentration of Clients—We derive a significant portion of our revenue from a limited number of major clients.
For the years ended December 31, 2014, 2013 and 2012, our drilling and production services to our top three clients
accounted for approximately 28%, 29%, and 25%, respectively, of our revenue, and in 2014, 2013 and 2012, one client,
Whiting Petroleum Company, accounted for 12%, 13% and 10%, respectively, of our revenue.
Cash and Cash Equivalents
For purposes of the consolidated statements of cash flows, we consider all highly liquid debt instruments purchased
with a maturity of three months or less to be cash equivalents. We had cash equivalents of $2.6 million and $0.7 million
at December 31, 2014 and 2013, respectively, which consisted of investments in corporate and government money
market accounts.
69
Trade Accounts Receivable
We record trade accounts receivable at the amount we invoice our clients. These accounts do not bear interest.
The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts
receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our clients and
general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance
for doubtful accounts.
We review our allowance for doubtful accounts on a monthly basis. Our typical drilling contract provides for
payment of invoices in 30 days. We generally do not extend payment terms beyond 30 days and have not extended
payment terms beyond 90 days for any of our contracts in the last three fiscal years. Our production services terms
generally provide for payment of invoices in 30 days. Balances more than 90 days past due are reviewed individually
for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means
of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit
exposure related to our clients.
The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase in allowance charged to expense . . . . . . . . . . . . . . . . . . . . . . .
Accounts charged against the allowance. . . . . . . . . . . . . . . . . . . . . . . . .
Balance at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,356
1,445
(254)
2,547
$
$
1,044
801
(489)
1,356
$
$
994
76
(26)
1,044
Year ended December 31,
2014
2013
2012
Unbilled Accounts Receivable
The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling
contracts and production services completed but not yet invoiced. We typically invoice our clients at 15-day intervals
during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey drilling
contracts are invoiced upon completion of the contract.
Our unbilled receivables totaled $38.0 million at December 31, 2014, of which $0.8 million related to turnkey
drilling contract revenues, $32.8 million represented revenue recognized but not yet billed on daywork drilling contracts
in progress at December 31, 2014 and $4.4 million related to unbilled receivables for our Production Services Segment.
At December 31, 2013, our unbilled receivables totaled $49.5 million, of which $45.4 million represented revenue
recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 million related
to unbilled receivables for our Production Services Segment.
Inventories
Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services
Segment’s operations in Colombia and supplies held for use by our Production Services Segment’s operations.
Inventories are valued at the lower of cost (first in, first out or actual) or market value.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets include items such as insurance, rent deposits and fees. We routinely
expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses and
other current assets also include the current portion of prepaid taxes in Colombia which are creditable against future
income taxes and the current portion of deferred mobilization costs for certain drilling contracts that are recognized on
a straight-line basis over the contract term.
70
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets
over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense
whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We capitalize
expenditures for renewals and betterments to the appropriate property and equipment accounts.
Intangible Assets
Our intangible assets consist of the following components as of December 31, 2014 and 2013 (amounts in
thousands):
Cost:
December 31,
2014
2013
Client relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Non-compete agreements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63,168
1,355
Accumulated amortization:
Client relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-compete agreements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(39,256)
(1,044)
24,223
$
$
$
63,168
1,355
(31,584)
(745)
32,194
Substantially all of our intangible assets were recorded in connection with the acquisitions of production services
businesses and are subject to amortization. The cost of our client relationships are amortized using the straight-line
method over their respective estimated economic useful lives which range from three to nine years. Amortization
expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements
which range from three to seven years. Amortization expense was $8.0 million, $8.5 million and $8.7 million for the
years ended December 31, 2014, 2013 and 2012, respectively. Amortization expense is estimated to be approximately
$7.9 million, $5.1 million, $3.8 million, $3.8 million and $3.6 million for the years ending December 31, 2015, 2016,
2017, 2018 and 2019, respectively. Actual amortization amounts may be different due to future acquisitions,
impairments, changes in amortization periods, or other factors.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when
indicators of impairment are present. Circumstances that could indicate a potential impairment include significant
adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator.
More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization
rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate
the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets
grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an
impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing,
wireline and coiled tubing). If the sum of the estimated future undiscounted net cash flows is less than the carrying
amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment
charge would be measured as the difference between the carrying amount and the fair value of these assets. The
assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management
judgment.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased
competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of
which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an
impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. Our analysis resulted in a non-
cash impairment charge of $3.1 million which we recognized during 2013 to reduce our intangible asset carrying value
of client relationships. This impairment charge did not have an impact on our liquidity or debt covenants; however, it
was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our
projected cash flows for the coiled tubing reporting unit. Due to continued increases in competition in certain coiled
tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-
71
lived tangible and intangible assets as of December 31, 2013, at which time we determined that the sum of the estimated
future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount
and concluded that no impairment existed.
The most significant inputs used in our impairment analyses include the projected utilization and pricing of our
coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements
and Disclosures. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate,
different assumptions and estimates could materially impact the analysis and resulting conclusions. If we fail to meet
the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable
changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the
projected utilization and pricing of our coiled tubing services, then we may incur a future impairment. Our coiled tubing
services' operating results for the year ended December 31, 2014 exceeded our projections.
Our impairment analyses did not result in any impairment charges to our coiled tubing tangible long-lived assets,
substantially all of which relates to our coiled tubing units and equipment. As discussed further below, we also recorded
a non-cash impairment charge during 2013 to reduce the carrying value of goodwill to zero.
Goodwill
In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million
of goodwill at December 31, 2011. Due to several significant adverse factors affecting our coiled tubing services
reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower
than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing
reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We used an income approach
to estimate the fair value of our coiled tubing services reporting unit and determined that there was no remaining implied
fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million during
2013 to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our
liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets
where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis included the projected utilization and pricing of our
coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted
cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value
Measurements and Disclosures. We assumed a 13% discount rate to estimate the fair value of the coiled tubing services
reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment
charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have
resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively.
Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different
assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in
estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and
require management judgment.
Other Long-Term Assets
Other long-term assets consist of noncurrent prepaid taxes in Colombia which are creditable against future income
taxes, debt issuance costs net of amortization, cash deposits related to the deductibles on our workers’ compensation
insurance policies and the long-term portion of deferred mobilization costs.
Other Current Liabilities
Our other accrued expenses include accruals for items such as property tax, sales tax, professional and other fees.
We routinely expense these items in the normal course of business over the periods these expenses benefit.
72
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of liabilities associated with our long-term
compensation plans, deferred mobilization revenues, and other deferred liabilities.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common
stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited
or charged to additional paid in capital using the average cost method.
Stock-based Compensation
We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the
fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. For our awards with
graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately
vesting portion of the award as if the award was, in substance, multiple awards.
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally
for the excess of the fair market value of our stock on the date of exercise over the exercise price of the options. In
accordance with ASC Topic 718, we reported all excess tax benefits resulting from the exercise of stock options as
financing cash flows in our consolidated statement of cash flows.
Income Taxes
We follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax
assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying
amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities
by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle
those temporary differences. The effect of a change in tax rates on deferred tax assets and liabilities is reflected in
income in the period during which the change occurs. A recent change in Colombia tax rates is described in more detail
in Note 6, Income Taxes.
Recently Issued Accounting Standards
Discontinued Operations. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting
Standards Update (ASU) No. 2014-08, Discontinued Operations (Topic 360): Reporting Discontinued Operations and
Disclosures of Disposals of Components of an Entity. This update, among other things, raises the threshold for a disposal
to qualify for discontinued operations accounting and requires additional disclosures about disposals. We chose early
adoption of this guidance beginning July 1, 2014.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition
standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single
comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when
promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity
expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning
with our first quarterly filing in 2017. We are currently evaluating the potential impact of this guidance, but at this time,
do not expect that the adoption of this new standard will have a material effect on our financial position or results of
operations.
Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current
year’s presentation.
73
2.
Sale of Fishing and Rental Services Operations
On September 17, 2014, we entered into an asset sales agreement with Basic Energy Services L.P. ("Basic") for
the sale of our fishing and rental services (“F&R”) operations for total consideration of $16.1 million, subject to certain
adjustments. The sales price consisted of $15.1 million of cash received at closing and $1.0 million to be held in escrow
for a period of 180 days for potential claims due to Basic. Under the terms of the sales agreement, Basic purchased two
real estate locations and all F&R tools and equipment for which we had a total net book value of $4.3 million at the
date of sale. Basic also purchased certain other assets and assumed certain liabilities related to our F&R operations. In
addition, Basic offered employment to the F&R employees and we agreed to provide transition services to Basic after
the close of the transaction. We recognized a $10.7 million gain on the sale of our F&R operations, net of costs directly
attributable to the sale. Net of income taxes, the gain was $6.6 million. Cash proceeds from the sale were used to repay
long-term debt obligations.
