10-Q 1 form10-qxq12018.htm 10-Q Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
______________________________________________ 
FORM 10-Q
______________________________________________ 
(Mark one)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2018
or
o
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
 
74-2088619
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification Number)
 
 
 
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas
 
78209
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code: (855) 884-0575
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  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
Accelerated filer
x
 
 
 
 
Non-accelerated filer
o
Smaller reporting company
o
   (Do not check if a small reporting company.)
 
 
Emerging Growth Company
o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No x
As of April 16, 2018, there were 77,805,934 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 



PART I. FINANCIAL INFORMATION
ITEM 1.
FINANCIAL STATEMENTS
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
March 31,
2018
 
December 31,
2017
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
68,726

 
$
73,640

Restricted cash
2,000

 
2,008

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
76,438

 
79,592

Unbilled receivables
22,306

 
16,029

Insurance recoveries
13,964

 
13,874

Other receivables
3,816

 
3,510

Inventory
16,100

 
14,057

Assets held for sale
6,139

 
6,620

Prepaid expenses and other current assets
4,914

 
6,229

Total current assets
214,403

 
215,559

Property and equipment, at cost
1,095,151

 
1,093,635

Less accumulated depreciation
554,863

 
544,012

Net property and equipment
540,288

 
549,623

Other noncurrent assets
3,009

 
1,687

Total assets
$
757,700

 
$
766,869

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
32,788

 
$
29,538

Deferred revenues
1,194

 
905

Accrued expenses:
 
 
 
Payroll and related employee costs
19,955

 
21,023

Insurance claims and settlements
13,964

 
13,289

Insurance premiums and deductibles
6,136

 
6,742

Interest
1,917

 
6,624

Other
6,267

 
6,793

Total current liabilities
82,221

 
84,914

Long-term debt, less unamortized discount and debt issuance costs
462,339

 
461,665

Deferred income taxes
4,061

 
3,151

Other noncurrent liabilities
8,892

 
7,043

Total liabilities
557,513

 
556,773

Commitments and contingencies (Note 10)

 

Shareholders’ equity:
 
 
 
Preferred stock, 10,000,000 shares authorized; none issued and outstanding

 

Common stock $.10 par value; 200,000,000 shares authorized; 77,795,934 and 77,719,021 shares outstanding at March 31, 2018 and December 31, 2017, respectively
7,845

 
7,835

Additional paid-in capital
547,407

 
546,158

Treasury stock, at cost; 658,561 and 630,688 shares at March 31, 2018 and December 31, 2017, respectively
(4,512
)
 
(4,416
)
Accumulated deficit
(350,553
)
 
(339,481
)
Total shareholders’ equity
200,187

 
210,096

Total liabilities and shareholders’ equity
$
757,700

 
$
766,869


See accompanying notes to condensed consolidated financial statements.

2




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
 
Three months ended March 31,
 
2018
 
2017
 
(in thousands, except per share data)
 
 
 
 
Revenues
$
144,478

 
$
95,757

 
 
 
 
Costs and expenses:
 
 
 
Operating costs
102,766

 
72,728

Depreciation and amortization
23,747

 
24,992

General and administrative
19,194

 
17,744

Bad debt recovery
(52
)
 
(363
)
Gain on dispositions of property and equipment, net
(335
)
 
(471
)
Total costs and expenses
145,320

 
114,630

Loss from operations
(842
)
 
(18,873
)
 
 
 
 
Other income (expense):
 
 
 
Interest expense, net of interest capitalized
(9,513
)
 
(6,059
)
Other income (expense), net
504

 
(144
)
Total other expense, net
(9,009
)
 
(6,203
)
 
 
 
 
Loss before income taxes
(9,851
)
 
(25,076
)
Income tax expense
(1,288
)
 
(48
)
Net loss
$
(11,139
)
 
$
(25,124
)
 
 
 
 
Loss per common share - Basic
$
(0.14
)
 
$
(0.33
)
 
 
 
 
Loss per common share - Diluted
$
(0.14
)
 
$
(0.33
)
 
 
 
 
Weighted average number of shares outstanding—Basic
77,606

 
77,072

 
 
 
 
Weighted average number of shares outstanding—Diluted
77,606

 
77,072

















See accompanying notes to condensed consolidated financial statements.

3




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Three months ended March 31,
 
2018
 
2017
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(11,139
)
 
$
(25,124
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
23,747

 
24,992

Allowance for doubtful accounts, net of recoveries
(52
)
 
(363
)
Gain on dispositions of property and equipment, net
(335
)
 
(471
)
Stock-based compensation expense
1,259

 
1,327

Amortization of debt issuance costs and discount
707

 
465

Deferred income taxes
911

 
(169
)
Change in other noncurrent assets
(463
)
 
466

Change in other noncurrent liabilities
1,844

 
868

Changes in current assets and liabilities:
 
 
 
Receivables
(3,296
)
 
(17,795
)
Inventory
(2,042
)
 
(1,911
)
Prepaid expenses and other current assets
881

 
1,012

Accounts payable
51

 
778

Deferred revenues
(108
)
 
(672
)
Accrued expenses
(6,908
)
 
(5,223
)
Net cash provided by (used in) operating activities
5,057

 
(21,820
)
 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(11,657
)
 
(24,683
)
Proceeds from sale of property and equipment
1,283

 
7,148

Proceeds from insurance recoveries
523

 
3,119

Net cash used in investing activities
(9,851
)
 
(14,416
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments

 
(6,305
)
Proceeds from issuance of debt

 
40,000

Debt issuance costs
(33
)
 

Purchase of treasury stock
(95
)
 
(363
)
Net cash provided by (used in) financing activities
(128
)
 
33,332

 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
(4,922
)
 
(2,904
)
Beginning cash, cash equivalents and restricted cash
75,648

 
10,194

Ending cash, cash equivalents and restricted cash
$
70,726

 
$
7,290

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
13,515

 
$
10,272

Income tax paid
$
658

 
$
261

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
2,931

 
$
2,924

 








See accompanying notes to condensed consolidated financial statements.

4




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Business
Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico.
Our drilling services business segments provide contract land drilling services through four domestic divisions which are located in the Marcellus/Utica, Eagle Ford, Permian Basin and Bakken regions, 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. Our drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. The following table summarizes our current rig fleet count and composition for each drilling services business segment:
 
Multi-well, Pad-capable
 
AC rigs
 
SCR rigs
 
Total
Domestic drilling
16

 

 
16
International drilling

 
8

 
8
 
 
 
 
 
24
Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast region, both onshore and offshore. As of March 31, 2018, the fleet count and composition for each of our production services business segments are as follows:
 
550 HP
 
600 HP
 
Total
Well servicing rigs, by horsepower (HP) rating
113
 
12

 
125

 
 
 
 
 
 
 
Onshore
 
Offshore
 
Total
Wireline services units
104
 
4

 
108

Coiled tubing services units
10
 
4

 
14

Basis of Presentation
The accompanying unaudited condensed 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 unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. We suggest that you read these unaudited condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the year ended December 31, 2017.
Use of Estimates In preparing the accompanying unaudited condensed 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 estimates of certain variable revenues and amortization periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, 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.

