10-Q 1 form10-qxq22018.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 June 30, 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 July 13, 2018, there were 78,214,550 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
 
June 30,
2018
 
December 31,
2017
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
61,517

 
$
73,640

Restricted cash
2,000

 
2,008

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
84,591

 
79,592

Unbilled receivables
22,951

 
16,029

Insurance recoveries
15,014

 
13,874

Other receivables
4,270

 
3,510

Inventory
17,719

 
14,057

Assets held for sale
6,433

 
6,620

Prepaid expenses and other current assets
6,710

 
6,229

Total current assets
221,205

 
215,559

Property and equipment, at cost
1,100,291

 
1,093,635

Less accumulated depreciation
567,014

 
544,012

Net property and equipment
533,277

 
549,623

Other noncurrent assets
2,562

 
1,687

Total assets
$
757,044

 
$
766,869

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
38,014

 
$
29,538

Deferred revenues
1,921

 
905

Accrued expenses:
 
 
 
Payroll and related employee costs
29,315

 
21,023

Insurance claims and settlements
14,702

 
13,289

Insurance premiums and deductibles
6,238

 
6,742

Interest
6,361

 
6,624

Other
7,732

 
6,793

Total current liabilities
104,283

 
84,914

Long-term debt, less unamortized discount and debt issuance costs
463,072

 
461,665

Deferred income taxes
3,429

 
3,151

Other noncurrent liabilities
3,569

 
7,043

Total liabilities
574,353

 
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; 78,214,550 and 77,719,021 shares outstanding at June 30, 2018 and December 31, 2017, respectively
7,900

 
7,835

Additional paid-in capital
548,461

 
546,158

Treasury stock, at cost; 789,532 and 630,688 shares at June 30, 2018 and December 31, 2017, respectively
(4,965
)
 
(4,416
)
Accumulated deficit
(368,705
)
 
(339,481
)
Total shareholders’ equity
182,691

 
210,096

Total liabilities and shareholders’ equity
$
757,044

 
$
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 June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(in thousands, except per share data)
 
 
 
 
 
 
 
 
Revenues
$
154,782

 
$
107,130

 
$
299,260

 
$
202,887

 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
Operating costs
114,197

 
79,059

 
216,963

 
151,787

Depreciation and amortization
23,287

 
24,740

 
47,034

 
49,732

General and administrative
24,829

 
16,112

 
44,023

 
33,856

Bad debt recovery, net of expense
(370
)
 
(226
)
 
(422
)
 
(589
)
Impairment
2,368

 
795

 
2,368

 
795

Gain on dispositions of property and equipment, net
(726
)
 
(621
)
 
(1,061
)
 
(1,092
)
Total costs and expenses
163,585

 
119,859

 
308,905

 
234,489

Loss from operations
(8,803
)
 
(12,729
)
 
(9,645
)
 
(31,602
)
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(9,642
)
 
(6,418
)
 
(19,155
)
 
(12,477
)
Other income (expense), net
44

 
73

 
548

 
(71
)
Total other expense, net
(9,598
)
 
(6,345
)
 
(18,607
)
 
(12,548
)
 
 
 
 
 
 
 
 
Loss before income taxes
(18,401
)
 
(19,074
)
 
(28,252
)
 
(44,150
)
Income tax (expense) benefit
249

 
(1,135
)
 
(1,039
)
 
(1,183
)
Net loss
$
(18,152
)
 
$
(20,209
)
 
$
(29,291
)
 
$
(45,333
)
 
 
 
 
 
 
 
 
Loss per common share - Basic
$
(0.23
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.59
)
 
 
 
 
 
 
 
 
Loss per common share - Diluted
$
(0.23
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.59
)
 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
77,944

 
77,377

 
77,776

 
77,225

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
77,944

 
77,377

 
77,776

 
77,225
















See accompanying notes to condensed consolidated financial statements.

3



PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Six months ended June 30,
 
2018
 
2017
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(29,291
)
 
$
(45,333
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
47,034

 
49,732

Allowance for doubtful accounts, net of recoveries
(422
)
 
(589
)
Gain on dispositions of property and equipment, net
(1,061
)
 
(1,092
)
Stock-based compensation expense
2,356

 
2,335

Amortization of debt issuance costs and discount
1,422

 
930

Impairment
2,368

 
795

Deferred income taxes
273

 
768

Change in other noncurrent assets
(199
)
 
299

Change in other noncurrent liabilities
(3,480
)
 
(1,563
)
Changes in current assets and liabilities:
 
 
 
Receivables
(12,368
)
 
(27,687
)
Inventory
(3,662
)
 
(2,151
)
Prepaid expenses and other current assets
(785
)
 
(403
)
Accounts payable
5,858

 
7,441

Deferred revenues
619

 
(244
)
Accrued expenses
8,463

 
465

Net cash provided by (used in) operating activities
17,125

 
(16,297
)
 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(31,485
)
 
(40,032
)
Proceeds from sale of property and equipment
2,225

 
7,748

Proceeds from insurance recoveries
541

 
3,119

Net cash used in investing activities
(28,719
)
 
(29,165
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
—

 
(12,305
)
Proceeds from issuance of debt
—

 
55,000

Proceeds from exercise of options
12

 
—

Purchase of treasury stock
(549
)
 
(533
)
Net cash provided by (used in) financing activities
(537
)
 
42,162

 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
(12,131
)
 
(3,300
)
Beginning cash, cash equivalents and restricted cash
75,648

 
10,194

Ending cash, cash equivalents and restricted cash
$
63,517

 
$
6,894

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
18,073

 
$
11,971

Income tax paid
$
1,789

 
$
630

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
2,440

 
$
1,952

 







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.
Our drilling services business segments provide contract land drilling services through three domestic divisions which are located in the Marcellus/Utica, Permian Basin and Eagle Ford, 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. All of our rigs are equipped with 1,500 horsepower or greater drawworks. 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
In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig which we expect to deploy in early 2019 to the Permian Basin.
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 Gulf Coast, Mid-Continent and Rocky Mountain states. The following table summarizes our current fleet count and composition for each of our production services business segments, including one coiled tubing unit which was delivered in early July:
 
550 HP
 
600 HP
 
Total
Well servicing rigs, by horsepower (HP) rating
113
 
12

 
125

 
 
 
 
 
 
 
Onshore
 
Offshore
 
Total
Wireline services units
104
 
—

 
104

Coiled tubing services units
9
 
2

 
11

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

5



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.
Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after June 30, 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 year periods 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.

6



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 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 recognize and present our revenues from drilling contracts (both lease and service components) as one revenue stream in our consolidated statements of operations. 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
Cash and Cash Equivalents — As of June 30, 2018, we had $50.1 million of cash equivalents, consisting of investments in highly-liquid money-market mutual funds. We had no cash equivalents at December 31, 2017.
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 six months ended June 30, 2018 and 2017, the Company paid approximately $120,000 and $70,000, 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.

7



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 June 30, 2018 and January 1, 2018 were as follows (amounts in thousands):
 
June 30, 2018
 
January 1, 2018
Current deferred revenues
$
1,921

 
$
1,287

Current deferred costs
633

 
1,072

 
 
 
 
Noncurrent deferred revenues
$
964

 
$
564

Noncurrent deferred costs
1,425

 
1,177


8



The changes in deferred revenue and cost balances during the three and six months ended June 30, 2018 are primarily related to the increase in deferred mobilization revenue and cost balances for the deployment of one international rig under a new term contract in the first quarter of 2018, an increase in deferred revenues associated with a prepayment made by one of our international clients, and decreases related to the amortization of deferred revenues and costs during the period. Amortization of deferred revenues and costs during the three and six months ended June 30, 2018 and 2017 were as follows (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Amortization of deferred revenues
$
542

 
$
521

 
$
1,041

 
$
1,297

Amortization of deferred costs
486

 
1,219

 
949

 
2,686

As of June 30, 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 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. 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, and constrained when appropriate, 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.