For the nine months ended September 30, 2014, F&R operations represented approximately 1% of our
consolidated revenues and approximately 1% of our consolidated pretax income. Total assets for F&R at the date of
sale represented less than 1% of our total assets as of September 30, 2014. The sale of the F&R operations does not
represent a strategic shift for our company and will not have a significant effect on our operating results. Therefore,
the F&R operations does not represent discontinued operations based on the criteria of ASU No. 2014-08, "Discontinued
Operations."
Balance sheet information for the F&R operations is as follows (amounts in thousands):
Current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Property and equipment, less accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
December 31, 2013
1,877
6,132
8,009
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Long term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
919
1,452
2,371
Statement of operations information for the F&R operations is as follows (amounts in thousands):
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F&R margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7,828
5,097
2,731
$
$
12,459
8,000
4,459
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . $
(162) $
242
$
$
$
13,327
8,146
5,181
1,177
Year ended December 31,
2014
2013
2012
3.
Property and Equipment
Our total capital expenditures of $188.1 million during 2014 primarily relate to our five new-build drilling rigs
which began construction during 2014, as well as unit additions to our production services fleets. As of December 31,
2014 and 2013, capital expenditures incurred for property and equipment not yet placed in service was $82.7 million
and $19.4 million, respectively. During the years ended December 31, 2014, 2013 and 2012, we capitalized $0.7 million,
$0.9 million and $10.2 million, respectively, of interest costs incurred primarily during the construction periods of new-
build drilling rigs and other drilling equipment.
74
As of December 31, 2014 and 2013, the estimated useful lives and costs of our asset classes are as follows:
December 31, 2014
December 31, 2013
Drilling rigs and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Well servicing rigs and equipment . . . . . . . . . . . . . . . . . . . . . . . .
Wireline units and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coiled tubing units and equipment . . . . . . . . . . . . . . . . . . . . . . . .
Fishing and rental tools and equipment . . . . . . . . . . . . . . . . . . . .
Vehicles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buildings and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lives
2 - 25
3 - 20
2 - 10
1 - 7
3 - 15
3 - 15
1 - 10
2 - 40
—
$
$
$
Cost (amounts in thousands)
1,168,404
232,771
146,748
60,389
—
55,014
11,521
25,007
2,419
1,702,273
1,223,621
205,409
128,800
47,761
17,264
65,796
9,274
23,931
2,268
1,724,124
$
We recorded gains on disposition of our property and equipment of $1.7 million, $1.4 million and $1.2 million
during the years ended December 31, 2014, 2013 and 2012, respectively, in our drilling and production services costs
and expenses. In February 2014, we completed the sale of our trucking assets for a sales price of $4.5 million which
included a fleet of 40 trucks and related transportation equipment that we used to transport our drilling rigs to and from
drilling sites. By owning our own trucks, we were historically able to reduce the overall cost and downtime between
rig moves. However, with the industry trend toward pad drilling, we upgraded a number of our drilling rigs in recent
years to equip them with walking or skidding systems, which enable the drilling rigs to move between wells in pad
drilling, and thus operating our own trucking fleet became less beneficial. The net book value of the trucking assets
sold was $3.4 million, for which we recognized a total gain of $1.1 million. During the second quarter of 2013, we sold
two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated
gain of approximately $0.8 million. Additionally, we disposed of a total of four wireline units during 2013, as well as
other wireline equipment.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when
indicators of impairment are present. Circumstances that could indicate a potential impairment include significant
adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator.
More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization
rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate
the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets
grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an
impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing,
wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate
future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as
a group. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset
group, then we would determine the fair value of the asset group. The amount of an impairment charge would be
measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in
the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Since October 2014, domestic and international oil prices have declined significantly to historically low price
levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived
assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment
charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated
fair value.
In recent years, and especially during the recent downturn, demand has significantly decreased for certain
mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due
to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling
enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site
location, thereby improving the productivity of exploration and production activities. This trend has resulted in
75
significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells,
and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the
most impacted by the industry downturn and are typically the first rigs to become idle.
As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which
includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as
held for sale during the first quarter of 2015, after their current contracts are completed. (See Note 14, Subsequent
Events.) With the significant decline in oil prices over the recent months, we performed impairment testing on all the
mechanical and lower horsepower drilling rigs in our fleet. In order to estimate our future undiscounted cash flows
from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near
term, versus working them at a significantly reduced expected rate of utilization through the end of their remaining
useful lives. Our testing indicated that the carrying value of these assets was more than our estimated undiscounted
cash flows, resulting in a total impairment of $71.0 million to reduce the carrying value of these assets to their estimated
fair value of $34.0 million, which was based on market appraisals, which are considered Level 3 inputs as defined by
ASC Topic 820, Fair Value Measurements and Disclosures.This impairment charge is not expected to have an impact
on our liquidity or debt covenants; however, it is a reflection of the overall downturn in our industry, drop in oil prices
in the fourth quarter of 2014 and decline in our projected future cash flows. We also performed an impairment test on
our drilling rigs in Colombia. Our net book value in these rigs was $87.5 million as of December 31, 2014 and our
analysis indicated that no impairment exists.
The most significant assumptions used in our analysis are the expected margin per day and utilization, as well
as the estimated proceeds upon any future sale or disposal of the rig. Although we believe the assumptions and estimates
used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the
analysis and resulting conclusions.
If the demand for our drilling services remains at current levels or declines further and any of our rigs become
idle for an extended amount of time, then our estimated cash flows may further decrease, and the probability of a near
term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.
Additionally, we recorded $2.0 million of impairment charges during the year ended December 31, 2014 to reduce
the carrying values of certain other assets, which were placed as held for sale during the year, to their estimated fair
values, based on expected sales price. As of December 31, 2014, our consolidated balance sheet reflects assets held for
sale of $9.9 million, which represents the fair value of nine drilling rigs, four wireline units, two real estate properties
and other drilling equipment. In January and February 2015, we sold six drilling rigs and one real estate property for
$17.8 million. We did not incur any additional loss upon the sale of these assets. (See Note 14, Subsequent Events.)
During the years ended December 31, 2013 and 2012, we recorded impairment charges on our property and
equipment of $9.5 million and $1.1 million, respectively. During the third quarter of 2013, we decided to place eight
of our mechanical drilling rigs as held for sale, and we recognized an impairment loss of $9.2 million in order to reduce
the carrying value of these assets to their estimated fair value, based on their sales price. The sales of all eight drilling
rigs were completed in late October 2013 and we did not incur any additional gain or loss upon the sale of these rigs.
We also recorded an impairment of $0.3 million during the third quarter of 2013 in association with our decision to
sell certain production services equipment. In March 2012, we retired two mechanical drilling rigs, with most of their
components to be used as spare parts, as well as two wireline units and other wireline equipment, and recognized an
associated impairment charge of $1.1 million.
76
4.
Debt
Our debt consists of the following (amounts in thousands):
Senior secured revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2014
155,000
300,000
80
455,080
(27)
455,053
$
December 31, 2013
80,000
$
419,586
2,927
502,513
(2,847)
499,666
$
Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on September 22, 2014, with Wells Fargo Bank, N.A. and a syndicate
of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-
line loans, of up to an aggregate principal amount of $350 million, all of which matures on September 22, 2019 (the
“Revolving Credit Facility”). In addition, at our request, and with the lenders' consent, the aggregate commitments of
the lenders under the Revolving Credit Facility may be increased up to an additional $100 million provided that no
default exists, all representations and warranties are true and correct, and compliance with financial covenants as set
forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. The Revolving Credit
Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances,
which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event
will reduce the borrowing availability under the Revolving Credit Facility to less than $350 million.
Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank
prime rate, plus an applicable per annum margin that ranges from 2.0% to 3.0% and 1.0% to 2.0%, respectively. The
LIBOR margin and bank prime rate margin currently in effect are 2.25% and 1.25%, respectively. The Revolving Credit
Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the
lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average
undrawn amount of letters of credit outstanding during such period.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets
(including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-
tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets
of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer
Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital
and other general corporate purposes.
As of February 1, 2015, we had $150.0 million outstanding under our Revolving Credit Facility and $18.5 million
in committed letters of credit, which resulted in borrowing availability of $181.5 million under our Revolving Credit
Facility. There are no limitations on our ability to access this borrowing capacity provided there is no default, all
representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit
Facility is maintained. At December 31, 2014, we were in compliance with our financial covenants under the Revolving
Credit Facility. Our total consolidated leverage ratio was 1.8 to 1.0, our senior consolidated leverage ratio was 0.7 to
1.0, and our interest coverage ratio was 6.7 to 1.0. The financial covenants contained in our Revolving Credit Facility
include the following:
• A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;
• A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that
cannot exceed 2.50 to 1.00;
• A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and
•
If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our
minimum asset coverage ratio cannot be less than 1.00 to 1.00.
77
The Revolving Credit Facility does not restrict capital expenditures or repurchases of capital stock as long as
(a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures or
repurchases of capital stock, (b) after giving effect to such capital expenditures or repurchases of capital stock there is
availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated
leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. In addition, the
repurchase of capital stock requires, on a pro-forma basis, compliance with the maximum total leverage ratio and
minimum interest coverage ratio as set forth in the Revolving Credit Facility, both before and after giving effect to such
repurchase. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal
to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital
expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate
preceding fiscal year up to $30 million.