5




Subsequent Events In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after March 31, 2018, through the filing of this Form 10-Q, for inclusion as necessary.
Reclassifications Certain amounts in the unaudited condensed consolidated financial statements for the prior years have been reclassified to conform to the current year’s presentation.
We have five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services). We revised our segments as of December 31, 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. See Note 9, Segment Information for this revised presentation.
Change in Accounting Principle and Recently Issued Accounting Standards
Changes to accounting principles generally accepted in the United States of America (“U.S. GAAP”) are established by the Financial Accounting Standards Board (FASB) in the form of Accounting Standards Updates (ASUs) to the FASB Accounting Standards Codification (ASC). We consider the applicability and impact of all ASUs; any ASUs not listed below were assessed and determined to be either not applicable or are expected to have an immaterial impact on our consolidated financial position and results of operations.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that supersedes nearly all pre-existing revenue recognition guidance. The standard, and its related amendments, collectively referred to as ASC Topic 606, 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 adopted this standard effective January 1, 2018 using the modified retrospective method, in which the standard has been applied to all contracts existing as of the date of initial application, with the cumulative effect of applying the standard recognized in retained earnings. Accordingly, revenues for reporting periods ending after January 1, 2018 are presented under ASC Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. In accordance with ASC Topic 606, we also adopted ASC Subtopic 340-40, Other Assets and Deferred Costs, Contracts with Customers, effective January 1, 2018, which requires that the incremental costs of obtaining or fulfilling a contract with a customer be recognized as an asset if the costs are expected to be recovered.
The adoption of these standards resulted in a cumulative effect adjustment of $0.1 million after applicable income taxes, which consists of the impact of the timing difference related to recognition of mobilization revenues and costs. Mobilization costs incurred are deferred and amortized over the expected period of benefit under ASC Subtopic 340-40, but were amortized over the initial contract term under the previous accounting guidance. The recognition of both mobilization revenues and costs begins when mobilization activity is completed under ASC Topic 606, but were recognized during the period of initial mobilization under the previous accounting guidance. Additionally, the opening balances of deferred mobilization costs were reclassified in accordance with ASC Subtopic 340-40, which requires classification of the entire deferred balance according to the duration of the original contract to which it relates, rather than bifurcating the asset into current and noncurrent portions.
For more information about the accounting under ASC Topic 606, and disclosures under the new standard, see Note 2, Revenue from Contracts with Customers.
Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which among other things, requires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the current lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance (referenced above). This ASU is effective for us beginning January 1, 2019 and requires a modified retrospective application, although certain practical expedients are permitted. We have performed a scoping and preliminary assessment of the impact of this new standard.
As a lessee, this standard will impact us in situations where we lease real estate and office equipment, for which we will recognize a right-of-use asset and a corresponding lease liability on our consolidated balance sheet. The future

6




lease obligations disclosed in Note 4, Leases, included in Part II, Item 8, of our Annual Report on Form 10-K for the year ended December 31, 2017, provides some insight to the estimated impact of adoption for us as a lessee.
As a lessor, we expect the adoption of this new standard will apply to our drilling contracts and as a result, we expect to have a lease component and a service component of our revenues derived from these contracts. However, recent FASB tentative decisions indicate that additional practical expedients may be adopted by the FASB which, if adopted, we expect would allow us to continue to present our revenues from drilling contracts (both lease and service components) as one revenue stream. We have not yet determined the impact this standard may have on our production services businesses. We continue to evaluate the impact of this guidance and have not yet determined its impact on our financial position and results of operations.
Additional Detail of Account Balances and Related-Party Transactions
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 deferred mobilization costs for short-term drilling contracts.
Other Noncurrent Assets — Other noncurrent assets consist of cash deposits related to the deductibles on our workers’ compensation insurance policies, deferred compensation plan investments, deferred mobilization costs on long-term drilling contracts, and intangible assets.
Other Accrued Expenses — Our other accrued expenses include accruals for items such as property taxes, sales taxes, and professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.
Other Noncurrent Liabilities — Our other noncurrent liabilities consist of the noncurrent portion of liabilities associated with our long-term compensation plans, deferred lease liabilities, and the noncurrent portion of deferred mobilization revenues.
Related-Party Transactions — During the three months ended March 31, 2018 and 2017, the Company paid approximately $67,000 and $17,000, respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman’s two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.

2.    Revenue from Contracts with Customers
Our production services business segments earn revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders or other contractual arrangements with the client. Production services jobs are generally short-term (less than 30 days) and are charged at current market rates for the labor, equipment and materials necessary to complete the job. Production services jobs are varied in nature, but typically represent a single performance obligation, either for a particular job, a series of distinct jobs, or a period of time during which we stand ready to provide services as our client needs them. Revenue is recognized for these services over time, as the services are performed.
Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. We provide the drilling rig, crew and supplies necessary to operate the rig. Contract modifications that extend the term of a dayrate contract are generally accounted for prospectively as a separate dayrate contract. We account for our services provided under daywork contracts as a single performance obligation comprised of a series of distinct time increments which are satisfied over time. Accordingly, dayrate revenues are recognized in the period during which the services are performed.
With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service and are recognized ratably over the related contract term.
The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced (or no) payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.
The upfront costs that we incur to mobilize the drilling rig to our client’s initial drilling site are capitalized and recognized ratably over the term of the related contract, including any contracted renewal or extension periods, which is our estimate of the period during which we expect to benefit from the cost of mobilizing the rig. Costs associated with the final demobilization at the end of the contract term are expensed when incurred, when the demobilization activity is performed.
We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues, many of which are variable, or dependent upon the activity that is actually performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments.
All of our revenues are recognized net of sales taxes, when applicable.
Contract Asset and Liability Balances and Contract Cost Assets
Contract asset and contract liability balances relate to demobilization and mobilization revenues, respectively. Demobilization revenue that we expect to receive is recognized ratably over the related contract term, but invoiced upon completion of the demobilization activity. Mobilization revenue which is typically collected upon the completion of the initial mobilization activity is deferred and recognized ratably over the related contract term. Contract asset and liability balances are netted at the contract level, with the net current and noncurrent portions separately classified in our condensed consolidated balance sheets, and referred to herein as “deferred revenues.”
Contract cost assets represent the costs associated with the initial mobilization required in order to fulfill the contract, which are deferred and recognized ratably over the period during which we expect to benefit from the mobilization, or the period during which we expect to satisfy the performance obligations of the related contract. Contract cost assets are presented as either current or noncurrent, according to the duration of the original contract to which it relates, and referred to herein as “deferred costs.”
Our current and noncurrent deferred revenues and costs as of March 31, 2018 and January 1, 2018 were as follows (amounts in thousands):
 