9



These differences have not had a material impact on our condensed consolidated financial position or results of operations as of and for the three and six months ended June 30, 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 $33.9 million and $42.0 million during the six months ended June 30, 2018 and 2017, respectively, which includes $0.1 million and $0.3 million, respectively, of capitalized interest costs incurred. Capital expenditures during the six months ended June 30, 2018 primarily related to various routine expenditures to maintain our fleets and purchase new support equipment, as well as the expansion of our wireline and coiled tubing fleets, vehicle fleet upgrades in all business segments, and capital projects to upgrade and refurbish certain of our international and domestic drilling rigs. Capital expenditures during the six months ended June 30, 2017 primarily related to the acquisition of 20 well servicing rigs, expansion of our wireline fleet, upgrades to drilling rigs and other new drilling equipment.
At June 30, 2018, capital expenditures incurred for property and equipment not yet placed in service was $14.4 million, primarily related to installments of $5.6 million on the purchase of two coiled tubing units, one of which was put into service in early July, as well as refurbishments and upgrades 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 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 six months ended June 30, 2018, we recognized net gains of $1.1 million 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. During the six months ended June 30, 2017, we recognized a net gain of $1.1 million on the disposition of property and equipment which was primarily related to the loss of drill pipe in operation, for which we were reimbursed by the client, gains on sales of vehicles which were used in our production services segments’ operations, and a gain on the disposal of two cranes that were damaged.
Assets Held for Sale — As of June 30, 2018, our condensed consolidated balance sheet reflects assets held for sale of $6.4 million, which primarily represents the fair value of two domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, six offshore wireline units and five coiled tubing units. All of the wireline units and three of the coiled tubing units were subsequently sold in July 2018. During the six months ended June 30, 2018 and 2017, we recognized impairment charges of $2.4 million and $0.8 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.
As of December 31, 2017, our condensed consolidated balance sheet reflects assets held for sale of $6.6 million, which primarily represents the fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, two offshore wireline units and one coiled tubing unit and other 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 June 30, 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 June 30, 2018, we had $95.2 million and $11.8 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

10



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 June 30, 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 federal 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 have an unlimited carryforward period and 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 June 30, 2018, we have a valuation allowance that fully offsets our foreign and domestic federal deferred tax assets.
During the three and six months ended June 30, 2018, we provided valuation allowance adjustments on deferred tax assets of $1.5 million and $5.7 million, respectively. During the three and six months ended June 30, 2017, we provided valuation allowance adjustments on deferred tax assets of $3.5 million and $13.2 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 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 System — To 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 June 30, 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 Deduction — The new limitation on interest expense resulted in a $14.1 million disallowance for the period ended June 30, 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 Deduction — Net 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 Period — Given 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,

11



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 June 30, 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):
 
June 30, 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 10.46%)
(3,036
)
 
(3,387
)
Less unamortized debt issuance costs
(8,892
)
 
(9,948
)
 
$
463,072

 
$
461,665

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.

12



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.
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 June 30, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $62.0 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.

13



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 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 and cash equivalents, trade and other receivables, trade payables, phantom stock unit awards and long-term debt.

14



The carrying value of cash and cash equivalents, 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 June 30, 2018 and December 31, 2017, the aggregate estimated fair value of our phantom stock unit awards was $18.3 million and $6.1 million, respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $10.1 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):
 
 
 
June 30, 2018
 
December 31, 2017
 
Hierarchy Level
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Senior notes
2
 
$
296,578

 
$
286,875

 
$
296,181

 
$
243,948

Senior secured term loan
3
 
166,494

 
$
181,781

 
165,484

 
171,613

 
 
 
$
463,072

 
$
468,656

 
$
461,665

 
$
415,561

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 June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Numerator (both basic and diluted):
 
 
 
 
 
 
 
Net loss
$
(18,152
)
 
$
(20,209
)
 
$
(29,291
)
 
$
(45,333
)
Denominator:
 
 
 
 
 
 
 
Weighted-average shares (denominator for basic earnings (loss) per share)
77,944

 
77,377

 
77,776

 
77,225

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

 
—

 
—

 
—

Denominator for diluted earnings (loss) per share
77,944

 
77,377

 
77,776

 
77,225

Loss per common share - Basic
$
(0.23
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.59
)
Loss per common share - Diluted
$
(0.23
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.59
)
Potentially dilutive securities excluded as anti-dilutive
4,055

 
5,185

 
5,015

 
4,750

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.

15



The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense (benefit) recognized for phantom stock unit awards during the three and six months ended June 30, 2018 and 2017 (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Stock option awards
$
99

 
$
246

 
$
241

 
$
477

Restricted stock awards
115

 
117

 
228

 
229

Restricted stock unit awards
883

 
645

 
1,887

 
1,629

 
$
1,097

 
$
1,008

 
$
2,356

 
$
2,335

Phantom stock unit awards
$
6,099

 
$
(581
)
 
$
6,529

 
$
(481
)
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. 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 six months ended June 30, 2018.
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 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 and restricted stock unit awards granted during the three and six months ended June 30, 2018 and 2017:
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Restricted Stock:
 
 
 
 
 
 
 
Restricted stock awards granted
78,632

 
167,272

 
78,632

 
167,272

Weighted-average grant-date fair value
$
5.85

 
$
2.75

 
$
5.85

 
$
2.75

Time-based RSUs:
 
 
 
 
 
 
 
Time-based RSUs granted
—

 
30,000

 
788,377

 
96,728

Weighted-average grant-date fair value
$
—

 
$
4.00

 
$
3.85

 
$
5.61

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.

16



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 June 30, 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. Half of the 2016 phantom stock unit awards 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 185% at June 30, 2018. The 2018 phantom stock unit awards will vest based upon our relative total shareholder return and relative EBITDA return on capital, both of which are subject to market conditions, and therefore, the fair value of these awards is 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 June 30, 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 June 30, 2018, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $1.1 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.
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 three and six months ended June 30, 2017 have been restated to reflect this change.

17



Our domestic and international drilling services segments provide contract land drilling services to a diverse group of exploration and production companies through our three 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 Gulf Coast, Mid-Continent and Rocky Mountain states.
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 June 30,
 
As of and for the six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
35,634

 
$
30,473

 
$
71,560

 
$
58,818

International drilling
21,773

 
8,306

 
39,384

 
18,977

Drilling services
57,407

 
38,779

 
110,944

 
77,795

Well servicing
23,162

 
21,017

 
44,276

 
39,751

Wireline services
62,137

 
39,832

 
118,738

 
72,378

Coiled tubing services
12,076

 
7,502

 
25,302

 
12,963

Production services
97,375

 
68,351

 
188,316

 
125,092

Consolidated revenues
$
154,782

 
$
107,130

 
$
299,260

 
$
202,887

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
21,749

 
$
20,380

 
$
42,647

 
$
39,889

International drilling
17,064

 
5,968

 
30,025

 
13,566

Drilling services
38,813

 
26,348

 
72,672

 
53,455

Well servicing
16,680

 
15,091

 
32,250

 
29,128

Wireline services
46,716

 
30,032

 
89,202

 
55,978

Coiled tubing services
11,988

 
7,588

 
22,839

 
13,226

Production services
75,384

 
52,711

 
144,291

 
98,332

Consolidated operating costs
$
114,197

 
$
79,059

 
$
216,963

 
$
151,787

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
13,885

 
$
10,093

 
$
28,913

 
$
18,929

International drilling
4,709

 
2,338

 
9,359

 
5,411

Drilling services
18,594

 
12,431

 
38,272

 
24,340

Well servicing
6,482

 
5,926

 
12,026

 
10,623

Wireline services
15,421

 
9,800

 
29,536

 
16,400

Coiled tubing services
88

 
(86
)
 