At December 31, 2014, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore,
we were not subject to the capital expenditure threshold restrictions listed above.
The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence
of additional debt, investments, liens, dividends, acquisitions, prepayments of indebtedness, asset dispositions, mergers
and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily
restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including
without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to
certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency,
judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit
agreement and change of control.
Senior Notes
On March 11, 2010, we issued $250 million of unregistered senior notes with a coupon interest rate of 9.875%
that were set to mature in 2018 (the “2010 Senior Notes”). The 2010 Senior Notes were sold with an original issue
discount of $10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity
of approximately 10.677%. On March 11, 2010, we received $234.8 million of net proceeds from the issuance of the
2010 Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for
underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings
outstanding under our Revolving Credit Facility.
On November 21, 2011, we issued $175 million of unregistered Senior Notes (the “2011 Senior Notes”). The
2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold
with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an
effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds
from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions
were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the
acquisition of the coiled tubing business in December 2011.
In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, during
2014, we redeemed all of our outstanding 2010 and 2011 Senior Notes, funded primarily by proceeds from the issuance
of our 2014 Senior Notes and additional borrowings under our Revolving Credit Facility, as well as some cash on hand.
In March 2014, we redeemed $99.5 million of the 2010 and 2011 Senior Notes for a total consideration of $1,055.08
for each $1,000 principal amount redeemed. In May and October 2014, we redeemed an additional $200.5 million and
$125.0 million, respectively, in aggregate principal amount of the 2010 and 2011 Senior Notes at a redemption price
equal to 104.938% of the principal amount, plus accrued and unpaid interest on the notes redeemed. Related to these
redemptions, we recognized a loss on debt extinguishment of approximately $31.2 million during 2014, which includes
redemption premiums of $21.6 million, $4.8 million of net unamortized discount and $4.8 million of unamortized debt
issuance costs.
On March 18, 2014, we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125%
that are due in 2022 (the “2014 Senior Notes”). The 2014 Senior Notes were sold at 100% of their face value. On
March 18, 2014, we received $293.9 million of net proceeds from the issuance of the 2014 Senior Notes after deductions
78
were made for the $6.1 million for underwriters’ fees and other debt offering costs. The net proceeds were used to fund
the tender and redemption of 2010 and 2011 Senior Notes in March and May 2014.
The 2014 Senior Notes will mature on March 15, 2022 with interest due semi-annually in arrears on March 15
and September 15 of each year. We have the option to redeem the 2014 Senior Notes, in whole or in part, at any time
on or after March 15, 2017 in each case at the redemption price specified in the Indenture dated March 18, 2014 (the
“2014 Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the 2014 Indenture)
thereon to the date of redemption. Prior to March 15, 2017, we may also redeem the 2014 Senior Notes, in whole or
in part, at a “make-whole” redemption price specified in the 2014 Indenture, plus any accrued and unpaid interest and
any additional interest thereon to the date of redemption. In addition, prior to March 15, 2017, we may, on one or more
occasions, redeem up to 35% of the aggregate principal amount of the 2014 Senior Notes at a redemption price equal
to 106.125% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the
redemption date, with the net cash proceeds of certain equity offerings, provided that at least 65% of the aggregate
principal amount of the 2014 Senior Notes remains outstanding after the occurrence of such redemption and that the
redemption occurs within 120 days of the date of the closing of such equity offering.
In accordance with a registration rights agreement with the holders of our 2014 Senior Notes, we filed an exchange
offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on
October 2, 2014, respectively. The exchange offer registration statement enabled the holders of our Senior Notes to
exchange their senior notes for publicly registered notes with substantially identical terms. References to the “Senior
Notes” herein include the senior notes issued in the exchange offer.
If we experience a change of control (as defined in the Indenture), we will be required to make an offer to each
holder of the Senior Notes to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the
principal amount of each Senior Note, plus accrued and unpaid interest, if any to the date of repurchase. If we engage
in certain asset sales, within 365 days of such sale we will be required to use the net cash proceeds from such sale, to
the extent we do not reinvest those proceeds in our business, to make an offer to repurchase the Senior Notes at a price
equal to 100% of the principal amount of each Senior Note, plus accrued and unpaid interest to the repurchase date.
The Indenture, among other things, limits our ability and the ability of certain of our subsidiaries to:
•
•
•
•
•
•
•
•
•
pay dividends on stock, repurchase stock, redeem subordinated indebtedness or make other restricted
payments and investments;
incur, assume or guarantee additional indebtedness or issue preferred or disqualified stock;
create liens on our or their assets;
enter into sale and leaseback transactions;
sell or transfer assets;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to any other person;
enter into transactions with affiliates; and
enter into new lines of business.
The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally
guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by
certain of our future domestic subsidiaries. (See Note 15, Guarantor/Non-Guarantor Condensed Consolidated
Financial Statements.)
Other Debt
Our other debt consists of a capital lease obligation for equipment with monthly payments due through November
2016.
79
Debt Issuance Costs
Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using
the straight-line method over the term of the Revolving Credit Facility which matures in September 2019. Costs incurred
in connection with the issuance of our 2014 Senior Notes were capitalized and are being amortized using the straight-
line method (which approximates amortization using the interest method) over the term of the Senior Notes which
mature in March 2022.
Capitalized debt costs related to the issuance of our long-term debt were approximately $9.8 million and $7.5
million as of December 31, 2014 and 2013, respectively. We recognized approximately $2.1 million of associated
amortization during each of the years ended December 31, 2014, 2013 and 2012, which excludes the $4.8 million of
debt costs recognized as loss on extinguishment of debt.
5.
Leases
We lease our corporate office facilities in San Antonio, Texas at a payment escalating from $41,264 per month
in January 2015 to $50,246 per month in December 2020. We recognize rent expense on a straight-line basis for our
corporate office lease. We also lease real estate at 51 other locations, which are primarily used for field offices and
storage and maintenance yards, and we lease vehicles, office and other equipment under non-cancelable operating
leases, most of which contain renewal options and some of which contain escalation clauses.
Future lease obligations required under non-cancelable operating leases as of December 31, 2014 were as follows
(amounts in thousands):
Year ended December 31,
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4,441
3,282
2,709
1,705
1,288
1,509
14,934
Rent expense under operating leases for the years ended December 31, 2014, 2013 and 2012 was $5.9 million,
$6.0 million and $5.6 million, respectively.
6.
Income Taxes
The jurisdictional components of income (loss) before income taxes consist of the following (amounts in
thousands):
Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Foreign. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
(49,050) $
(272)
(49,322) $
2013
(66,147) $
10,369
(55,778) $
2012
42,194
4,192
46,386
80
The components of our income tax expense (benefit) consist of the following (amounts in thousands):
Current tax:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
2013
2012
(112) $
1,325
3,149
4,362
(380) $
879
2,302
2,801
(17,438)
1,304
468
(15,666)
(11,304) $
(21,034)
(3,520)
1,907
(22,647)
(19,846) $
236
1,214
1,479
2,929
15,013
(749)
(839)
13,425
16,354
The difference between the income tax expense (benefit) and the amount computed by applying the federal
statutory income tax rate of 35% to income (loss) before income taxes consists of the following (amounts in thousands):
Expected tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Incentive stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net tax benefits and nondeductible expenses in foreign jurisdictions . . .
Foreign currency translation gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . .
Nondeductible expenses for tax purposes . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
(17,263) $
1,214
(208)
957
2,699
920
496
(119)
(11,304) $
2013
(19,522) $
(1,717)
66
(92)
617
863
—
(61)
(19,846) $
2012
16,235
302
43
533
(1,414)
770
(206)
91
16,354
Income tax expense (benefit) was allocated as follows (amounts in thousands):
Results of operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year ended December 31,
2014
(11,304) $
201
(11,103) $
2013
(19,846) $
321
(19,525) $
2012
16,354
449
16,803
81
Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their
reported amounts in the consolidated financial statements. The components of our deferred income tax assets and
liabilities were as follows (amounts in thousands):
Deferred tax assets:
Capital loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee benefits and insurance claims accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable reserve. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee stock-based compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses not deductible for tax purposes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued revenue not income for book purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal and state net operating loss and AMT credit carryforward . . . . . . . . . . . . . . .
Foreign net operating loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities:
Year ended December 31,
2014
2013
$
1,009
33,542
12,146
908
8,440
1,391
429
84,782
2,562
145,209
(1,504)
143,705
1,008
36,442
9,332
501
8,905
749
942
94,605
3,411
155,895
(1,008)
154,887
Property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
199,532
199,532
225,275
225,275
Net deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
55,827
$
70,388
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. Based on the expectation of future taxable income and that
the deductible temporary differences will offset existing taxable temporary differences, we believe it is more likely
than not that we will realize the benefits of these deductible temporary differences, with the exception of the items
noted below.
As of December 31, 2014, we had a $1.0 million deferred tax asset related to the sale of our ARPSs investments
which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this loss
to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our
deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods. In addition,
we have set up a $0.5 million valuation allowance against net operating losses in certain states.