March 31, 2018
 
January 1, 2018
Current deferred revenues
$
1,178

 
$
1,287

Current deferred costs
845

 
1,072

 
 
 
 
Noncurrent deferred revenues
$
712

 
$
174

Noncurrent deferred costs
1,700

 
1,177

The changes in deferred revenue and cost balances during the three months ended March 31, 2018 are primarily related to the amortization of deferred revenues and costs during the period, as well as the increase in deferred mobilization revenue and cost balances for the deployment of one international rig during the first quarter under a new term contract. Amortization of deferred revenues and costs during the three months ended March 31, 2018 and 2017 were as follows (amounts in thousands):
 
Three months ended March 31,
 
2018
 
2017
Amortization of deferred revenues
$
499

 
$
776

Amortization of deferred costs
463

 
1,467

As of March 31, 2018, all 16 of our domestic drilling rigs are operating under daywork contracts, 14 of which are term contracts, and seven of our eight international drilling rigs are operating under term daywork contracts. The term contracts for our international drilling rigs are cancelable by our clients without penalty, although the contracts require 30 days notice

7




and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice, but typically do not include a required payment for demobilization services. Revenues associated with the initial mobilization and/or demobilization of drilling rigs under cancelable contracts are deferred and recognized ratably over the anticipated duration of the original contract, which is the period during which we expect our client to benefit from the mobilization of the rig, and represents a separate performance obligation because the payment for mobilization and/or demobilization creates a material right to our client during the cancelable period, for which the transaction price is allocated to the optional goods and services expected to be provided.
Remaining Performance Obligations
We have elected to apply the practical expedients in ASC Topic 606 which allow entities to omit disclosure of (i) the transaction price allocated to the remaining performance obligations associated with short-term contracts, and (ii) the estimated variable consideration related to wholly unsatisfied performance obligations, or to distinct future time increments within a series of performance obligations. Therefore, we have not disclosed the remaining amount of fixed mobilization revenue (or estimated future variable demobilization revenue) associated with short-term contracts, and we have not disclosed an estimate of the amount of future variable dayrate drilling revenue. However, the amount of fixed mobilization revenue associated with remaining performance obligations is reflected in the net unamortized balance of deferred mobilization revenues, which is presented in both current and noncurrent portions in our condensed consolidated balance sheet.
Disaggregation of Revenue
ASC Topic 606 requires disclosure of the disaggregation of revenue into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. We believe the disclosure of revenues by operating segment achieves the objective of this disclosure requirement. Therefore, see Note 9, Segment Information, for the disaggregation of revenues by operating segment, which reflects the disaggregation of revenues by the type of services provided and by geography (international versus domestic).
Impact of ASC Topic 606 on Financial Statement Line Items and Disclosures
Our revenue recognition pattern under ASC Topic 606 is similar to revenue recognition under the previous accounting guidance, except for: (i) the timing of recognition of demobilization revenues which are estimated and recognized ratably over the term of the related contract under ASC Topic 606, but were previously not recognized until the activity was performed under previous guidance; (ii) the timing of recognition of mobilization revenues and costs which are recognized over the applicable amortization period beginning when the initial mobilization of the rig is completed, but which, under previous guidance, we recognized over the related contract term beginning when the initial mobilization activity commenced, (iii) the timing of recognition of mobilization costs which are deferred and recognized ratably over the expected period of benefit, but which, under previous guidance, we recognized ratably over the term of the initial contract; and (iv) presentation of mobilization costs which are presented as either current or noncurrent according to the duration of the original contract to which it relates under ASC Topic 606, but which we bifurcated and presented both current and noncurrent portions in separate line items under previous guidance.
These differences have not had a material impact on our condensed consolidated financial position or results of operations as of and for the three months ended March 31, 2018. Additionally, we have determined that any disclosures required by ASC Topic 606 which are not presented herein are either not applicable, or are not material.
3.    Property and Equipment
Capital Expenditures — Our capital expenditures were $14.6 million and $27.6 million during the three months ended March 31, 2018 and 2017, respectively. Capital expenditures during the three months ended March 31, 2018 primarily related to the expansion of our wireline and coiled tubing fleets, upgrades and refurbishments to our international drilling rigs, and routine equipment and fleet maintenance. Capital expenditures during the three months ended March 31, 2017 primarily related to the acquisition of 20 well servicing rigs, upgrades to drilling rigs and other new drilling equipment.
At March 31, 2018, capital expenditures incurred for property and equipment not yet placed in service was $9.0 million, primarily related to installments on the purchase of two coiled tubing units and one wireline unit and scheduled refurbishments of various drilling and production services equipment. At December 31, 2017, property and equipment not yet placed in service was $6.8 million, primarily related to routine refurbishments on one international drilling rig in preparation for its