2,463

 
(263
)
Production services
21,991

 
15,640

 
44,025

 
26,760

Consolidated gross margin
$
40,585

 
$
28,071

 
$
82,297

 
$
51,100


18



 
As of and for the three months ended June 30,
 
As of and for the six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Identifiable Assets:
 
 
 
 
 
 
 
Domestic drilling (1)
$
380,355

 
$
412,319

 
$
380,355

 
$
412,319

International drilling (1) (2)
42,457

 
33,469

 
42,457

 
33,469

Drilling services
422,812

 
445,788

 
422,812

 
445,788

Well servicing
124,458

 
135,041

 
124,458

 
135,041

Wireline services
99,243

 
88,629

 
99,243

 
88,629

Coiled tubing services
31,889

 
26,121

 
31,889

 
26,121

Production services
255,590

 
249,791

 
255,590

 
249,791

Corporate
78,642

 
12,962

 
78,642

 
12,962

Consolidated identifiable assets
$
757,044

 
$
708,541

 
$
757,044

 
$
708,541

 
 
 
 
 
 
 
 
Depreciation and Amortization:
 
 
 
 
 
 
 
Domestic drilling
$
10,139

 
$
11,534

 
$
20,588

 
$
23,013

International drilling
1,301

 
1,357

 
2,748

 
2,979

Drilling services
11,440

 
12,891

 
23,336

 
25,992

Well servicing
4,865

 
5,000

 
9,785

 
10,012

Wireline services
4,601

 
4,452

 
9,209

 
8,905

Coiled tubing services
2,114

 
2,089

 
4,146

 
4,215

Production services
11,580

 
11,541

 
23,140

 
23,132

Corporate
267

 
308

 
558

 
608

Consolidated depreciation and amortization
$
23,287

 
$
24,740

 
$
47,034

 
$
49,732

 
 
 
 
 
 
 
 
Capital Expenditures:
 
 
 
 
 
 
 
Domestic drilling
$
4,736

 
$
6,314

 
$
7,494

 
$
15,780

International drilling
1,213

 
1,342

 
3,913

 
1,714

Drilling services
5,949

 
7,656

 
11,407

 
17,494

Well servicing
3,403

 
2,007

 
5,452

 
14,347

Wireline services
4,917

 
3,501

 
8,590

 
7,509

Coiled tubing services
4,817

 
982

 
7,981

 
2,262

Production services
13,137

 
6,490

 
22,023

 
24,118

Corporate
251

 
231

 
495

 
372

Consolidated capital expenditures
$
19,337

 
$
14,377

 
$
33,925

 
$
41,984

(1)
Identifiable assets for our drilling segments include the impact of a $35.1 million and $20.6 million intercompany balance, as of June 30, 2018 and 2017, respectively, between our domestic drilling segment (intercompany receivable) and our international drilling segment (intercompany payable).
(2)
Identifiable assets for our international drilling segment 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 June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Consolidated gross margin
$
40,585

 
$
28,071

 
$
82,297

 
$
51,100

Depreciation and amortization
(23,287
)
 
(24,740
)
 
(47,034
)
 
(49,732
)
General and administrative
(24,829
)
 
(16,112
)
 
(44,023
)
 
(33,856
)
Bad debt recovery, net of expense
370

 
226

 
422

 
589

Impairment
(2,368
)
 
(795
)
 
(2,368
)
 
(795
)
Gain on dispositions of property and equipment, net
726

 
621

 
1,061

 
1,092

Loss from operations
$
(8,803
)
 
$
(12,729
)
 
$
(9,645
)
 
$
(31,602
)

19



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 $73.4 million relating to our performance under these bonds as of June 30, 2018.
We are currently undergoing sales and use tax audits for multi-year periods. As of June 30, 2018 and December 31, 2017, our accrued liability was $1.4 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 June 30, 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.

20



CONDENSED CONSOLIDATING BALANCE SHEETS
(unaudited, in thousands)
 
June 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
57,351

 
$
(1,688
)
 
$
5,854

 
$
—

 
$
61,517

Restricted cash
2,000

 
—

 
—

 
—

 
2,000

Receivables, net of allowance
4

 
100,739

 
25,342

 
741

 
126,826

Intercompany receivable (payable)
(24,836
)
 
59,677

 
(34,841
)
 
—

 
—

Inventory
—

 
8,895

 
8,824

 
—

 
17,719

Assets held for sale
—

 
6,433

 
—

 
—

 
6,433

Prepaid expenses and other current assets
2,062

 
3,137

 
1,511

 
—

 
6,710

Total current assets
36,581

 
177,193

 
6,690

 
741

 
221,205

Net property and equipment
1,949

 
502,384

 
28,944

 
—

 
533,277

Investment in subsidiaries
589,844

 
22,780

 
—

 
(612,624
)
 
—

Deferred income taxes
40,272

 
—

 
—

 
(40,272
)
 
—

Other noncurrent assets
641

 
582

 
1,339

 
—

 
2,562

Total assets
$
669,287

 
$
702,939

 
$
36,973

 
$
(652,155
)
 
$
757,044

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,245

 
$
29,882

 
$
6,887

 
$
—

 
$
38,014

Deferred revenues
—

 
45

 
1,876

 
—

 
1,921

Accrued expenses
20,980

 
38,193

 
4,434

 
741

 
64,348

Total current liabilities
22,225

 
68,120

 
13,197

 
741

 
104,283

Long-term debt, less unamortized discount and debt issuance costs
463,072

 
—

 
—

 
—

 
463,072

Deferred income taxes
—

 
43,701

 
—

 
(40,272
)
 
3,429

Other noncurrent liabilities
1,299

 
1,274

 
996

 
—

 
3,569

Total liabilities
486,596

 
113,095

 
14,193

 
(39,531
)
 
574,353

Total shareholders’ equity
182,691

 
589,844

 
22,780

 
(612,624
)
 
182,691

Total liabilities and shareholders’ equity
$
669,287

 
$
702,939

 
$
36,973

 
$
(652,155
)
 
$
757,044

 
 
 
 
 
 
 
 
 
 
 
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


21



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)

 
Three months ended June 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
133,008

 
$
21,774

 
$
—

 
$
154,782

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
97,134

 
17,063

 
—

 
114,197

Depreciation and amortization
266

 
21,720

 
1,301

 
—

 
23,287

General and administrative
10,130

 
14,090

 
714

 
(105
)
 
24,829

Intercompany leasing
—

 
(1,215
)
 
1,215

 
—

 
—

Bad debt recovery, net of expense
—

 
(370
)
 
—

 
—

 
(370
)
Impairment
—

 
2,368

 
—

 
—

 
2,368

Gain on dispositions of property and equipment, net
—

 
(713
)
 
(13
)
 
—

 
(726
)
Total costs and expenses
10,396

 
133,014

 
20,280

 
(105
)
 
163,585

Income (loss) from operations
(10,396
)
 
(6
)
 
1,494

 
105

 
(8,803
)
Other income (expense):

 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
521

 
1,034

 
—

 
(1,555
)
 
—

Interest expense
(9,645
)
 
(2
)
 
5

 
—

 
(9,642
)
Other income (expense)
159

 
223

 
(233
)
 
(105
)
 
44

Total other income (expense), net
(8,965
)
 