As of December 31, 2014, we had $84.8 million and $2.6 million of deferred tax assets related to domestic and
foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability
of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the
jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating
losses and we expect to apply the net operating losses against taxable income that we have estimated in future periods.
The domestic net operating losses can be used to offset future domestic taxable income through 2033, while the majority
of the foreign net operating losses can be carried forward indefinitely.
Deferred income taxes have not been provided on the future tax consequences attributable to difference between
the financial statements carrying amounts of existing assets and liabilities and the respective tax bases of our foreign
subsidiary based on the determination that such differences are essentially permanent in duration in that the earnings
of the subsidiary is expected to be indefinitely reinvested in foreign operations. As of December 31, 2014, the cumulative
undistributed earnings/loss of the subsidiary was approximately a $11.6 million loss. If earnings were not considered
indefinitely reinvested, deferred income taxes would have been recorded after consideration of foreign tax credits. It
is not practicable to estimate the amount of additional tax that might be payable on earnings, if distributed.
82
On December 26, 2012, Colombia enacted a tax reform bill that, among other things, decreased the corporate
tax rate from 33% to 25%, but also added a new 9% tax for equality, which results in a combined tax rate of 34%. Net
operating losses cannot be utilized against the new 9% tax for equality, and therefore the associated deferred tax asset
must now be based on the lower 25% corporate tax rate only. Other deferred tax assets and liabilities must now be
based on the higher combined income tax rate of 34%. Included in our 2012 deferred foreign tax expense is a $1.7
million expense to adjust our Colombian net deferred tax assets and liabilities for the change in rates.
On December 23, 2014, the Colombian government enacted a tax reform bill that among other things, increased
the tax for equality ("CREE") rate from 9% to 14% in 2015, 15% in 2016, 17% in 2017 and 18% in 2018. Deferred
tax assets and liabilities (with the exception of net operating losses) must now be based on the higher combined income
tax rate and CREE rate of 39% in 2015, 40% in 2016, 42% in 2017 and 43% in 2018. Included in our 2014 deferred
foreign tax expense (benefit) is a $0.2 million benefit to adjust our Colombian net deferred tax assets and liabilities for
the change in rates. In addition, a new net-worth tax was enacted for all Colombian entities. The tax is calculated based
on an entity’s net equity as of January 1, 2015. The tax expense will be recognized when the net-worth tax is assessed,
beginning annually from 2015 through 2017. Based on our Colombian operation's net equity, our net-worth tax
obligations are expected to be approximately $1.4 million, $1.2 million and $0.5 million for the years ended
December 31, 2015, 2016 and 2017, respectively. The net worth tax is not deductible for income tax purposes.
We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during
the year ended December 31, 2014.
We adopted a policy to record interest and penalty expense related to income taxes as interest and other expense,
respectively. At December 31, 2014, no interest or penalties have been or are required to be accrued. Our open tax years
for our federal income tax returns in the United States are for the years ended December 31, 2011 to 2013. Our open
tax years for our income tax returns in Colombia are for the years ended December 31, 2009 to 2013.
7.
Fair Value of Financial Instruments
ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework
associated with the level of subjectivity used in measuring assets and liabilities at fair value.
At December 31, 2014 and December 31, 2013, our financial instruments consist primarily of cash, trade and
other receivables, trade payables and long-term debt. The carrying value of cash, trade and other receivables, and trade
payables are considered to be representative of their respective fair values due to the short-term nature of these
instruments.
The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we
believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on
inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments.
The following table presents the supplemental fair value information about long-term debt at December 31, 2014 and
December 31, 2013 (amounts in thousands):
Total debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 455,080
Carrying
Amount
Fair
Value
$ 415,785
Carrying
Amount
$ 502,513
Fair
Value
$ 538,074
December 31, 2014
December 31, 2013
83
8.
Earnings Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic income per share
and diluted income per share computations (amounts in thousands, except per share data):
Year ended December 31,
2014
2013
2012
Basic
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(38,018) $
(35,932) $
30,032
Weighted-average shares. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63,161
62,213
61,780
Income (loss) per common share—Basic . . . . . . . . . . . . . . . . . . . $
(0.60) $
(0.58) $
0.49
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(38,018) $
(35,932) $
30,032
Diluted
Weighted-average shares
Outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted effect of outstanding stock options, restricted stock
and restricted stock unit awards . . . . . . . . . . . . . . . . . . . . . . .
63,161
—
63,161
62,213
—
62,213
61,780
982
62,762
Income (loss) per common share—Diluted. . . . . . . . . . . . . . . . . . $
(0.60) $
(0.58) $
0.48
Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 3,949,464,
5,507,765 and 4,311,645 shares of common stock for the years ended December 31, 2014, 2013 and 2012, respectively,
were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.
9.
Equity Transactions and Stock-Based Compensation Plans
Equity Transactions
In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up
to a total dollar amount of $300 million. As of December 31, 2014, the entire $300 million under the shelf registration
statement is available for equity or debt offerings. In the future, we may consider equity or debt offerings, as appropriate,
to meet our liquidity needs.
Stock-based Compensation Plans
We have stock-based award plans that are administered by the Compensation Committee of our Board of Directors,
which selects persons eligible to receive awards and determines the number of stock options, restricted stock, or restricted
stock units subject to each award and the terms, conditions and other provisions of the awards. At December 31, 2014,
the total shares available for future grants to employees and directors under existing plans were 2,303,381, of which
no more than 1,669,117 may be granted in the form of restricted stock or restricted stock unit awards.
We grant stock option and restricted stock awards with vesting based on time of service conditions. We also grant
restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance
and market conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit
awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation.
For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period
for each separately vesting portion of the award as if the award was, in substance, multiple awards.
84
The following table summarizes the compensation expense recognized for stock option, restricted stock and
restricted stock unit awards during the years ended December 31, 2014, 2013 and 2012 (amounts in thousands):
Stock option awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Restricted stock awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock unit awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Stock Options
Year ended December 31,
2014
2013
2012
1,275
548
5,794
7,617
$
$
1,771
576
4,024
6,371
$
$
2,962
628
3,729
7,319
We grant stock option awards which generally become exercisable over a three-year period and expire ten years
after the date of grant. Our stock-based compensation plans require that all stock option awards have an exercise price
that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common
stock when vested stock option awards are exercised.
We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model.
The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-
average calculation for the years ended December 31, 2014, 2013 and 2012:
Year ended December 31,
2014
2013
2012
Expected volatility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life in years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grant-date fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
66%
1.7%
5.49
$4.87
66%
1.0%
5.53
$4.36
70%
0.8%
5.12
$5.02
The assumptions used in the Black-Scholes option pricing model are based on multiple factors, including historical
exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors,
expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have
not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual
value that will be realized, if any, will depend on the future performance of our common stock and overall stock market
conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated
using the Black-Scholes options-pricing model.
The following table represents stock option activity from December 31, 2012 through December 31, 2014:
Outstanding stock options as of December 31, 2012 . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding stock options as of December 31, 2013 . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding stock options as of December 31, 2014 . . . . . . .
Stock options exercisable as of December 31, 2014 . . . . . . .
Number of
Shares
5,649,991
220,656
(67,500)
(270,934)
5,532,213
221,440
(155,100)
(928,777)
4,669,776
4,124,506
Weighted-Average
Exercise Price
Per Share
Weighted-Average
Remaining Contract
Life in Years
$10.09
7.58
16.02
4.67
$10.18
8.44
14.82
9.01
$10.18
$10.42
4.7
4.2
85
At December 31, 2014, the aggregate intrinsic value of stock options outstanding was $1.4 million and the
aggregate intrinsic value of stock options exercisable was $1.4 million. Intrinsic value is the difference between the
exercise price of a stock option and the closing market price of our common stock, which was $5.54 on December 31,
2014.
The following table summarizes our nonvested stock option activity from December 31, 2012 through
December 31, 2014:
Nonvested stock options as of December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested stock options as of December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested stock options as of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . .
Number of
Shares
1,130,844
220,656
(594,459)
757,041
221,440
(433,211)
545,270
Weighted-Average
Grant-Date
Fair Value Per Share
$4.89
4.36
4.88
$4.74
4.87
4.77
$4.77
At December 31, 2014, there was $0.6 million of unrecognized compensation cost relating to stock options which
is expected to be recognized over a weighted-average period of 0.6 years.
In January 2015, our Board of Directors approved the grant of stock options representing 338,638 shares of
common stock to officers and employees that will vest over a three-year period.
Restricted Stock
Historically, we have generally granted restricted stock awards that vest over a three-year period with a fair value
based on the closing price of our common stock on the date of the grant. However, beginning in 2013, we began granting
restricted stock awards with a vesting period of one year. When restricted stock awards are granted, or when restricted
stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to
certain restrictions.
The following table summarizes our restricted stock activity from December 31, 2012 through December 31,
2014:
Nonvested restricted stock as of December 31, 2012 . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested restricted stock as of December 31, 2013 . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested restricted stock as of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . .
Number of
Shares
142,820
61,248
(98,864)
105,204
32,100
(88,620)
48,684
Weighted-Average
Grant-Date
Fair Value per Share
$8.67
7.51
8.47
$8.18
14.33
8.20
$12.20
At December 31, 2014, there was $0.2 million of unrecognized compensation cost relating to restricted stock
awards which is expected to be recognized over a weighted-average period of 0.4 years.