8




deployment in 2018, installments on the purchase of three wireline units and one coiled tubing unit, and scheduled refurbishments on drilling and production services equipment.
Gain/Loss on Disposition of Property — During the three months ended March 31, 2018 and 2017, we recognized net gains of $0.3 million and $0.5 million, respectively, on the disposition of various property and equipment, including the sale of six wireline units and one drilling rig, which was previously held for sale, in the first quarter of 2018.
Assets Held for Sale — As of March 31, 2018 and December 31, 2017, our condensed consolidated balance sheet reflects assets held for sale of $6.1 million and $6.6 million, respectively, which primarily represents the fair value of two domestic SCR drilling rigs (three at December 31, 2017) and one domestic mechanical drilling rig, as well as other drilling equipment, two wireline units and one coiled tubing unit and spare equipment.
Impairments We evaluate for potential impairment of long-lived assets when indicators of impairment are present, which may include, among other things, significant adverse changes in industry trends (including revenue rates, utilization rates, oil and natural gas market prices, and industry rig counts). Beginning in late 2014, oil prices declined significantly resulting in a downturn in our industry that persisted through 2016, affecting both drilling and production services. Despite the recovery in commodity prices that began in late 2016 and continued through 2017, we continued to monitor all indicators of potential impairments in accordance with ASC Topic 360, Property, Plant and Equipment, and concluded there are no triggers present that require impairment testing as of March 31, 2018. The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment.
4.
Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform
Valuation Allowances on Deferred Tax Assets
As of March 31, 2018, we had $94.3 million and $12.3 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 consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
In performing this analysis as of March 31, 2018 in accordance with ASC Topic 740, Income Taxes, we assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of negative evidence evaluated is the cumulative loss incurred during previous years. Such negative evidence limits the ability to consider other positive evidence that is subjective, such as projections for taxable income in future years. As a result, we would recognize a benefit only to the extent that reversals of deferred income tax liabilities are expected to generate taxable income in each relevant jurisdiction in future periods which would offset our deferred tax assets.
Our domestic net operating losses generated through 2017 have a 20 year carryforward period and can be used to offset future domestic taxable income until their expiration, beginning in 2030, with the latest expiration in 2037. Losses generated after 2017 are limited in usage to 80% of taxable income (pursuant to the Tax Reform Act mentioned below). The majority of our foreign net operating losses generated through 2016 have an indefinite carryforward period, while losses generated after 2016 have a carryforward period of 12 years. As of March 31, 2018, we have a valuation allowance that fully offsets our foreign and U.S. federal deferred tax assets.
During the three months ended March 31, 2018 and 2017, we provided valuation allowance adjustments on deferred tax assets of $4.2 million and $9.8 million, respectively. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate. The amount of the deferred tax asset considered realizable, however, would increase if cumulative losses are no longer present and additional weight is given to subjective evidence in the form of projected future taxable income.
Recently Enacted Tax Reform
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Act”) was enacted. The legislation significantly changes U.S. tax law by, among other things, permanently reducing the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21%, repealing the alternative minimum tax (AMT), implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries, limiting the current deductibility of net

9




interest expense in excess of 30% of adjusted taxable income, and limiting net operating losses generated after 2017 to 80% of taxable income.
Territorial Tax SystemTo minimize tax base erosion with a territorial tax system, beginning in 2018, the Tax Reform Act provides for a new global intangible low-taxed income (GILTI) provision. Under the GILTI provision, certain foreign subsidiary earnings in excess of an allowable return on the foreign subsidiary’s tangible assets are included in U.S. taxable income. We are now subject to GILTI, but have not yet triggered an income inclusion as of March 31, 2018. Any future inclusion is expected to be offset by net operating loss carry forwards in the U.S. We are still evaluating, pending further interpretive guidance, whether to make a policy election to treat the GILTI tax as a period expense or to provide U.S. deferred taxes on foreign temporary differences that are expected to generate GILTI income when they reverse in future years.
Limitation on Interest Expense DeductionThe new limitation on interest expense resulted in a $8.1 million disallowance for the period ended March 31, 2018; however, this adjustment is offset fully by our net operating loss carry forwards. The disallowed interest has an indefinite carry forward period and any limitations on the utilization of this interest expense carryforward have been factored into our valuation allowance analysis.
Limitation on Future Net Operating Losses DeductionNet operating losses generated after 2017 are carried forward indefinitely and are limited to 80% of taxable income. Net operating losses generated prior to 2018 continue to be carried forward for 20 years and have no 80% limitation on utilization.
Measurement PeriodGiven the significance of the legislation, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used when accounting for business combinations. However, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 summarizes a three-step process to be applied at each reporting period to account for and qualitatively disclose: (1) the effects of the change in tax law for which accounting is complete; (2) provisional amounts (or adjustments to provisional amounts) for the effects of the tax law where accounting is not complete, but that a reasonable estimate has been determined; and (3) a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the Tax Reform Act.
Our accounting is complete as of March 31, 2018 and December 31, 2017 as related to the re-measurement of deferred taxes to the new tax rate of 21%, repeal of the AMT, mandatory repatriation, limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, and limitation of net operating losses generated after 2017 to 80% of taxable income. With respect to the new GILTI provision, we are awaiting further interpretive guidance regarding the possible application of deferred taxes to GILTI.
5.     Debt
Our debt consists of the following (amounts in thousands):
 
March 31, 2018
 
December 31, 2017
Senior secured term loan
$
175,000

 
$
175,000

Senior notes
300,000

 
300,000

 
475,000

 
475,000

Less unamortized discount (based on imputed interest rate of 10.44%)
(3,214
)
 
(3,387
)
Less unamortized debt issuance costs
(9,447
)
 
(9,948
)
 
$
462,339

 
$
461,665


10




Senior Secured Term Loan
Our senior secured term loan (the “Term Loan”) entered into on November 8, 2017 provided for one drawing in the amount of $175 million, net of a 2% original issue discount. Proceeds from the issuance of the Term Loan were used to repay the entire outstanding balance under our Revolving Credit Facility, plus fees and accrued and unpaid interest, as well as the fees and expenses associated with entering into the Term Loan and ABL Facility, which is further described below. The remainder of the proceeds are available to be used for other general corporate purposes.
The Term Loan is not subject to amortization payments of principal. Interest on the principal amount accrues at the LIBOR rate or the base rate as defined in the agreement, at our option, plus an applicable margin of 7.75% and 6.75%, respectively. The Term Loan is set to mature on November 8, 2022, or earlier, subject to certain circumstances as described in the agreement, and including an earlier maturity date if the outstanding balance of the Senior Notes exceeds $15.0 million on December 14, 2021, at which time the Term Loan would then mature. However, the Term Loan may be prepaid, at our option, at any time, in whole or in part, subject to a minimum of $5 million, and subject to a declining call premium as defined in the agreement.
The Term Loan contains a financial covenant requiring the ratio of (i) the net orderly liquidation value of our fixed assets (based on appraisals obtained as required by our lenders), on a consolidated basis, in which the lenders under the Term Loan maintain a first priority security interest, plus proceeds of asset dispositions not required to be used to effect a prepayment of the Term Loan to (ii) the outstanding principal amount of the Term Loan, to be at least equal to 1.50 to 1.00 as of any June 30 or December 31 of any calendar year through maturity.
The Term Loan contains customary mandatory prepayments from the proceeds of certain transactions including certain asset dispositions and debt issuances, and has additional customary restrictions that, among other things, and subject to certain exceptions, limit our ability to:
incur additional debt;
incur or permit liens on assets;
make investments and acquisitions;
consolidate or merge with another company;
engage in asset sales; and
pay dividends or make distributions.
In addition, the Term Loan contains customary events of default, upon the occurrence and during the continuation of any of which the applicable margin would increase by 2% per year, including without limitation:
payment defaults;
covenant defaults;
material breaches of representations or warranties;
event of default under, or acceleration of, other material indebtedness;
bankruptcy or insolvency;
material judgments against us;
failure of any security document supporting the Term Loan; and
change of control.
Our obligations under the Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our domestic assets, in each case, subject to certain exceptions and permitted liens.