1,255

 
(228
)
 
(1,660
)
 
(9,598
)
Income (loss) before income taxes
(19,361
)
 
1,249

 
1,266

 
(1,555
)
 
(18,401
)
Income tax (expense) benefit 1
1,209

 
(728
)
 
(232
)
 
—

 
249

Net income (loss)
$
(18,152
)
 
$
521

 
$
1,034

 
$
(1,555
)
 
$
(18,152
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended June 30, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
98,824

 
$
8,306

 
$
—

 
$
107,130

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
73,092

 
5,967

 
—

 
79,059

Depreciation and amortization
307

 
23,076

 
1,357

 
—

 
24,740

General and administrative
4,941

 
10,833

 
476

 
(138
)
 
16,112

Intercompany leasing
—

 
(1,215
)
 
1,215

 
—

 
—

Bad debt recovery, net of expense
—

 
(226
)
 
—

 
—

 
(226
)
Impairment
—

 
795

 
—

 
—

 
795

Loss (gain) on dispositions of property and equipment, net
2

 
(511
)
 
(112
)
 
—

 
(621
)
Total costs and expenses
5,250

 
105,844

 
8,903

 
(138
)
 
119,859

Loss from operations
(5,250
)
 
(7,020
)
 
(597
)
 
138

 
(12,729
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(6,283
)
 
(883
)
 
—

 
7,166

 
—

Interest expense
(6,480
)
 
62

 
—

 
—

 
(6,418
)
Other income (expense)
12

 
245

 
(46
)
 
(138
)
 
73

Total other expense, net
(12,751
)
 
(576
)
 
(46
)
 
7,028

 
(6,345
)
Loss before income taxes
(18,001
)
 
(7,596
)
 
(643
)
 
7,166

 
(19,074
)
Income tax (expense) benefit 1
(2,208
)
 
1,313

 
(240
)
 
—

 
(1,135
)
Net loss
$
(20,209
)
 
$
(6,283
)
 
$
(883
)
 
$
7,166

 
$
(20,209
)
 
 
 
 
 
 
 
 
 
 
1  The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.


22



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)
 
Six months ended June 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
259,875

 
$
39,385

 
$
—

 
$
299,260

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
186,943

 
30,020

 
—

 
216,963

Depreciation and amortization
557

 
43,729

 
2,748

 
—

 
47,034

General and administrative
16,368

 
26,629

 
1,236

 
(210
)
 
44,023

Intercompany leasing
—

 
(2,430
)
 
2,430

 
—

 
—

Bad debt recovery, net of expense
—

 
(422
)
 
—

 
—

 
(422
)
Impairment
—

 
2,368

 
—

 
—

 
2,368

Gain on dispositions of property and equipment, net
—

 
(1,034
)
 
(27
)
 
—

 
(1,061
)
Total costs and expenses
16,925

 
255,783

 
36,407

 
(210
)
 
308,905

Income (loss) from operations
(16,925
)
 
4,092

 
2,978

 
210

 
(9,645
)
Other income (expense):

 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
5,070

 
2,687

 
—

 
(7,757
)
 
—

Interest expense
(19,161
)
 
(2
)
 
8

 
—

 
(19,155
)
Other income
161

 
442

 
155

 
(210
)
 
548

Total other income (expense), net
(13,930
)
 
3,127

 
163

 
(7,967
)
 
(18,607
)
Income (loss) before income taxes
(30,855
)
 
7,219

 
3,141

 
(7,757
)
 
(28,252
)
Income tax (expense) benefit 1
1,564

 
(2,149
)
 
(454
)
 
—

 
(1,039
)
Net income (loss)
$
(29,291
)
 
$
5,070

 
$
2,687

 
$
(7,757
)
 
$
(29,291
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
183,910

 
$
18,977

 
$
—

 
$
202,887

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
138,227

 
13,560

 
—

 
151,787

Depreciation and amortization
608

 
46,145

 
2,979

 
—

 
49,732

General and administrative
10,770

 
22,436

 
926

 
(276
)
 
33,856

Intercompany leasing
—

 
(2,430
)
 
2,430

 
—

 
—

Bad debt recovery, net of expense
—

 
(589
)
 
—

 
—

 
(589
)
Impairment
—

 
795

 
—

 
—

 
795

Loss (gain) on dispositions of property and equipment, net
2

 
(967
)
 
(127
)
 
—

 
(1,092
)
Total costs and expenses
11,380

 
203,617

 
19,768

 
(276
)
 
234,489

Loss from operations
(11,380
)
 
(19,707
)
 
(791
)
 
276

 
(31,602
)
Other income (expense):

 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(14,868
)
 
(1,531
)
 
—

 
16,399

 
—

Interest expense
(12,496
)
 
19

 
—

 
—

 
(12,477
)
Other income (expense)
28

 
458

 
(281
)
 
(276
)
 
(71
)
Total other expense, net
(27,336
)
 
(1,054
)
 
(281
)
 
16,123

 
(12,548
)
Loss before income taxes
(38,716
)
 
(20,761
)
 
(1,072
)
 
16,399

 
(44,150
)
Income tax (expense) benefit 1
(6,617
)
 
5,893

 
(459
)
 
—

 
(1,183
)
Net loss
$
(45,333
)
 
$
(14,868
)
 
$
(1,531
)
 
$
16,399

 
$
(45,333
)
 
 
 
 
 
 
 
 
 
 
1  The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

23



CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 
Six months ended June 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(26,819
)
 
$
37,264

 
$
6,680

 
$
—

 
$
17,125

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(435
)
 
(26,989
)
 
(4,061
)
 
—

 
(31,485
)
Proceeds from sale of property and equipment
—

 
2,212

 
13

 
—

 
2,225

Proceeds from insurance recoveries
—

 
527

 
14

 
—

 
541

 
(435
)
 
(24,250
)
 
(4,034
)
 
—

 
(28,719
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from exercise of options
12

 
—

 
—

 
—

 
12

Purchase of treasury stock
(549
)
 
—

 
—

 
—

 
(549
)
Intercompany contributions/distributions
12,876

 
(12,821
)
 
(55
)
 
—

 
—

 
12,339

 
(12,821
)
 
(55
)
 
—

 
(537
)
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
(14,915
)
 
193

 
2,591

 
—

 
(12,131
)
Beginning cash, cash equivalents and restricted cash
74,266

 
(1,881
)
 
3,263

 
—

 
75,648

Ending cash, cash equivalents and restricted cash
$
59,351

 
$
(1,688
)
 
$
5,854

 
$
—

 
$
63,517

 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2017
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(21,031
)
 
$
2,799

 
$
1,935

 
$
—

 
$
(16,297
)
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(317
)
 
(37,904
)
 
(2,081
)
 
270

 
(40,032
)
Proceeds from sale of property and equipment
—

 
7,869

 
149

 
(270
)
 
7,748

Proceeds from insurance recoveries
—

 
3,119

 
—

 
—

 
3,119

 
(317
)
 
(26,916
)
 
(1,932
)
 
—

 
(29,165
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Debt repayments
(12,305
)
 
—

 
—

 
—

 
(12,305
)
Proceeds from issuance of debt
55,000

 
—

 
—

 
—

 
55,000

Purchase of treasury stock
(533
)
 
—

 
—

 
—

 
(533
)
Intercompany contributions/distributions
(22,201
)
 
22,216

 
(15
)
 
—

 
—

 
19,961

 
22,216

 
(15
)
 
—

 
42,162

 
 
 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
(1,387
)
 
(1,901
)
 
(12
)
 
—

 
(3,300
)
Beginning cash and cash equivalents
9,898

 
(764
)
 
1,060

 
—

 
10,194

Ending cash and cash equivalents
$
8,511

 
$
(2,665
)
 
$
1,048

 
$
—

 
$
6,894

 
 




24



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.