Restricted Stock Units
We grant restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”),
and we grant restricted stock unit awards with vesting based on time of service, which are also subject to performance
and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted
stock units only when they have satisfied the applicable vesting conditions.
86
Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our
common stock on the date of grant.
Our performance-based RSUs generally cliff vest after 39 months from the date of grant and are granted at a
target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual
achievement levels that are measured against predetermined performance conditions. The number of shares of common
stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a
predefined peer group, over the performance period, generally three years.
Approximately one-third of the performance-based RSUs granted during 2011, 2012 and 2013, and half of the
performance-based RSUs granted during 2014, are subject to a market condition based on total shareholder return, and
therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for
awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made,
regardless of the number of shares issued. The remaining performance-based RSUs are subject to performance
conditions, based on EBITDA and return on capital employed, and therefore the fair value is based on the closing price
of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensation
expense ultimately recognized for awards with performance conditions will be equal to the fair value of the restricted
stock unit award based on the actual outcome of the service and performance conditions.
In April 2014, we determined that 116.6% of the target number of shares granted during 2011 were actually earned
based on the Company’s achievement of certain performance measures, as compared to the predefined peer group, over
the performance period from January 1, 2011 through December 31, 2013, resulting in an additional 22,091 shares
being issued. The performance-based RSUs granted during 2011 vested and were converted to common stock at the
end of April 2014.
As of December 31, 2014, we estimated that our actual achievement level for the performance-based RSUs
granted during 2012, 2013 and 2014 will be approximately 117%, 100% and 110% of the predetermined performance
conditions, respectively. Therefore, the outstanding 861,812 restricted stock units would be adjusted to represent 922,845
shares of our common stock if these achievement levels are maintained through the applicable performance periods.
The following table summarizes our restricted stock unit activity from December 31, 2012 through December 31,
2014:
Time-Based Award
Performance-Based Award
Number of
Time-Based
Award Units
Weighted-Average
Grant-Date
Fair Value
per Unit
Number of
Performance-
Based
Award Units
Weighted-Average
Grant-Date
Fair Value
per Unit
Nonvested restricted stock units as of
December 31, 2012. . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested restricted stock units as of
December 31, 2013. . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . .
Achieved performance adjustment . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited. . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested restricted stock units as of
December 31, 2014. . . . . . . . . . . . . . . . . . . . . .
531,526
406,027
(254,629)
(55,212)
627,712
360,665
—
(267,430)
(45,868)
675,079
$9.16
7.59
9.82
8.60
$7.93
8.64
—
8.16
8.07
$8.21
355,051
346,731
—
(28,020)
673,762
400,503
22,091
(155,647)
(78,897)
861,812
$9.99
8.34
—
8.81
$9.19
9.67
10.23
10.23
9.30
$9.24
At December 31, 2014, there was $5.0 million of unrecognized compensation cost relating to restricted stock
unit awards which is expected to be recognized over a weighted-average period of 1.1 years.
In January 2015, our Board of Directors approved the grant of restricted stock units representing 581,192 shares
of common stock to officers and employees that will vest over a three-year period.
87
10.
Employee Benefit Plans and Insurance
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching
contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we
determine annually. Our matching contributions for the years ended December 31, 2014, 2013 and 2012 were $6.4
million, $6.0 million and $4.6 million, respectively.
We maintain a self-insurance program, for major medical and hospitalization coverage for employees and their
dependents, which is partially funded by employee payroll deductions. We have provided for reported claims costs as
well as incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum
liability of $200,000 per covered individual per year. Amounts in excess of the stated maximum are covered under a
separate policy provided by an insurance company. Accrued insurance premiums and deductibles at December 31, 2014
and 2013 include $3.4 million and $3.1 million, respectively, for our estimate of incurred but unpaid costs related to
the self-insurance portion of our health insurance.
We are self-insured for up to $500,000 per incident for all workers’ compensation claims submitted by employees
for on-the-job injuries. We have a deductible of $250,000 per occurrence under both our general liability insurance and
auto liability insurance. We accrue our workers’ compensation claim cost estimates based on historical claims
development data and we accrue the cost of administrative services associated with claims processing. Accrued insurance
premiums and deductibles at December 31, 2014 and 2013 include $9.0 million and $7.3 million, respectively, for our
estimate of costs relative to the self-insured portion of our workers’ compensation, general liability and auto liability
insurance. Based upon our past experience, management believes that we have adequately provided for potential losses.
However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our
financial position and results of operations.
11.
Segment Information
We have two operating segments referred to as the Drilling Services Segment and the Production Services Segment
which is the basis management uses for making operating decisions and assessing performance.
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse
group of oil and gas exploration and production companies through our six drilling divisions in the US and internationally
in Colombia.
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
Drilling Rigs
Held for Sale
(9)
(12)
Drilling Rig
Fleet Count
53
47
As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
South Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appalachia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rig Count
13
10
9
4
3
8
47
Production Services Segment—Our Production Services Segment provides a range of services to exploration and
production companies, including well servicing, wireline services and coiled tubing services. Our production services
operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and
Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of February 1, 2015, we have a fleet of
88
117 well servicing rigs consisting of 107 rigs with 550 horsepower and 10 rigs with 600 horsepower. We provide
wireline services and coiled tubing services with a fleet of 128 wireline units and 17 coiled tubing units. On September
17, 2014, we completed the disposition of our fishing and rental services operations.
The following tables set forth certain financial information for our two operating segments and corporate as of
and for the years ending December 31, 2014, 2013 and 2012 (amounts in thousands):
As of and for the year ended December 31, 2014
Drilling
Services
Segment
Production
Services
Segment
Corporate
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . $
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Segment margin . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . $
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . $
712,604
516,473
345,862
170,611
115,714
112,483
$
$
$
$
$
412,516
538,750
340,102
198,648
66,326
74,652
$
$
$
$
$
46,469
$
— $
—
— $
$
$
1,336
986
As of and for the year ended December 31, 2013
Drilling
Services
Segment
Production
Services
Segment
Corporate
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . $
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Segment margin . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . $
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . $
791,820
528,327
351,630
176,697
122,201
78,708
$
$
$
$
$
395,219
431,859
277,625
154,234
64,604
44,541
$
$
$
$
$
42,584
$
— $
—
— $
$
$
1,113
2,171
As of and for the year ended December 31, 2012
Drilling
Services
Segment
Production
Services
Segment
Corporate
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . $
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Segment margin . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . $
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . $
867,526
498,867
333,846
165,021
108,151
265,966
$
$
$
$
$
439,113
420,576
252,775
167,801
55,693
110,813
$
$
$
$
$
33,137
$
— $
—
— $
$
873
$
2,493
Total
1,171,589
1,055,223
685,964
369,259
183,376
188,121
Total
1,229,623
960,186
629,255
330,931
187,918
125,420
Total
1,339,776
919,443
586,621
332,822
164,717
379,272
The following table reconciles the segment profits reported above to income from operations as reported on the
consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (amounts in thousands):
Segment margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of fishing and rental services operations . . . . . . . . .
Gain on litigation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations . . . . . . . . . . . . . . . . . . . . . . . . $
89
Year ended December 31,
2014
369,259
(183,376)
(103,385)
(1,445)
(73,025)
10,702
5,254
23,984
$
$
$
2013
330,931
(187,918)
(94,183)
(767)
(54,292)
—
—
(6,229) $
2012
332,822
(164,717)
(85,603)
440
(1,131)
—
—
81,811
The following table sets forth certain financial information for our international operations in Colombia as of
and for the years ended December 31, 2014, 2013 and 2012 (amounts in thousands):
Identifiable assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
As of and for the year ended December 31,
2014
142,321
104,520
$
$
2013
150,719
115,631
$
$
2012
148,567
95,338
Identifiable assets for our international operations in Colombia include five drilling rigs that are owned by our
Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our
Colombia subsidiary.
12.
Commitments and Contingencies
In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on
drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have
guaranteed payments of $51.7 million relating to our performance under these bonds as of December 31, 2014.
Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims
related to our business activities, including workers’ compensation claims and employment-related disputes. Legal
costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation,
disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash
flow from operations.
13.
Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for the years ended December 31, 2014 and 2013 (in
thousands, except per share data):
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
Year ended December 31, 2014
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 239,034
17,935
Income (loss) from operations . . . . . . . . . . . . . . .
(37)
Income tax (expense) benefit . . . . . . . . . . . . . . . .
(2,579)
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings (loss) per share:
$ 259,812
21,917
1,070
(319)
$ 273,267
32,804
(9,927)
12,453
$ 283,110
(48,672)
20,198
(47,573)
$1,055,223
23,984
11,304
(38,018)
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(0.04) $
(0.04) $
(0.01) $
(0.01) $
0.20
0.19
$
$
(0.75) $
(0.75) $
(0.60)
(0.60)
Year ended December 31, 2013
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 229,670
10,445
Income (loss) from operations . . . . . . . . . . . . . . .