11




Asset-based Lending Facility
In addition to entering into the Term Loan, on November 8, 2017, we also entered into a senior secured revolving asset-based credit facility (the “ABL Facility”) providing for borrowings in the aggregate principal amount of up to $75 million, subject to a borrowing base and including a $30 million sub-limit for letters of credit. The ABL Facility bears interest, at our option, at the LIBOR rate or the base rate as defined in the ABL Facility, plus an applicable margin ranging from 1.75% to 3.25%, based on average availability on the ABL Facility. The ABL Facility requires a commitment fee due monthly based on the average monthly unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a monthly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. The ABL Facility is generally set to mature 90 days prior to the maturity of the Term Loan, subject to certain circumstances, including the future repayment, extinguishment or refinancing of our Term Loan and/or Senior Notes prior to their respective maturity dates. Availability under the ABL Facility is determined by reference to a borrowing base as defined in the agreement, generally comprised of a percentage of our accounts receivable and inventory.
We have not drawn upon the ABL Facility to date. As of March 31, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $56.6 million. Borrowings available under the ABL Facility are available for general corporate purposes and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. Additionally, if our availability under the ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month basis.
The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to:
declare dividends and make other distributions;
issue or sell certain equity interests;
optionally prepay, redeem or repurchase certain of our subordinated indebtedness;
make loans or investments (including acquisitions);
incur additional indebtedness or modify the terms of permitted indebtedness;
grant liens;
change our business or the business of our subsidiaries;
merge, consolidate, reorganize, recapitalize, or reclassify our equity interests;
sell our assets, and
enter into certain types of transactions with affiliates.
Our obligations under the ABL Facility are guaranteed by us and our domestic subsidiaries, subject to certain exceptions, and are secured by (i) a first-priority perfected security interest in all inventory and cash, and (ii) a second-priority perfected security in substantially all of our tangible and intangible assets, in each case, subject to certain exceptions and permitted liens.
Senior Notes
In 2014, we issued $300 million of unregistered senior notes at face value, with a coupon interest rate of 6.125% that are due in 2022 (the “Senior Notes”). The 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 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 “Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the Indenture) thereon to the date of redemption.
In accordance with a registration rights agreement with the holders of our 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. 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

12




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 us and certain of our subsidiaries, subject to certain exceptions, in 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 or their assets;
enter into sale and leaseback transactions;
sell or transfer assets;
borrow, pay dividends, 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 11, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)
Debt Issuance Costs and Original Issue Discount
Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the effective interest method over the term of the Senior Notes which mature in March 2022. The original issue discount and costs incurred in connection with the issuance of the Term Loan were capitalized and are being amortized using the effective interest method over the expected term of the agreement. Costs incurred in connection with the ABL Facility were capitalized and are being amortized using the straight-line method over the expected term of the agreement.
6.
Fair Value of Financial Instruments
The FASB’s Accounting Standards Codification (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. Our financial instruments consist primarily of cash, trade and other receivables, trade payables, phantom stock unit awards 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. At March 31, 2018 and December 31, 2017, the aggregate estimated fair value of our phantom stock unit awards was $8.5 million and $6.1 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $4.0 million and $3.6 million, respectively. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 8, Stock-Based Compensation Plans.
The fair value of our Senior Notes is estimated based on recent observable market prices for our debt instruments, which are defined by ASC Topic 820 as Level 2 inputs. The fair value of our Term Loan is based on estimated market pricing for our debt instrument, which is defined by ASC Topic 820 as using Level 3 inputs which are unobservable and therefore more likely to be affected by changes in assumptions. The following table presents supplemental fair value information and carrying value for our debt, net of discount and debt issuance costs (amounts in thousands):
 
 
 
March 31, 2018
 
December 31, 2017
 
Hierarchy Level
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Senior notes
2
 
$
296,378

 
$
259,906

 
$
296,181

 
$
243,948

Senior secured term loan
3
 
165,961

 
$
182,000

 
165,484

 
171,613

 
 
 
$
462,339

 
$
441,906

 
$
461,665

 
$
415,561


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7.
Earnings (Loss) Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations (amounts in thousands, except per share data):
 
Three months ended March 31,
 
2018
 
2017
Numerator (both basic and diluted):
 
 
 
Net loss
$
(11,139
)
 
$
(25,124
)
Denominator:
 
 
 
Weighted-average shares (denominator for basic earnings (loss) per share)
77,606

 
77,072

Dilutive effect of outstanding stock options, restricted stock and restricted stock unit awards

 

Denominator for diluted earnings (loss) per share
77,606

 
77,072

Loss per common share - Basic
$
(0.14
)
 
$
(0.33
)
Loss per common share - Diluted
$
(0.14
)
 
$
(0.33
)
Potentially dilutive securities excluded as anti-dilutive
5,621

 
4,944

8.
Stock-Based Compensation Plans
We grant stock option and restricted stock awards with vesting based on time of service conditions. We grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We grant phantom stock unit awards with vesting based on time of service, performance and market conditions, which are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation since we expect to settle the awards in cash when they become vested.
We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic 718, and we recognize forfeitures when they occur. 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.
The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense recognized for phantom stock unit awards during the three months ended March 31, 2018 and 2017 (amounts in thousands):
 
Three months ended March 31,
 
2018
 
2017
Stock option awards
$
142

 
$
231

Restricted stock awards
113

 
112

Restricted stock unit awards
1,004

 
984

 
$
1,259

 
$
1,327

Phantom stock unit awards
$
430

 
$
100

Stock Option Awards
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.

14




We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended March 31, 2018. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the options granted during the three months ended March 31, 2017:
 
Three months ended March 31,
 
2017
Expected volatility
76
%
Risk-free interest rates
2.1
%
Expected life in years
5.86

Options granted
268,185
Grant-date fair value
$4.28
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.
Restricted Stock and Restricted Stock Unit Awards
We grant restricted stock awards that vest over a one-year period with a fair value based on the closing price of our common stock on the date of the grant. 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. We did not grant any restricted stock awards during the three months ended March 31, 2018 or 2017.
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.
The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the three months ended March 31, 2018 and 2017:
 
Three months ended March 31,
 
2018
 
2017
Time-based RSUs:
 
 
 
Time-based RSUs granted
788,377

 
66,728

Weighted-average grant-date fair value
$
3.85

 
$
6.33

Performance-based RSUs:
 
 
 
Performance-based RSUs granted

 
563,469

Weighted-average grant-date fair value
$

 
$
7.75

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.