25



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. 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 July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig which we expect to deploy in early 2019 to the Permian Basin. 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 current fleet are deployed through our division offices in the following regions:
 
 
Rig Count
Domestic drilling
 
 
Marcellus/Utica
 
6

Permian Basin and Eagle Ford
 
8

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 Gulf Coast, Mid-Continent and Rocky Mountain states.
•
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. We have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 11 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. We have a current fleet of 104 wireline units, with one additional unit on order for delivery in the third quarter of 2018. Our units are deployed through 14 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. We have a current fleet of 11 coiled tubing units, with one additional unit on order for delivery late in 2018. Our units are deployed through two operating locations that provide services in Texas, Wyoming and surrounding areas.

26



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 change 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.
From time to time, temporary regional slowdowns or constraints occur in our industry due to a variety of factors, including, among others, infrastructure or takeaway capacity limitations, labor shortages, increased regulatory or environmental pressures, or an influx of competitors in a particular region. Any of these factors can influence the profitability of operations in the affected region. However, term contract coverage for our drilling services business and the mobility of all our equipment between regions limits our exposure to the impact of regional constraints and fluctuations in demand.
For additional information concerning the potential effects of volatility in oil and gas prices and other industry trends, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2017.

27



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 just under $50 per barrel at the end of June 2016 to approximately $60 per barrel at the end of 2017. In 2018, WTI oil prices continued to increase to almost $75 per barrel at the end of June, and have since averaged above $70 per barrel through mid-July.
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:
a1yrspotpricesandrigcount.jpg
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. In July 2018, we entered into a three-year term contract for the construction of a new 1,500 horsepower, AC pad-optimal rig which we expect to deploy in early 2019 to the Permian Basin.
As of June 30, 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
 
18 Months
to 2 Years
 
2 to 4 Years
Domestic rigs
2

 
14

 
6

 
3

 
5

 
—

 
—

International rigs
—

 
7

 
—

 
2

 
1

 
3

 
1

 
2

 
21

 
6

 
5

 
6

 
3

 
1


28



The term contracts for our international drilling rigs are cancelable by our clients without penalty, although the contracts require 30 days notice and payment for demobilization services. We are actively marketing our idle rig in Colombia and we also continue to evaluate the possibility of selling some or all of our assets in Colombia.
Our well servicing rig hours and number of wireline jobs completed during the quarter ended June 30, 2018 increased by 5% and 7%, respectively, while revenue days for our coiled tubing services decreased by 15%, as compared to the first quarter of 2018. Average revenue rates for our well servicing, wireline and coiled tubing services provided during this same period increased by 4%, 3% and 8% (on a per hour, per job and per day basis, respectively). The wireline and coiled tubing increases were primarily driven by an increase in the proportion of completion-related activity and work performed by larger diameter coiled tubing units.
Despite the recovery of demand for our services in onshore regions, offshore activity has remained depressed. As a result, we exited the offshore wireline and coiled tubing market in the second quarter of 2018 and designated as held for sale all but two of our more desirable offshore coiled tubing units that we may deploy if offshore demand improves.
Limited takeaway capacity in the Permian Basin has led to price discounts on crude oil that could impact activity and near term growth in the region; however, we have term contract coverage for our drilling rigs and limited production services units currently operating in this region which limits our exposure to any decreases in activity.
Absent a significant decline in commodity prices, we expect demand to remain strong for the remainder of 2018. Although we expect a highly competitive environment to continue, we believe our high-quality equipment and services and our excellent safety record make us well positioned to compete.
Liquidity and Capital Resources
Sources of Capital Resources
Our principal sources of liquidity currently consist of:
•
total cash and cash equivalents ($63.5 million as of June 30, 2018);
•
cash generated from operations ($17.1 million during the six months ended June 30, 2018);
•
proceeds from sales of certain non-strategic assets; and
•
the unused portion of our asset-based lending facility ($62.0 million as of June 30, 2018).
Our asset-based lending facility (the “ABL Facility”) provides for a senior secured revolving asset-based credit facility, with sub-limits for letters of credit, of up to a current aggregate commitment amount of $75 million, subject to availability under a borrowing base generally comprised of a percentage of our accounts receivable and inventory. 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.
We have not drawn upon our ABL Facility to date. As of June 30, 2018, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $62.0 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. Additional information regarding these covenants is provided in the Debt Compliance Requirements section below.
In the future, we may also consider equity and/or debt offerings, as appropriate, to meet our liquidity needs. On May 22, 2018, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of June 30, 2018, the entire $300 million under the shelf registration statement is available for equity or debt offerings, subject to the limitations imposed by our Term Loan, ABL Facility and Senior Notes.
We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of certain non-strategic assets, and available borrowings under our ABL Facility are adequate to cover our liquidity requirements for at least the next 12 months.

29



Uses of Capital Resources
Our principal liquidity requirements are currently for:
•
working capital needs;
•
debt service; and
•
capital expenditures.
Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements generally increase during periods when rig construction projects are in progress or during periods of expansion in our production services business, at which times we have been more likely to access capital through equity or debt financing. Additionally, our working capital needs may increase in periods of increasing activity following a sustained period of low activity. During periods of sustained low activity and pricing, we may also access additional capital through the use of available funds under our ABL Facility.
Working Capital — Our working capital was $116.9 million at June 30, 2018, compared to $130.6 million at December 31, 2017. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.1 at June 30, 2018, as compared to 2.5 at December 31, 2017. The changes in the components of our working capital were as follows (amounts in thousands), and as described below:
 
June 30,
2018
 
December 31,
2017
 
Change
Cash and cash equivalents
$
61,517

 
$
73,640

 
$
(12,123
)
Restricted cash
2,000

 
2,008

 
(8
)
Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
84,591

 
79,592

 
4,999

Unbilled receivables
22,951

 
16,029

 
6,922

Insurance recoveries
15,014

 
13,874

 
1,140

Other receivables
4,270

 
3,510

 
760

Inventory
17,719

 
14,057

 
3,662

Assets held for sale
6,433

 
6,620

 
(187
)
Prepaid expenses and other current assets
6,710

 
6,229

 
481

Current assets
221,205

 
215,559

 
5,646

Accounts payable
38,014

 
29,538

 
8,476

Deferred revenues
1,921

 
905

 
1,016

Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
29,315

 
21,023

 
8,292

Insurance claims and settlements
14,702

 
13,289

 
1,413

Insurance premiums and deductibles
6,238

 
6,742

 
(504
)
Interest
6,361

 
6,624

 
(263
)
Other
7,732

 
6,793

 
939

Current liabilities
104,283

 
84,914

 
19,369

Working capital
$
116,922

 
$
130,645

 
$
(13,723
)
•
Cash and cash equivalents — The change in cash and cash equivalents during 2018 is primarily due to $31.5 million of cash used for the purchase of property and equipment, partially offset by $17.1 million of cash from operating activities and $2.2 million of proceeds from the sale of property and equipment.
•
Trade and unbilled receivables — The net increase in our total trade and unbilled receivables during 2018 is primarily due to the 23% increase in our revenues during the quarter ended June 30, 2018, as compared to the quarter ended December 31, 2017. Our domestic trade receivables generally turn over within 60 days, and our Colombian trade receivables generally turn over within 100 days.
•
Insurance recoveries and Insurance claims and settlements — The increase in our insurance recoveries receivables and our insurance claims and settlements accrued expenses during 2018 is primarily due to an increase in our insurance company’s reserve for workers’ compensation claims in excess of our deductibles.