546
Income tax (expense) benefit . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
(1,292)
Earnings (loss) per share:
$ 248,354
(27,268)
14,953
(25,895)
$ 243,979
1,870
3,614
(6,230)
$ 238,183
8,724
733
(2,515)
$ 960,186
(6,229)
19,846
(35,932)
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(0.02) $
(0.02) $
(0.42) $
(0.42) $
(0.10) $
(0.10) $
(0.04) $
(0.04) $
(0.58)
(0.58)
90
14.
Subsequent Events
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015.
As of December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of February 1, 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Rigs
Owned
62
59
Drilling Rigs
Held for Sale
(9)
(12)
Drilling Rig
Fleet Count
53
47
In January, we sold three drilling rigs and placed an additional six drilling rigs as held for sale. In February, we
sold another three drilling rigs and we expect to place an additional nine drilling rigs as held for sale before the end of
the first quarter of 2015. Excluding the drilling rigs which we expect to sell, we expect to have 38 drilling rigs in our
fleet at March 31, 2015.
The net book value of the nine drilling rigs held for sale at December 31, 2014 is $9.1 million, which is classified
as current assets held for sale in our consolidated balance sheet. The net book value as of December 31, 2014 of the
15 additional rigs which we expect to place as held for sale during the first quarter of 2015 is $17.5 million.
In addition to the six drilling rigs which we sold in January and February 2015, we sold one real estate property,
for a combined total of $17.8 million. We did not incur any additional loss upon the sale of these assets.
15.
Guarantor/Non-Guarantor Condensed Consolidated Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by
all existing domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate
our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries
do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.
In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor
subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to
distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that
we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of December 31,
2014, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of the guarantee arrangements, we are presenting the following condensed consolidated balance sheets,
statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor
subsidiaries.
91
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands)
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . .
Receivables, net of allowance. . . . . . . . . . . . . . . . . . . . .
Intercompany receivable (payable). . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net of accumulated amortization . . . . . . . . .
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Current portion of long-term debt. . . . . . . . . . . . . . . . . .
Deferred revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, less current portion . . . . . . . . . . . . . . . . . . . .
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total shareholders’ equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and shareholders’ equity . . . . . . . . . . . . . . . . . $
ASSETS
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . $
Receivables, net of allowance. . . . . . . . . . . . . . . . . . . . .
Intercompany receivable (payable). . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net of accumulated amortization . . . . . . . . .
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Current portion of long-term debt. . . . . . . . . . . . . . . . . .
Deferred revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, less current portion . . . . . . . . . . . . . . . . . . . .
Noncurrent deferred income taxes . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total shareholders’ equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and shareholders’ equity . . . . . . . . . . . . . . . . . $
Parent
Guarantor
Subsidiaries
December 31, 2014
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
27,688
1,641
(24,836)
1,827
—
—
1,217
7,537
4,179
830,185
—
111,286
10,122
963,309
735
—
—
11,109
11,844
455,000
138
513
467,495
495,814
963,309
$
$
$
(5,516)
151,048
55,567
8,196
7,208
9,909
6,554
232,966
763,994
116,799
24,223
—
1,955
1,139,937
57,910
27
3,315
64,063
125,315
53
180,726
3,658
309,752
830,185
1,139,937
$
$
$
12,752
37,512
(30,728)
975
6,909
—
1,154
28,574
89,118
—
—
2,753
6,921
127,366
5,660
—
—
4,376
10,036
—
—
531
10,567
116,799
127,366
$
$
— $
—
(3)
—
—
—
—
(3)
(750)
(946,984)
—
(111,286)
—
(1,059,023)
$
— $
—
—
(3)
(3)
—
(111,286)
—
(111,289)
(947,734)
(1,059,023)
$
34,924
190,201
—
10,998
14,117
9,909
8,925
269,074
856,541
—
24,223
2,753
18,998
1,171,589
64,305
27
3,315
79,545
147,192
455,053
69,578
4,702
676,525
495,064
1,171,589
Parent
Guarantor
Subsidiaries
December 31, 2013
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
$
$
28,368
905
(24,837)
1,143
—
1,013
6,592
4,531
939,091
—
78,486
7,588
1,036,288
757
—
—
16,368
17,125
499,586
—
394
517,105
519,183
1,036,288
92
(2,059)
125,979
52,671
8,005
7,415
7,094
199,105
846,632
120,630
32,194
—
2,009
1,200,570
37,797
2,847
699
51,739
93,082
80
163,122
5,195
261,479
939,091
1,200,570
$
$
$
$
1,076
49,476
(27,834)
3,944
5,817
1,204
33,683
87,244
—
—
1,156
9,639
131,722
5,164
—
—
5,462
10,626
—
—
466
11,092
120,630
131,722
$
$
$
$
— $
—
—
—
—
—
—
(750)
(1,059,721)
—
(78,486)
—
(1,138,957)
$
— $
—
—
—
—
—
(78,486)
—
(78,486)
(1,060,471)
(1,138,957)
$
27,385
176,360
—
13,092
13,232
9,311
239,380
937,657
—
32,194
1,156
19,236
1,229,623
43,718
2,847
699
73,569
120,833
499,666
84,636
6,055
711,190
518,433
1,229,623
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)
Year ended December 31, 2014
Non-Guarantor
Subsidiaries
Guarantor
Subsidiaries
Eliminations
Consolidated
Parent
Revenues .................................................................................. $
Costs and expenses:
Operating costs ...............................................................
Depreciation and amortization .......................................
General and administrative .............................................
Bad debt expense (recovery) ..........................................
Impairment charges ........................................................
Gain on sale of fishing and rental services operations....
Gain on litigation ............................................................
Intercompany leasing .....................................................
Total costs and expenses ..........................................................
Income (loss) from operations .................................................
Other (expense) income:
Equity in earnings of subsidiaries ...................................
Interest expense, net of interest capitalized ....................
Loss on extinguishment of debt ......................................
Other ..............................................................................
Total other (expense) income ...................................................
Income (loss) before income taxes ...........................................
Income tax (expense) benefit ...................................................
Net income (loss) ..................................................................... $
— $
950,703
$
104,520
$
— $
1,055,223
—
1,336
27,314
—
—
—
(5,254)
—
23,396
(23,396)
21,254
(38,562)
(31,221)
21
(48,508)
(71,904)
33,886
(38,018) $
609,596
168,157
72,878
1,329
73,025
(10,702)
—
(4,860)
909,423
41,280
(3,767)
(223)
—
2,985
(1,005)
40,275
(19,021)
21,254
$
76,368
13,883
3,745
116
—
—
—
4,860
98,972
5,548
—
—
(552)
—
—
—
—
—
(552)
552
—
4
—
(5,758)
(5,754)
(206)
(3,561)
(3,767) $
(17,487)
—
—
(552)
(18,039)
(17,487)
—
(17,487) $
685,964
183,376
103,385
1,445
73,025
(10,702)
(5,254)
—
1,031,239
23,984
—
(38,781)
(31,221)
(3,304)
(73,306)
(49,322)
11,304
(38,018)
Revenues .................................................................................. $
Costs and expenses:
Operating costs ...............................................................
Depreciation and amortization .......................................
General and administrative .............................................
Bad debt expense (recovery) ..........................................
Impairment charges ........................................................
Intercompany leasing .....................................................
Total costs and expenses ..........................................................
Income (loss) from operations .................................................
Other (expense) income:
Equity in earnings of subsidiaries ...................................
Interest expense, net of interest capitalized ....................
Other ..............................................................................
Total other (expense) income ...................................................
Income (loss) before income taxes ...........................................
Income tax (expense) benefit ...................................................
Net income (loss) ..................................................................... $
Revenues .................................................................................. $
Costs and expenses:
Operating costs ...............................................................
Depreciation and amortization .......................................
General and administrative .............................................
Bad debt expense (recovery) ..........................................
Impairment of equipment ...............................................
Intercompany leasing .....................................................
Total costs and expenses ..........................................................
Income (loss) from operations .................................................
Other (expense) income:
Equity in earnings of subsidiaries ...................................
Interest expense ..............................................................
Other ..............................................................................
Total other (expense) income ...................................................
Income (loss) before income taxes ...........................................
Income tax expense (benefit) ...................................................