15




Approximately half of the performance-based RSUs outstanding are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for equity awards with a market condition is reduced only for actual 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 our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, 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 2018, we determined that 106% of the target number of shares granted during 2015 were actually earned based on the Company’s achievement of the performance measures as described above. As of March 31, 2018, we estimate that the achievement level for our outstanding performance-based RSUs granted in 2017 will be approximately 100% of the predetermined performance conditions.
Phantom Stock Unit Awards
In 2016 and 2018, we granted 1,268,068 and 1,188,216 phantom stock unit awards with weighted-average grant-date fair values of $1.35 and $3.06 per share, respectively. These awards cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the respective three-year performance periods, and each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to a maximum of $8.08 and $9.66 (which is four and three times the grant date stock price), respectively.
The fair value of these awards is measured using inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures. For the 2016 phantom stock unit awards, half are subject to a market condition based on relative total shareholder return, and therefore the fair values of these awards are measured using a Monte Carlo simulation model, which incorporates the estimate of our relative total shareholder return achievement level. The remaining 2016 phantom stock unit awards are subject to performance conditions, based on our relative EBITDA and EBITDA return on capital employed, and the fair values of these awards are measured using a Black-Scholes pricing model. We estimate our relative weighted average EBITDA and EBITDA return on capital achievement level for the 2016 phantom stock unit awards to be 165% at March 31, 2018.
For the 2018 phantom stock unit awards, half are based on relative total shareholder return, and the remaining half are based on relative EBITDA return on capital, both of which are subject to market conditions, and therefore, their fair values are measured using a Monte Carlo simulation model which generates a fair value that incorporates the relative estimated achievement levels. We estimate our relative EBITDA return on capital achievement level for the 2018 phantom stock unit awards to be 100% at March 31, 2018.
These awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our condensed consolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. We estimate that a hypothetical increase of $1 in the market price of our common stock as of March 31, 2018, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $1.5 million, which represents the hypothetical increase in fair value of the liability for all outstanding phantom stock unit awards which would be recognized as compensation expense in our condensed consolidated statement of operations.

16




9.
Segment Information
We have five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services). We revised our segments as of December 31, 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. The following financial information presented as of and for the years ended March 31, 2018 and 2017 have been restated to reflect this change.
Our domestic and international drilling services segments provide contract land drilling services to a diverse group of exploration and production companies through our four 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.
Our well servicing, wireline services and coiled tubing services segments provide a range of production services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast region, both onshore and offshore.
The following tables set forth certain financial information for each of our segments and corporate (amounts in thousands):
 
As of and for the three months ended March 31,
 
2018
 
2017
Revenues:
 
 
 
Domestic drilling
$
35,926

 
$
28,345

International drilling
17,611

 
10,671

Drilling services
53,537

 
39,016

Well servicing
21,114

 
18,734

Wireline services
56,601

 
32,546

Coiled tubing services
13,226

 
5,461

Production services
90,941

 
56,741

Consolidated revenues
$
144,478

 
$
95,757

 
 
 
 
Operating costs:
 
 
 
Domestic drilling
$
20,898

 
$
19,509

International drilling
12,961

 
7,598

Drilling services
33,859

 
27,107

Well servicing
15,570

 
14,037

Wireline services
42,486

 
25,946

Coiled tubing services
10,851

 
5,638

Production services
68,907

 
45,621

Consolidated operating costs
$
102,766

 
$
72,728

 
 
 
 
Gross margin:
 
 
 
Domestic drilling
$
15,028

 
$
8,836

International drilling
4,650

 
3,073

Drilling services
19,678

 
11,909

Well servicing
5,544

 
4,697

Wireline services
14,115

 
6,600

Coiled tubing services
2,375

 
(177
)
Production services
22,034

 
11,120

Consolidated gross margin
$
41,712

 
$
23,029


17




 
As of and for the three months ended March 31,
 
2018
 
2017
Identifiable Assets:
 
 
 
Domestic drilling
$
380,382

 
$
413,764

International drilling (1)
39,305

 
34,788

Drilling services
419,687

 
448,552

Well servicing
124,162

 
136,407

Wireline services
96,686

 
86,729

Coiled tubing services
30,824

 
25,340

Production services
251,672

 
248,476

Corporate
86,341

 
11,300

Consolidated identifiable assets
$
757,700

 
$
708,328

 
 
 
 
Depreciation and Amortization:
 
 
 
Domestic drilling
$
10,449

 
$
11,479

International drilling
1,447

 
1,622

Drilling services
11,896

 
13,101

Well servicing
4,920

 
5,012

Wireline services
4,608

 
4,453

Coiled tubing services
2,032

 
2,126

Production services
11,560

 
11,591

Corporate
291

 
300

Consolidated depreciation and amortization
$
23,747

 
$
24,992

 
 
 
 
Capital Expenditures:
 
 
 
Domestic drilling
$
2,758

 
$
9,466

International drilling
2,700

 
372

Drilling services
5,458

 
9,838

Well servicing
2,049

 
12,340

Wireline services
3,673

 
4,008

Coiled tubing services
3,164

 
1,280

Production services
8,886

 
17,628

Corporate
244

 
141

Consolidated capital expenditures
$
14,588

 
$
27,607

(1) 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.
The following table reconciles the consolidated gross margin of our segments reported above to loss from operations as reported on the condensed consolidated statements of operations (amounts in thousands):
 
Three months ended March 31,
 
2018
 
2017
Consolidated gross margin
$
41,712

 
$
23,029

Depreciation and amortization
(23,747
)
 
(24,992
)
General and administrative
(19,194
)
 
(17,744
)
Bad debt recovery
52

 
363

Gain on dispositions of property and equipment, net
335

 
471

Loss from operations
$
(842
)
 
$
(18,873
)

18




10.
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 $69.5 million relating to our performance under these bonds as of March 31, 2018.
We are currently undergoing sales and use tax audits for multi-year periods. As of March 31, 2018 and December 31, 2017, our accrued liability was $1.3 million and $1.2 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
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.
11.
Guarantor/Non-Guarantor Condensed Consolidating Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all existing 100% owned 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 March 31, 2018, 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 consolidating balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

19




CONDENSED CONSOLIDATING BALANCE SHEETS
(unaudited, in thousands)
 
March 31, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
66,509

 
$
(861
)
 
$
3,078

 
$

 
$
68,726

Restricted cash
2,000

 

 

 

 
2,000

Receivables, net of allowance
13,975

 
79,599

 
22,950

 

 
116,524

Intercompany receivable (payable)
(24,836
)
 
56,070

 
(31,234
)
 

 

Inventory

 
8,886

 
7,214

 

 
16,100

Assets held for sale

 
6,139

 

 

 
6,139

Prepaid expenses and other current assets
1,347

 
2,312

 
1,255

 