30



•
Other receivables — The increase in other receivables during 2018 is primarily due to an increase in recoverable income tax receivables attributable to the increase in activity for our international operations. This increase is partially offset by a decrease in short-term notes receivable from the sale of drilling rigs and equipment, for which payments were received during 2018.
•
Inventory — The increase in inventory during 2018 is primarily due to the increase in activity for our international operations, as well as purchases of supplies and job materials for our wireline and coiled tubing operations.
•
Accounts payable — Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2018 is primarily due to the 24% increase in our operating costs for the quarter ended June 30, 2018 as compared to the quarter ended December 31, 2017 as well as an increase of $2.4 million in our accruals for capital expenditures as of June 30, 2018 as compared to December 31, 2017.
•
Accrued payroll and related employee costs — The increase in accrued payroll and related employee costs during 2018 is primarily due to the movement of the accrued liability for our 2016 phantom stock unit awards from noncurrent to current, as these awards are scheduled to vest in April 2019. Additionally, the accrued liability for these awards increased due to the recent increase in our stock price which is the most impactful input for the fair value measurement of these awards. For additional information about these awards, see Note 8, Stock-Based Compensation Plans of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q. The increase in accrued payroll and related employee costs during 2018 is partially offset by a decrease in annual incentive compensation associated with the payment of 2017 annual bonuses which were fully accrued at December 31, 2017 and were paid in the first quarter of 2018.
•
Other accrued expenses — The increase in other accrued expenses during 2018 is primarily related to an increase in accrued taxes associated with the increase in revenues for our international operations.
Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at June 30, 2018 (amounts in thousands):
 
Payments Due by Period
Contractual Obligations
Total
 
Within 1 Year
 
2 to 3 Years
 
4 to 5 Years
 
Beyond 5 Years
Debt
$
475,000

 
$
—

 
$
—

 
$
475,000

 
$
—

Interest on debt
131,672

 
35,228

 
70,455

 
25,989

 
—

Purchase commitments
11,959

 
11,959

 
—

 
—

 
—

Operating leases
10,803

 
3,432

 
3,568

 
2,258

 
1,545

Incentive compensation
27,947

 
17,544

 
10,403

 
—

 
—

 
$
657,381

 
$
68,163

 
$
84,426

 
$
503,247

 
$
1,545

•
Debt — Debt obligations at June 30, 2018 consist of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $175 million of principal amount outstanding under our Term Loan which is expected to mature December 14, 2021. As of June 30, 2018, we had no debt outstanding under our ABL Facility.
•
Interest on debt — Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year until maturity on March 15, 2022. Interest payment obligations on our Term Loan were estimated based on (1) the 9.8% interest rate that was in effect at June 30, 2018, and (2) the principal balance of $175 million at June 30, 2018, and assuming repayment of the outstanding balance occurs at December 14, 2021.
•
Purchase commitments — Purchase commitments generally relate to capital projects for the repair, upgrade and maintenance of our equipment, the construction or purchase of new equipment, and purchase orders for various job and inventory supplies. At June 30, 2018, our purchase commitments primarily pertain to $5.5 million of remaining obligations for the purchase of two new coiled tubing units (one of which was put into service in early July) and one new wireline unit, which are on order for delivery in the second half of 2018. Other purchase commitments include job supply purchases for our wireline and coiled tubing operations and committed capital expenditures for various refurbishments and upgrades to our drilling rig equipment.
•
Operating leases — Our operating leases consist of lease agreements for office space, operating facilities, field personnel housing, and office equipment.

31



•
Incentive compensation — Incentive compensation is payable to our employees, generally contingent upon their continued employment through the date of each respective award’s payout. A portion of our long-term incentive compensation is performance-based and therefore the final amount will be determined based on our actual performance relative to a pre-determined peer group over the performance period.
Debt Compliance Requirements — The following is a summary of our debt compliance requirements including covenants, restrictions and guarantees, all of which are described in more detail in Note 5, Debt, and Note 11, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
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. As of June 30, 2018, the asset coverage ratio, as calculated under the Term Loan, was 2.17 to 1.00.
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 limit our ability to enter into various transactions. 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. 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.
The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to enter into certain transactions. 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.
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.
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. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. Our Senior Notes are not subject to any sinking fund requirements. The Indenture governing our Senior Notes contains additional restrictive covenants that limit our ability to enter into various transactions.
As of June 30, 2018, we were in compliance with all covenants required by our Term Loan, ABL Facility and Senior Notes.
Capital Expenditures — During the six months ended June 30, 2018, we spent $31.5 million on purchases of property and equipment and placed into service property and equipment of $33.9 million. Currently, we expect to spend approximately $65 million to $70 million on capital expenditures during 2018, which includes approximately $23 million for two large-diameter coiled tubing units, one of which was delivered in early July, three wireline units, two of which were delivered in January, high-pressure pump packages for completion operations, and the construction of the new-build drilling rig expected to be completed in 2019.
Actual capital expenditures may vary depending on the climate of our industry and any resulting increase or decrease in activity levels, the timing of commitments and payments, and the level of rig build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the remaining capital expenditures in 2018 from operating cash flow in excess of our working capital requirements, proceeds from sales of certain non-strategic assets, remaining proceeds from our Term Loan issuance, and from available borrowings under our ABL Facility, if necessary.

32



Results of Operations
Statements of Operations Analysis
The following table provides certain information about our operations, including a detail of each of our business segments’ revenues, operating costs and gross margin for the three and six months ended June 30, 2018 and 2017 (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
35,634

 
$
30,473

 
$
71,560

 
$
58,818

International drilling
21,773

 
8,306

 
39,384

 
18,977

Drilling services
57,407

 
38,779

 
110,944

 
77,795

Well servicing
23,162

 
21,017

 
44,276

 
39,751

Wireline services
62,137

 
39,832

 
118,738

 
72,378

Coiled tubing services
12,076

 
7,502

 
25,302

 
12,963

Production services
97,375

 
68,351

 
188,316

 
125,092

Consolidated revenues
$
154,782

 
$
107,130

 
$
299,260

 
$
202,887

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
21,749

 
$
20,380

 
$
42,647

 
$
39,889

International drilling
17,064

 
5,968

 
30,025

 
13,566

Drilling services
38,813

 
26,348

 
72,672

 
53,455

Well servicing
16,680

 
15,091

 
32,250

 
29,128

Wireline services
46,716

 
30,032

 
89,202

 
55,978

Coiled tubing services
11,988

 
7,588

 
22,839

 
13,226

Production services
75,384

 
52,711

 
144,291

 
98,332

Consolidated operating costs
$
114,197

 
$
79,059

 
$
216,963

 
$
151,787

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
13,885

 
$
10,093

 
$
28,913

 
$
18,929

International drilling
4,709

 
2,338

 
9,359

 
5,411

Drilling services
18,594

 
12,431

 
38,272

 
24,340

Well servicing
6,482

 
5,926

 
12,026

 
10,623

Wireline services
15,421

 
9,800

 
29,536

 
16,400

Coiled tubing services
88

 
(86
)
 
2,463

 
(263
)
Production services
21,991

 
15,640

 
44,025

 
26,760

Consolidated gross margin
$
40,585

 
$
28,071

 
$
82,297

 
$
51,100

 
 
 
 
 
 
 
 
Consolidated:
 
 
 
 
 
 
 
Net loss
$
(18,152
)
 
$
(20,209
)
 
$
(29,291
)
 
$
(45,333
)
Adjusted EBITDA (1)
$
16,896

 
$
12,879

 
$
40,305

 
$
18,854

(1)    Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, impairment, and any loss on extinguishment of debt. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies.