Net income (loss) ..................................................................... $
Parent
Guarantor
Subsidiaries
844,555
— $
Year ended December 31, 2013
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
115,631
$
— $
960,186
—
1,113
25,272
67
—
—
26,452
(26,452)
11,861
(48,302)
9
(36,432)
(62,884)
26,952
(35,932) $
548,345
173,516
65,962
700
54,292
(4,860)
837,955
6,600
6,260
(37)
1,990
8,213
14,813
(2,952)
11,861
$
80,910
13,289
3,501
—
—
4,860
102,560
13,071
—
—
(552)
—
—
—
(552)
552
—
29
(2,686)
(2,657)
10,414
(4,154)
6,260
$
(18,121)
—
(552)
(18,673)
(18,121)
—
(18,121) $
629,255
187,918
94,183
767
54,292
—
966,415
(6,229)
—
(48,310)
(1,239)
(49,549)
(55,778)
19,846
(35,932)
Year ended December 31, 2012
Non-Guarantor
Subsidiaries
Guarantor
Subsidiaries
Eliminations
Consolidated
Parent
— $
779,163
$
140,280
$
— $
919,443
485,342
142,972
54,715
(612)
1,131
(4,860)
678,688
100,475
4,029
(59)
940
4,910
105,385
(37,033)
68,352
$
101,279
20,872
9,228
172
—
4,860
136,411
3,869
—
—
(552)
—
—
—
(552)
552
—
21
968
989
4,858
(829)
4,029
$
(72,381)
—
(552)
(72,933)
(72,381)
—
(72,381) $
586,621
164,717
85,603
(440)
1,131
—
837,632
81,811
—
(37,049)
1,624
(35,425)
46,386
(16,354)
30,032
—
873
22,212
—
—
—
23,085
(23,085)
68,352
(37,011)
268
31,609
8,524
21,508
30,032
93
$
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
Year ended December 31, 2014
Non-Guarantor
Guarantor
Subsidiaries
Subsidiaries
146,891
$
27,332
$
Consolidated
$
233,041
(158,392)
—
8,069
(150,323)
(25)
—
—
—
—
—
(25)
(3,457)
(2,059)
(5,516) $
$
(15,957)
—
301
(15,656)
—
—
—
—
—
—
—
11,676
1,076
12,752
$
(175,378)
15,090
8,370
(151,918)
(490,025)
440,000
(9,239)
(21,553)
8,368
(1,135)
(73,584)
7,539
27,385
34,924
Year ended December 31, 2013
Non-Guarantor
Guarantor
Subsidiaries
Subsidiaries
142,225
$
447
$
Consolidated
$
174,580
Parent
58,818
(1,029)
15,090
—
14,061
(490,000)
440,000
(9,239)
(21,553)
8,368
(1,135)
(73,559)
(680)
28,368
27,688
Parent
31,908
(2,649)
8
—
(2,641)
(60,000)
40,000
(13)
1,266
(631)
(19,378)
9,889
18,479
28,368
$
(151,363)
12,510
844
(138,009)
(874)
—
—
—
—
(874)
3,342
(5,401)
(2,059) $
(11,344)
1,318
—
(10,026)
—
—
—
—
—
—
(9,579)
10,655
1,076
$
(165,356)
13,836
844
(150,676)
(60,874)
40,000
(13)
1,266
(631)
(20,252)
3,652
23,733
27,385
Year ended December 31, 2012
Non-Guarantor
Guarantor
Subsidiaries
Subsidiaries
338,418
32,489
$
Parent
(171,541) $
Consolidated
$
199,366
(2,187)
—
(2,187)
—
100,000
(58)
693
(360)
100,275
(73,453)
91,932
18,479
(332,082)
2,998
(329,084)
(856)
—
—
—
—
(856)
8,478
(13,879)
$
(5,401) $
(30,055)
95
(29,960)
(18)
—
—
—
—
(18)
2,511
8,144
10,655
$
(364,324)
3,093
(361,231)
(874)
100,000
(58)
693
(360)
99,401
(62,464)
86,197
23,733
Cash flows from operating activities............................................................. $
Cash flows from investing activities:
Purchases of property and equipment ..................................................
Proceeds from sale of fishing and rental services operations...............
Proceeds from sale of property and equipment ....................................
Cash flows from financing activities:
Debt repayments...................................................................................
Proceeds from issuance of debt ............................................................
Debt issuance costs...............................................................................
Tender premium costs...........................................................................
Proceeds from exercise of options........................................................
Purchase of treasury stock....................................................................
Net increase (decrease) in cash and cash equivalents ...................................
Beginning cash and cash equivalents ............................................................
Ending cash and cash equivalents ................................................................. $
Cash flows from operating activities............................................................. $
Cash flows from investing activities:
Purchases of property and equipment ..................................................
Proceeds from sale of property and equipment ....................................
Proceeds from insurance recoveries .....................................................
Cash flows from financing activities:
Debt repayments...................................................................................
Proceeds from issuance of debt ............................................................
Debt issuance costs...............................................................................
Proceeds from exercise of options........................................................
Purchase of treasury stock....................................................................
Net increase (decrease) in cash and cash equivalents ...................................
Beginning cash and cash equivalents ............................................................
Ending cash and cash equivalents ................................................................. $
Cash flows from operating activities............................................................. $
Cash flows from investing activities:
Purchases of property and equipment ..................................................
Proceeds from sale of property and equipment ....................................
Cash flows from financing activities:
Debt repayments...................................................................................
Proceeds from issuance of debt ............................................................
Debt issuance costs...............................................................................
Proceeds from exercise of options........................................................
Purchase of treasury stock....................................................................
Net increase (decrease) in cash and cash equivalents ...................................
Beginning cash and cash equivalents ............................................................
Ending cash and cash equivalents ................................................................. $
94
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision
and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon
that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2014, to ensure that information required to be disclosed in our reports
filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our
management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three months
ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Pioneer Energy Services Corp. is responsible for establishing and maintaining adequate
internal control over financial reporting. Pioneer Energy Services Corp.'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: (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) 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 Pioneer
Energy Services Corp. are being made only in accordance with authorizations of management and directors of the
company; and (3) 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.
Pioneer Energy Services Corp.’s management assessed the effectiveness of Pioneer Energy Services Corp.’s
internal control over financial reporting as of December 31, 2014. In making this assessment, it used the criteria set
forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-
Integrated Framework (1992). Based on our assessment we have concluded that, as of December 31, 2014, Pioneer
Energy Services Corp.’s internal control over financial reporting was effective based on those criteria.
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements
of Pioneer Energy Services Corp. included in this Annual Report on Form 10-K, has issued an attestation report on the
effectiveness of Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 2014.
This report is included in Item 8, Financial Statements and Supplementary Data.
Item 9B. Other Information
Not applicable.
95
PART III
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items
from the definitive proxy statement for our 2015 Annual Meeting of Shareholders. We intend to file that definitive
proxy statement with the SEC on or about April 15, 2015.
Item 10. Directors, Executive Officers and Corporate Governance
Please see the information appearing in the proposal for the election of directors and under the headings “Executive
Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Business Conduct
and Ethics and Corporate Governance Guidelines” and “Section 16(a) Beneficial Ownership Reporting Compliance”
in the definitive proxy statement for our 2015 Annual Meeting of Shareholders for the information this Item 10 requires.
Item 11. Executive Compensation
Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Director
Compensation,” “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and
“Report of the Compensation Committee” in the definitive proxy statement for our 2015 Annual Meeting of Shareholders
for the information this Item 11 requires.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder
Matters
Please see the information appearing under the headings “Equity Compensation Plan Information” and “Security
Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2015 Annual
Meeting of Shareholders for the information this Item 12 requires.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Please see the information appearing in the proposal for the election of directors and under the heading “Certain
Relationships and Related Transactions” in the definitive proxy statement for our 2015 Annual Meeting of Shareholders
for the information this Item 13 requires.
Item 14. Principal Accountant Fees and Services
Please see the information appearing in the proposal for the ratification of the appointment of our independent
registered public accounting firm in the definitive proxy statement for our 2015 Annual Meeting of Shareholders for
the information this Item 14 requires.
96
Item 15. Exhibits and Financial Statement Schedules
(1) Financial Statements.
PART IV
See Index to Consolidated Financial Statements included in Item 8, Financial Statements and Supplementary
Data.
(2) Financial Statement Schedules.
No financial statement schedules are submitted because either they are inapplicable or because the required
information is included in the consolidated financial statements or notes thereto.
(3) Exhibits.
The following exhibits are filed as part of this report:
Exhibit
Number
Description
3.1*
- Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012
(File No. 1-8182, Exhibit 3.1)).
3.2*
- Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012
(File No. 1-8182, Exhibit 3.2)).
4.1*
- Form of Certificate representing Common Stock of Pioneer Energy Services Corp. (Form 10-Q
dated August 7, 2012 (File No. 1-8182, Exhibit 4.1)).
4.2*
- Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary
guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated
March 12, 2010 (File No. 1-8182, Exhibit 4.1)).
4.3*
- Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company,
the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated
March 12, 2010 (File No. 1-8182, Exhibit 4.2)).
4.4*
- First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company,
the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee
(Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)).
4.5*
- Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling
Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K
dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)).
4.6*
- Second Supplemental Indenture, dated October 1, 2012, by and among Pioneer Coiled Tubing
Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo
Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182,
Exhibit 4.6)).
4.7*
- Indenture, dated March 18, 2014, by and among Pioneer Energy Services Corp., the subsidiaries
named as guarantors therein and Wells Fargo Bank, National Association, as trustee (Form 8-K
dated March 18, 2014 (File No. 1-8182, Exhibit 4.1)).
4.8*
- Registration Rights Agreement, dated March 18, 2014, by and among Pioneer Energy Services
Corp., the subsidiaries named as guarantors therein and the initial purchasers party thereto (Form 8-
K dated March 18, 2014 (File No. 1-8182, Exhibit 10.1)).
10.1+*
- Pioneer Drilling Company’s 1999 Stock Plan and Form of Stock Option Agreement (Form 10-K
dated June 22, 2001 (File No. 1-8182, Exhibit 10.7)).