 
4,914

Total current assets
58,995

 
152,145

 
3,263

 

 
214,403

Net property and equipment
1,963

 
509,183

 
29,142

 

 
540,288

Investment in subsidiaries
591,031

 
21,748

 

 
(612,779
)
 

Deferred income taxes
39,090

 

 

 
(39,090
)
 

Other noncurrent assets
549

 
943

 
1,517

 

 
3,009

Total assets
$
691,628

 
$
684,019

 
$
33,922

 
$
(651,869
)
 
$
757,700

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
703

 
$
26,452

 
$
5,633

 
$

 
$
32,788

Deferred revenues

 
217

 
977

 

 
1,194

Accrued expenses
23,874

 
19,982

 
4,383

 

 
48,239

Total current liabilities
24,577

 
46,651

 
10,993

 

 
82,221

Long-term debt, less unamortized discount and debt issuance costs
462,339

 

 

 

 
462,339

Deferred income taxes

 
43,151

 

 
(39,090
)
 
4,061

Other noncurrent liabilities
4,525

 
3,186

 
1,181

 

 
8,892

Total liabilities
491,441

 
92,988

 
12,174

 
(39,090
)
 
557,513

Total shareholders’ equity
200,187

 
591,031

 
21,748

 
(612,779
)
 
200,187

Total liabilities and shareholders’ equity
$
691,628

 
$
684,019

 
$
33,922

 
$
(651,869
)
 
$
757,700

 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
72,258

 
$
(1,881
)
 
$
3,263

 
$

 
$
73,640

Restricted cash
2,008

 

 

 

 
2,008

Receivables, net of allowance
7

 
93,866

 
19,174

 
(42
)
 
113,005

Intercompany receivable (payable)
(24,836
)
 
51,532

 
(26,696
)
 

 

Inventory

 
7,741

 
6,316

 

 
14,057

Assets held for sale

 
6,620

 

 

 
6,620

Prepaid expenses and other current assets
1,238

 
3,193

 
1,798

 

 
6,229

Total current assets
50,675

 
161,071

 
3,855

 
(42
)
 
215,559

Net property and equipment
2,011

 
521,080

 
26,532

 

 
549,623

Investment in subsidiaries
596,927

 
20,095

 

 
(617,022
)
 

Deferred income taxes
38,028

 

 

 
(38,028
)
 

Other noncurrent assets
496

 
788

 
403

 

 
1,687

Total assets
$
688,137

 
$
703,034

 
$
30,790

 
$
(655,092
)
 
$
766,869

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
286

 
$
24,174

 
$
5,078

 
$

 
$
29,538

Deferred revenues

 
97

 
808

 

 
905

Accrued expenses
12,504

 
37,814

 
4,195

 
(42
)
 
54,471

Total current liabilities
12,790

 
62,085

 
10,081

 
(42
)
 
84,914

Long-term debt, less unamortized discount and debt issuance costs
461,665

 

 

 

 
461,665

Deferred income taxes

 
41,179

 

 
(38,028
)
 
3,151

Other noncurrent liabilities
3,586

 
2,843

 
614

 

 
7,043

Total liabilities
478,041

 
106,107

 
10,695

 
(38,070
)
 
556,773

Total shareholders’ equity
210,096

 
596,927

 
20,095

 
(617,022
)
 
210,096

Total liabilities and shareholders’ equity
$
688,137

 
$
703,034

 
$
30,790

 
$
(655,092
)
 
$
766,869


20




CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(unaudited, in thousands)

 
Three months ended March 31, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
126,867

 
$
17,611

 
$

 
$
144,478

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
89,809

 
12,957

 

 
102,766

Depreciation and amortization
291

 
22,009

 
1,447

 

 
23,747

General and administrative
6,238

 
12,539

 
522

 
(105
)
 
19,194

Bad debt recovery

 
(52
)
 

 

 
(52
)
Gain on dispositions of property and equipment, net

 
(321
)
 
(14
)
 

 
(335
)
Intercompany leasing

 
(1,215
)
 
1,215

 

 

Total costs and expenses
6,529

 
122,769

 
16,127

 
(105
)
 
145,320

Income (loss) from operations
(6,529
)
 
4,098

 
1,484

 
105

 
(842
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
4,549

 
1,653

 

 
(6,202
)
 

Interest expense, net of interest capitalized
(9,516
)
 

 
3

 

 
(9,513
)
Other
2

 
219

 
388

 
(105
)
 
504

Total other income (expense)
(4,965
)
 
1,872

 
391

 
(6,307
)
 
(9,009
)
Income (loss) before income taxes
(11,494
)
 
5,970

 
1,875

 
(6,202
)
 
(9,851
)
Income tax (expense) benefit 1
355

 
(1,421
)
 
(222
)
 

 
(1,288
)
Net income (loss)
$
(11,139
)
 
$
4,549

 
$
1,653

 
$
(6,202
)
 
$
(11,139
)
 
 
 
Three months ended March 31, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
85,086

 
$
10,671

 
$

 
$
95,757

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
65,135

 
7,593

 

 
72,728

Depreciation and amortization
301

 
23,069

 
1,622

 

 
24,992

General and administrative
5,829

 
11,603

 
450

 
(138
)
 
17,744

Bad debt recovery

 
(363
)
 

 

 
(363
)
Gain on dispositions of property and equipment, net

 
(456
)
 
(15
)
 

 
(471
)
Intercompany leasing

 
(1,215
)
 
1,215

 

 

Total costs and expenses
6,130

 
97,773

 
10,865

 
(138
)
 
114,630

Income (loss) from operations
(6,130
)
 
(12,687
)
 
(194
)
 
138

 
(18,873
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(8,585
)
 
(648
)
 

 
9,233

 

Interest expense, net of interest capitalized
(6,016
)
 
(43
)
 

 

 
(6,059
)
Other
16

 
213

 
(235
)
 
(138
)
 
(144
)
Total other income (expense)
(14,585
)
 
(478
)
 
(235
)
 
9,095

 
(6,203
)
Income (loss) before income taxes
(20,715
)
 
(13,165
)
 
(429
)
 
9,233

 
(25,076
)
Income tax (expense) benefit 1
(4,409
)
 
4,580

 
(219
)
 

 
(48
)
Net income (loss)
$
(25,124
)
 
$
(8,585
)
 
$
(648
)
 
$
9,233

 
$
(25,124
)
 
 
 
 
 
 
 
 
 
 
1  The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.





21




CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 
Three months ended March 31, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(16,310
)
 
$
19,012

 
$
2,355

 
$

 
$
5,057

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(179
)
 
(8,978
)
 
(2,500
)
 