33



A reconciliation of net loss, as reported, to Adjusted EBITDA, and to consolidated gross margin, are set forth in the following table.
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(amounts in thousands)
Net loss
$
(18,152
)
 
$
(20,209
)
 
$
(29,291
)
 
$
(45,333
)
Depreciation and amortization
23,287

 
24,740

 
47,034

 
49,732

Impairment
2,368

 
795

 
2,368

 
795

Interest expense
9,642

 
6,418

 
19,155

 
12,477

Income tax expense (benefit)
(249
)
 
1,135

 
1,039

 
1,183

Adjusted EBITDA
16,896

 
12,879

 
40,305

 
18,854

General and administrative
24,829

 
16,112

 
44,023

 
33,856

Bad debt recovery, net of expense
(370
)
 
(226
)
 
(422
)
 
(589
)
Gain on dispositions of property and equipment, net
(726
)
 
(621
)
 
(1,061
)
 
(1,092
)
Other expense (income)
(44
)
 
(73
)
 
(548
)
 
71

Consolidated gross margin
$
40,585

 
$
28,071

 
$
82,297

 
$
51,100

Consolidated gross margin — Our consolidated gross margin increased by 45% and 61% for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, as a result of higher demand for all of our drilling and production services segments. Of the $12.5 million and $31.2 million increases in consolidated gross margin for the three and six months ended June 30, 2018, respectively, 51% and 55%, respectively, are attributable to our production services segments, primarily due to improved demand for our wireline services, while the remaining increases are attributable to our drilling services segments, primarily driven by higher domestic dayrates and activity.
•
Drilling Services — Our drilling services revenues increased by $18.6 million, or 48%, and $33.1 million, or 43%, for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, while operating costs increased by $12.5 million, or 47%, and $19.2 million, or 36%. The increases in our drilling services revenues and operating costs primarily resulted from a 29% increase in revenue days during both the three and six months ended June 30, 2018, as compared to the corresponding periods in 2017, due to the increasing demand in our industry. The following table provides operating statistics for each of our drilling services segments:
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Domestic drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
16

 
16

 
16

 
16

Utilization rate
100
%
 
92
%
 
100
%
 
89
%
Revenue days
1,454

 
1,345

 
2,894

 
2,580

 
 
 
 
 
 
 
 
Average revenues per day
$
24,508

 
$
22,657

 
$
24,727

 
$
22,798

Average operating costs per day
14,958

 
15,152

 
14,736

 
15,461

Average margin per day
$
9,550

 
$
7,505

 
$
9,991

 
$
7,337

 
 
 
 
 
 
 
 
International drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
8

 
8

 
8

 
8

Utilization rate
85
%
 
36
%
 
81
%
 
40
%
Revenue days
621

 
262

 
1,171

 
582

 
 
 
 
 
 
 
 
Average revenues per day
$
35,061

 
$
31,702

 
$
33,633

 
$
32,607

Average operating costs per day
27,478

 
22,779

 
25,640

 
23,309

Average margin per day
$
7,583

 
$
8,923

 
$
7,993

 
$
9,298

Our domestic drilling fleet utilization has been fully utilized since mid-2017, allowing us to achieve the higher margins of a fully utilized fleet. Our domestic drilling average revenues per day for the three and six months ended June 30, 2018 increased as compared to the corresponding periods in 2017, primarily due to increasing drilling dayrates, while

34



our average operating costs per day decreased, primarily because additional costs were incurred during the first half of 2017 to deploy previously idle rigs under new contracts.
Our international drilling fleet utilization has steadily improved since the beginning of 2017, with seven of eight rigs utilized at June 30, 2018, versus four rigs utilized at the beginning of 2017. Despite the improved utilization in 2018, our average margin per day decreased for the three and six months ended June 30, 2018 as compared to the corresponding periods in 2017, due primarily to additional costs incurred to deploy a previously idle rig during the first quarter of 2018, and the impact of both an increase in the revenue days associated with mobilization activity and rigs on standby during the second quarter of 2018.
•
Production Services — Our revenues from production services increased by $29.0 million, or 42%, and $63.2 million, or 51%, for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, while operating costs increased by $22.7 million, or 43%, and $46.0 million, or 47%, respectively. The increases in revenues and operating costs in our production services segments are a result of the increased demand for our services, particularly those that perform completion-related activities. The following table provides operating statistics for each of our production services segments:
 
Three months ended June 30,
 
Six months ended June 30,
 
2018
 
2017
 
2018
 
2017
Well servicing:
 
 
 
 
 
 
 
Average number of rigs
125

 
125

 
125

 
125

Utilization rate
49
%
 
47
%
 
48
%
 
45
%
Rig hours
42,871

 
40,880

 
83,645

 
78,589

Average revenue per hour
$
540

 
$
514

 
$
529

 
$
506

 
 
 
 
 
 
 
 
Wireline services:
 
 
 
 
 
 
 
Average number of units
108

 
114

 
108

 
114

Number of jobs
3,022

 
2,908

 
5,852

 
5,762

Average revenue per job
$
20,562

 
$
13,697

 
$
20,290

 
$
12,561

 
 
 
 
 
 
 
 
Coiled tubing services:
 
 
 
 
 
 
 
Average number of units
14

 
17

 
14

 
17

Revenue days
350

 
400

 
764

 
738

Average revenue per day
$
34,503

 
$
18,755

 
$
33,118

 
$
17,565

Increases in production services revenues and operating costs were led by our wireline services business segment, which experienced a significant increase in completion-related activity as wells that were drilled but not completed during the downturn created higher demand for completion services as our industry continues to recover. Although the number of wireline jobs we completed increased by just 4% and 2% for the three and six months ended June 30, 2018, as compared to the corresponding periods in 2017, respectively, average revenue per job increased by 50% and 62%, respectively, which is largely due to a higher percentage of the work performed being attributable to completion-related jobs which earn higher revenue rates, but also incur higher costs for the job materials consumed on these types of jobs.
Our coiled tubing services business segment also experienced an increase in demand during 2018, especially for services provided using our larger diameter coiled tubing units. Although revenue days decreased 13% and increased 4% for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, average revenue per day increased by 84% and 89%, respectively. The increases in average revenue per day were primarily due to a larger proportion of the work performed with larger diameter coiled tubing units which typically earn higher revenue rates as compared to smaller diameter coiled tubing units. Additionally, the expansion of our coiled tubing operations into a new market in late 2017 contributed to the improvement in 2018, as compared to the corresponding periods in 2017.
Our well servicing business segment experienced a moderate increase in demand. Well servicing utilization increased to 49% and 48% for the three and six months ended June 30, 2018, respectively, from 47% and 45%, respectively, during the corresponding periods in 2017. These utilization improvements represent 5% and 6% increases in well servicing rig hours, respectively, while average revenue per hour also increased by 5% from both comparative periods.