10.2+*
- Pioneer Drilling Company 2003 Stock Plan (Form S-8 dated November 18, 2003 (File No.
333-110569, Exhibit 4.4)).
97
10.3+*
- Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q dated November
3, 2011 (File No. 1-8182, Exhibit 10.1)).
10.4+*
- Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award
Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).
10.5*
- Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement (Form 10-Q
dated July 31, 2014 (File No. 1-8182, Exhibit 10.2)).
10.6+*
- Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement (Form 10-Q
dated July 31, 2014 (File No. 1-8182, Exhibit 10.3)).
10.7+*
- Pioneer Energy Services Corp. 2007 Incentive Plan Form of Restricted Stock Unit Award
Agreement (Form 10-Q dated July 31, 2014 (File No. 1-8182, Exhibit 10.4)).
10.8+*
- Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock
Unit Award Agreement (Form 10-Q dated July 31, 2014 (File No. 1-8182, Exhibit 10.5)).
10.9+*
- Pioneer Energy Services Corp. 2007 Incentive Plan Form of Non-Employee Director Restricted
Stock Award Agreement (Form 10-Q dated July 31, 2014 (File No. 1-8182, Exhibit 10.6)).
10.10+* - Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award
Agreement (Form 10-Q dated July 31, 2014 (File No. 1-8182, Exhibit 10.7)).
10.11+* - Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award
Agreement (Form 10-Q dated July 31, 2014 (File No. 1-8182, Exhibit 10.8)).
10.12+* - Pioneer Drilling Company Amended and Restated Key Executive Severance Plan (Form 10-Q for
the dated August 5, 2008 (File No. 1-8182, Exhibit 10.4)).
10.13+* - Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007
(File No. 1-8182, Exhibit 10.1)).
10.14+* - Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K
dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).
10.15*
- Amended and Restated Credit Agreement, dated as of June 30, 2011 among Pioneer Drilling
Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing
lender and swing line lender (Form 8-K dated July 5, 2011 (File No. 1-8182, Exhibit 10.1)).
10.16*
10.17*
- First Amendment dated as of March 3, 2014, by and among Pioneer Energy Services Corp. (f/k/a
Pioneer Drilling Company), a Texas corporation, the lenders party thereto, and Wells Fargo Bank,
N.A., as administrative agent for the lenders (Form 8-K dated March 4, 2014 (File No. 1-8182,
Exhibit 4.1)).
- Second Amendment dated as of September 22, 2014, by and among Pioneer Energy Services Corp.
(f/k/a Pioneer Drilling Company), a Texas corporation, the lenders party thereto, and Wells Fargo
Bank, N.A., as administrative agent for the lenders (Form 8-K dated September 23, 2014 (File No.
1-8182, Exhibit 4.1)).
10.18+* - Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace
(Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)).
10.19+* - Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer
Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5,
2008 (File No. 1-8182, Exhibit 10.2)).
10.20+* - Employment Letter, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips
(Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).
10.21+* - Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K
dated January 30, 2013 (File No. 1-8182, Exhibit 10.1)).
10.22+* - Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of
definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182)).
98
10.23+* - Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of
definitive proxy statement on Schedule 14A dated April 9, 2014 (File No. 1-8182)).
10.24+** - Retirement and Consulting Services Agreement and Complete Release of All Claims, effective
January 1, 2015, by and between Pioneer Energy Services Corp and F.C. "Red" West.
12.1**
- Computation of ratio of earnings to fixed charges.
21.1**
- Subsidiaries of Pioneer Energy Services Corp.
23.1**
- Consent of Independent Registered Public Accounting Firm.
31.1**
- Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14
(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
31.2**
- Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32.1#
- Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
32.2#
- Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
101**
- The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year
ended December 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i)
Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated
Statements of Shareholders' Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to
Consolidated Financial Statements.
Incorporated by reference to the filing indicated.
_______________
*
** Filed herewith.
# Furnished herewith.
+ Management contract or compensatory plan or arrangement.
99
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
February 17, 2015
PIONEER ENERGY SERVICES CORP.
/S/ WM. STACY LOCKE
Wm. Stacy Locke
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/S/ DEAN A. BURKHARDT
Dean A. Burkhardt
Chairman
February 17, 2015
/S/ WM. STACY LOCKE
Wm. Stacy Locke
/S/ LORNE E. PHILLIPS
Lorne E. Phillips
/S/ C. JOHN THOMPSON
C. John Thompson
/S/ JOHN MICHAEL RAUH
John Michael Rauh
/S/ SCOTT D. URBAN
Scott D. Urban
President, Chief Executive Officer and Director
(Principal Executive Officer)
February 17, 2015
February 17, 2015
February 17, 2015
February 17, 2015
February 17, 2015
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting
Officer)
Director
Director
Director
100
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[THIS PAGE INTENTIONALLY LEFT BLANK]
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
Reconciliation of Adjusted EBITDA to Net Income (Loss)
(in thousands)
2014
2013
2012
2011
2010
Year ended December 31,
Reconciliation of Adjusted EBITDA to
net income (loss):
Adjusted EBITDA*
$
277,081
$
Depreciation and amortization
(183,376)
Impairment charges
Interest expense
Loss on extinguishment of debt
Income tax (expense) benefit
(73,025)
(38,781)
(31,221)
11,304
Net income (loss)
$
(38,018) $
$
234,742
(187,918)
(54,292)
(48,310)
—
19,846
(35,932) $
249,283
(164,717)
(1,131)
(37,049)
—
(16,354)
30,032
$
$
183,870
(132,832)
(484)
(29,721)
—
(9,656)
11,177
$
$
103,151
(120,811)
(3,331)
(26,567)
—
14,297
(33,261)
*Adjusted EBITDA represents income (loss) before interest income (expense), taxes, depreciation, amortization, loss
on extinguishment of debt and impairments. We use this non-GAAP measure, together with our GAAP financial metrics,
to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives.
We believe that this measure is useful to investors and analysts in allowing for greater transparency of our operating
performance and makes it easier to compare our results with those of other companies within our industry. Adjusted
EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of
cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent
funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures
reported by other companies.
Pioneer Energy Services
2014 ANNUAL REPORT
DIRECTORS
DEAN A. BURKHARDT
Сonsultant to energy industry
SCOTT D. URBAN
Partner in Edgewater Energy
JOHN MICHAEL RAUH
Retired
Kerr-McGee Corporation
C. JOHN THOMPSON
Chairman and Chief Executive Officer
Ventana Capital Advisors, Inc.
WM. STACY LOCKE
President and
Chief Executive Officer
Pioneer Energy Services Corp.
OFFICERS
WM. STACY LOCKE
President and
Chief Executive Officer
CARLOS R. PEÑA
Senior Vice President,
General Counsel, Secretary and
Compliance Officer
CORPORATE INFORMATION
LORNE E. PHILLIPS
Executive Vice President and
Chief Financial Officer
BRIAN L. TUCKER
President of Drilling Services
BILL W. BOUZIDEN
JOE P. FREEMAN
Senior Vice President of Wireline
Services and Coiled Tubing Services
Senior Vice President
of Well Servicing
CORPORATE HEADQUARTERS
SHAREHOLDER CONTACT
INVESTOR RELATIONS
Pioneer Energy Services
1250 N.E. Loop 410
Suite 1000
San Antonio, Texas 78209
855.884.0575
Fax 210.828.8228
AUDITORS
KPMG LLP
17802 IH-10, Suite 101
Promenade Two
San Antonio, Texas 78257
Lorne E. Phillips
Executive Vice President and
Chief Financial Officer
855.884.0575
Fax 210.828.8228
investorrelations@pioneeres.com
A copy of the Company's annual report on
Form 10-K is available, without charge, upon
request to the address listed above.
STOCK LISTING
The New York Stock Exchange: PES
Lisa Elliott
Dennard (cid:402) Lascar Associates
713.529.6600
lelliott@DennardLascar.com
Anne Pearson
Dennard (cid:402) Lascar Associates
210.408.6321
apearson@DennardLascar.com
As of March 23, 2015, the approximate number of common shareholders of record was 356.
Certain information in this Annual Report, including information related to the retirement of our indebtedness, our future revenue stream, our future investment focus, future market conditions, future oil and gas prices,
fleet size, rig utilization, pricing, length of the current industry downturn, drilling contracts, and hourly rates, as well as other statements that express a belief, expectation or intention, and those that are not statements
of historical fact, are forward-looking statements. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan, “intend,” “seek,”
“will,” “should,” “goal” or other words and phrases of similar import that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date of the preparation of this Annual
Report. We disclaim any obligation to update any of these forward-looking statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and
assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other
risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties include, among other matters, the risks set forth in
Item 1A—“Risk Factors” of our Form 10-K for the fiscal year ended December 31, 2014. These risks, contingencies and uncertainties could cause our actual results to differ materially from those expressed in a
forward-looking statement contained in this Annual Report. Unpredictable or unknown factors we have not discussed in this Annual Report or elsewhere could also have material adverse effects on actual results of
matters that are the subject of our forward-looking statements. We advise our shareholders to (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and
(2) use caution and common sense when considering our forward-looking statements.
Pioneer Energy Services
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas 78209
www.pioneeres.com