 
(11,657
)
Proceeds from sale of property and equipment

 
1,283

 

 

 
1,283

Proceeds from insurance recoveries

 
508

 
15

 

 
523

 
(179
)
 
(7,187
)
 
(2,485
)
 

 
(9,851
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Debt issuance costs
(33
)
 

 

 

 
(33
)
Purchase of treasury stock
(95
)
 

 

 

 
(95
)
Intercompany contributions/distributions
10,860

 
(10,805
)
 
(55
)
 

 

 
10,732

 
(10,805
)
 
(55
)
 

 
(128
)
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
(5,757
)
 
1,020

 
(185
)
 

 
(4,922
)
Beginning cash, cash equivalents and restricted cash
74,266

 
(1,881
)
 
3,263

 

 
75,648

Ending cash, cash equivalents and restricted cash
$
68,509

 
$
(861
)
 
$
3,078

 
$

 
$
70,726

 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(14,236
)
 
$
(8,233
)
 
$
649

 
$

 
$
(21,820
)
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(127
)
 
(24,013
)
 
(813
)
 
270

 
(24,683
)
Proceeds from sale of property and equipment

 
7,387

 
31

 
(270
)
 
7,148

Proceeds from insurance recoveries

 
3,119

 

 

 
3,119

 
(127
)
 
(13,507
)
 
(782
)
 

 
(14,416
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Debt repayments
(6,305
)
 

 

 

 
(6,305
)
Proceeds from issuance of debt
40,000

 

 

 

 
40,000

Purchase of treasury stock
(363
)
 

 

 

 
(363
)
Intercompany contributions/distributions
(21,598
)
 
21,653

 
(55
)
 

 

 
11,734

 
21,653

 
(55
)
 

 
33,332

 
 
 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
(2,629
)
 
(87
)
 
(188
)
 

 
(2,904
)
Beginning cash and cash equivalents
9,898

 
(764
)
 
1,060

 

 
10,194

Ending cash and cash equivalents
$
7,269

 
$
(851
)
 
$
872

 
$

 
$
7,290

 
 



ITEM 2.
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 made in good faith 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 debt agreements, including our senior secured term loan, our senior secured revolving asset-based credit facility, and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing units and wireline units within the industry, the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units, 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 and in our Annual Report on Form 10-K for the year ended December 31, 2017, 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. Other unpredictable or unknown factors 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) recognize 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.

22




Company Overview
Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (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.
Drilling Services— Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our fleet are currently deployed through our division offices in the following regions:
 
 
Rig Count
Domestic drilling
 
 
Marcellus/Utica
 
6

Eagle Ford
 
1

Permian Basin
 
7

Bakken
 
2

International drilling
 
8

 
 
24

Production Services— Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast region, both onshore and offshore.
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 March 31, 2018, we have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 10 locations, mostly in the Gulf Coast states, as well as in Arkansas, North Dakota, and Colorado.
Wireline Services. Oil and gas exploration and production companies require wireline services to better understand the reservoirs they are drilling or producing, and use logging services to accurately characterize reservoir rocks and fluids. To complete a cased-hole 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 in addition to a range of other mechanical services that are needed in order to place equipment in or retrieve equipment or debris from the wellbore, install bridge plugs and control pressure. As of March 31, 2018, we have a fleet of 108 wireline units in 16 operating locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.
Coiled Tubing Services. Coiled tubing is another important element of the well servicing industry that allows operators to continue production during service operations on a well under pressure 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 March 31, 2018, our coiled tubing business consists of 10 onshore and four offshore coiled tubing units which are deployed through three operating locations that provide services in Texas, Louisiana, Wyoming and surrounding areas.

23




Pioneer Energy Services Corp. was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Over the last 15 years, we have significantly expanded and transformed our business through acquisitions and organic growth. Our business is comprised of two business lines Drilling Services and Production Services. We report our Drilling Services business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 9, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Pioneer Energy Services Corp.’s corporate office is located at 1250 N.E. 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.
Market Conditions in Our Industry
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 is primarily driven by current and expected oil and natural gas prices.
Our business is influenced substantially by exploration and production companies’ spending that is generally categorized as either a capital expenditure or an operating expenditure. Capital expenditures for the drilling and completion of exploratory and development 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, operating expenditures for the maintenance of existing wells, for which a range of production services are required in order to maintain production, are relatively more stable and predictable.
Drilling and production services have historically trended similarly in response to fluctuations in commodity prices. However, because exploration and production companies often adjust their budgets for exploration and development 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 ongoing expenditures that are necessary to maintain production. Additionally, within the range of production services businesses, those that derive more revenue from production related activity, as opposed to completion of new wells, tend to be less affected by fluctuations in commodity prices and temporary reductions in industry activity.
However, in a severe downturn that is prolonged, both operating and capital expenditures are significantly reduced, and the demand for all our service offerings is significantly impacted. After a prolonged downturn, among the production services, the demand for completion-oriented services generally improves first, as exploration and production companies begin to complete wells that were previously drilled but not completed during the downturn, and to complete newly drilled wells as the demand for drilling services improves during recovery.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends in our industry, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2017.
Market Conditions — Our industry is currently experiencing a recovery from a severe down cycle that began in late 2014 and which persisted through 2016, during which WTI oil prices dipped below $30 in early 2016. A modest recovery in commodity prices began in the latter half of 2016 with WTI oil prices steadily increasing from $48 per barrel as of June 30, 2016 to approximately $60 per barrel at the end of 2017, and reaching $65 per barrel at March 31, 2018.

24




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.
a3yearspotpricesandrigcounts.jpg
The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:
a1yearspotpricesandrigcounts.jpg
With the increases in commodity prices that began in late 2016, we experienced a resulting increase in activity and revenue rates for our services during 2017 and 2018.
Our well servicing rig hours and coiled tubing revenue days during the quarter ended March 31, 2018 increased by 8% and 22%, respectively, as compared to the first quarter of 2017, while an increase in the proportion of the work performed attributable to completion-related activity and larger diameter coiled tubing services during this same period resulted in significant increases in our average revenues for wireline and coiled tubing services performed (on a per job and day basis, respectively).
We began 2017 with utilization of our domestic fleet at 81% and four rigs working in Colombia. Since then, utilization of our domestic fleet has increased to 100%, and seven of our eight international rigs are currently earning revenues under term contracts. As of March 31, 2018, 23 of our 24 drilling rigs are earning revenues, 21 of which are under term contracts, which if not canceled or renewed prior to the end of their terms, will expire as follows:
 
Spot Market Contracts
 
 
 
Term Contract Expiration by Period
 
 
Total Term Contracts
 
Within
6 Months
 
6 Months
to 1 Year
 
1 Year to
18 Months