35



Depreciation and amortization expense — Our depreciation and amortization expense decreased by $1.5 million and $2.7 million for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017, primarily as a result of reduced capital expenditures during 2016 and 2017, when discretionary upgrades, refurbishments and purchases of new equipment were limited or deferred to preserve capital through the downturn.
Impairment — During the six months ended June 30, 2018 and 2017, we recognized impairment charges of $2.4 million and $0.8 million, respectively, to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair values based on expected sale prices. For more detail, see Note 3, Property and Equipment, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 Financial Statements, of this Quarterly Report on Form 10-Q.
Interest expense — Our interest expense increased by $6.7 million during the six months ended June 30, 2018, as compared to the corresponding period in 2017, primarily due to the issuance of our Term Loan in November 2017, from which a portion of the proceeds were used to repay and retire our Revolving Credit Facility. As a result, our total debt outstanding increased, as did the interest rate applicable to outstanding borrowings. Debt outstanding under our Term Loan was $175 million during the six months ended June 30, 2018, while the weighted average debt outstanding under our Revolving Credit Facility was approximately $74 million during the six months ended June 30, 2017, with annualized weighted average interest rates applicable to these borrowings during these periods of approximately 9.6% and 5.5%, respectively.
Income tax expense (benefit) — Our effective income tax rate for the six months ended June 30, 2018 was lower than the federal statutory rate in the United States, primarily due to valuation allowances, foreign currency translation, state taxes, and other permanent differences. For more detail, see Note 4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
General and administrative expense — Our general and administrative expense increased by approximately $8.7 million, or 54%, and $10.2 million, or 30%, for the three and six months ended June 30, 2018, respectively, as compared to the corresponding periods in 2017. The increase during both of these periods was primarily due to an increase of $6.6 million during the three months ended June 30, 2018 associated with the increase in fair value of our phantom stock unit awards. In addition, our general and administrative expense increased due to higher compensation costs, including a $1.7 million increase in salary and related employee benefits during the six months ended June 30, 2018 which primarily resulted from additional personnel to support the increase in activity.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. Except for those related to the adoption of ASC Topic 606 discussed below, as of June 30, 2018, there were no significant changes to our critical accounting policies since the date of our annual report on Form 10-K for the year ended December 31, 2017.
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

36



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, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Accounting 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.
•
In accordance with ASC Topic 606, Revenue from Contracts with Customers, we estimate certain variable revenues associated with the demobilization of our drilling rigs under daywork drilling contracts. We also make estimates of the applicable amortization periods for deferred mobilization costs, and for mobilization revenues related to cancelable term contracts which represent a material right to our clients. These estimates and assumptions are described in more detail in Note 2, Revenue from Contracts with Customers. In order to make these estimates, management considers all the facts and circumstances pertaining to each particular contract, our past experience and knowledge of current market conditions.
•
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). 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 June 30, 2018. The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analyses are reasonable and appropriate, different assumptions and estimates could materially impact the analyses and resulting conclusions.
•
As of June 30, 2018, we had $95.2 million and $11.8 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. As a result, we have a valuation allowance that fully offsets our foreign and domestic federal deferred tax assets as of June 30, 2018. The valuation allowance is the primary factor causing our effective tax rate to be significantly lower than the statutory rate. For more information, see Note 4, Valuation Allowances on Deferred Tax Assets and Recently Enacted Tax Reform, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
•
Our accrued insurance premiums and deductibles as of June 30, 2018 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.3 million and our workers’ compensation, general liability and auto liability insurance of approximately $4.8 million. We have stop-loss coverage of $200,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the costs of administrative services associated with claims processing.

37



•
Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods. Additionally, our phantom stock unit 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. For more information, see Note 8, Stock-Based Compensation Plans, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Recently Issued Accounting Standards
For a detail of recently issued accounting standards, see Note 1, Organization and Summary of Significant Accounting Policies, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk — We are subject to interest rate market risk on our variable rate debt. As of June 30, 2018, the principal amount under our Term Loan was $175 million, which is our only variable rate debt with an outstanding balance. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $0.9 million during the six months ended June 30, 2018. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, 2018.
Foreign Currency Risk — While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian Pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements. The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in net foreign currency gains of $0.1 million for the six months ended June 30, 2018.
ITEM 4.
CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2018, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In the ordinary course of business, we may make changes to our systems and processes to improve controls and increase efficiency, and make changes to our internal controls over financial reporting in order to ensure that we maintain an effective

38



internal control environment. There has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

39


PART II - OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.

ITEM 1A.
RISK FACTORS
Not applicable.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
We did not make any unregistered sales of equity securities during the quarter ended June 30, 2018. The following table provides information relating to our repurchase of common shares during the quarter ended June 30, 2018:
Period
Total Number of
Shares Purchased 
(1)
 
Average Price Paid
per Share
(2)
 
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans or Programs
April 1 - April 30
130,241

 
$
3.45

 
—

 
—

May 1 - May 31
730

 
$
6.00

 
—

 
—

June 1 - June 30
—

 
$
—

 
—

 
—

Total
130,971

 
$
3.46

 
—

 
—

(1)
The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended June 30, 2018, to satisfy the employees’ tax withholding obligations in connection with the vesting of share-based compensation awards, which we repurchased based on the fair market value on the date the relevant transaction occurred.
(2)
The calculation of the average price paid per share does not give effect to any fees, commissions or other costs associated with the repurchase of such shares.

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
Not applicable.

ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.

ITEM 5.
OTHER INFORMATION
We are providing the following disclosure in lieu of providing this information in a Current Report on Form 8-K.
Item 1.01 - Entry into a Material Definitive Agreement.
On July 26, 2018, in connection with a periodic review of its existing indemnification agreements, the Board of Directors (the “Board”) of Pioneer Energy Services Corp. (the “Company”) approved a new form of indemnification agreement (“Indemnification Agreement”) to be entered into by and between the Company and each of its directors and executive officers (each, an “Indemnitee”). The Company intends to enter into an Indemnification Agreement with each current member of the Board and each current executive officer of the Company.
The Indemnification Agreement supplements indemnification provisions already in the Company’s Restated Articles of Incorporation and Amended and Restated Bylaws and supersedes any prior indemnification agreements entered into between the Company and its current directors or executive officers.

40



In general, the Indemnification Agreement provides that, subject to the procedures, limitations and exceptions set forth therein, the Company will indemnify the Indemnitee to the fullest extent permitted by the Texas Business Organizations Code against all damages, judgments, fines, penalties, settlements and other costs and expenses (including, without limitation, reasonable attorneys’ fees) actually paid or reasonably incurred by the Indemnitee in any threatened or pending proceeding by reason of or arising in part out of (i) the Indemnitee serving as a director, officer, partner, venturer, proprietor, trustee, fiduciary, managing member, employee, agent or similar functionary of the Company or (ii) the Indemnitee serving as a director, officer, partner, venturer, proprietor, trustee, fiduciary, managing member, employee, agent or similar functionary of any other corporation, limited liability company, limited or general partnership, joint venture, sole proprietorship, trust or other enterprise at the request of the Company.
Under the terms of the Indemnification Agreement, the Indemnitee also generally has the right to have the Company advance all expenses actually paid or reasonably incurred by the Indemnitee in any proceeding to the fullest extent permitted by the Texas Business Organizations Code prior to the final disposition of such proceeding.
The above description of the Indemnification Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Indemnification Agreement filed herewith as Exhibit 10.1 and incorporated herein by reference.

ITEM 6.
EXHIBITS
See the Index to Exhibits immediately following the signatures page.



41



SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
PIONEER ENERGY SERVICES CORP.
 
/s/ Lorne E. Phillips
Lorne E. Phillips
Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Duly Authorized Officer)
Dated: July 31, 2018


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Index to Exhibits

The following documents are exhibits to this Form 10-Q:
Exhibit
Number
 
Description
 
 
 
3.1*
-
 
 
 
3.2*
-
 
 
 
4.1*
-
 
 
 
4.2*
-
 
 
 
4.3*
-
 
 
 
10.1+**
 
 
 
 
31.1**
-
 
 
 
31.2**
-
 
 
 
32.1#
-
 
 
 
32.2#
-
 
 
 
101**
-
The following financial statements from Pioneer Energy Services Corp.’s Form 10-Q for the quarter ended June 30, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Condensed Consolidated Financial Statements.
 
 
 
*
Incorporated by reference to the filing indicated.
**
Filed herewith.
#
Furnished herewith.
+
Management contract or compensatory plan or arrangement.

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