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, 2019
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

Securities registered pursuant to Section 12(b) of the Act
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, $0.10 par value
PES
New York Stock Exchange
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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   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
 
 
 
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 15, 2019 , there were 79,202,216 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 


TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 



PART I. FINANCIAL INFORMATION
ITEM 1.
FINANCIAL STATEMENTS
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
2019
 
December 31,
2018
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
30,132

 
$
53,566

Restricted cash
998

 
998

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
90,288

 
76,924

Unbilled receivables
24,691

 
24,822

Insurance recoveries
22,902

 
23,656

Other receivables
7,691

 
5,479

Inventory
22,800

 
18,898

Assets held for sale
5,962

 
3,582

Prepaid expenses and other current assets
7,061

 
7,109

Total current assets
212,525

 
215,034

Property and equipment, at cost
1,121,703

 
1,118,215

Less accumulated depreciation
620,860

 
593,357

Net property and equipment
500,843

 
524,858

Operating lease assets
8,775

 
—

Other noncurrent assets
1,526

 
1,658

Total assets
$
723,669

 
$
741,550

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
41,019

 
$
34,134

Deferred revenues
1,420

 
1,722

Accrued expenses:
 
 
 
Payroll and related employee costs
19,484

 
24,598

Insurance claims and settlements
22,637

 
23,593

Insurance premiums and deductibles
4,989

 
5,482

Interest
5,754

 
6,148

Other
10,697

 
9,091

Total current liabilities
106,000

 
104,768

Long-term debt, less unamortized discount and debt issuance costs
466,093

 
464,552

Noncurrent operating lease liabilities
6,495

 
—

Deferred income taxes
4,913

 
3,688

Other noncurrent liabilities
1,823

 
3,484

Total liabilities
585,324

 
576,492

Commitments and contingencies (Note 11)

 

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

 
—

Common stock $.10 par value; 200,000,000 shares authorized; 79,121,204 and 78,214,550 shares outstanding at June 30, 2019 and December 31, 2018, respectively
8,000

 
7,900

Additional paid-in capital
551,642

 
550,548

Treasury stock, at cost; 877,047 and 789,532 shares at June 30, 2019 and December 31, 2018, respectively
(5,090
)
 
(4,965
)
Accumulated deficit
(416,207
)
 
(388,425
)
Total shareholders’ equity
138,345

 
165,058

Total liabilities and shareholders’ equity
$
723,669

 
$
741,550

See accompanying notes to condensed consolidated financial statements.

3



PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(in thousands, except per share data)
 
 
 
 
 
 
 
 
Revenues
$
152,843

 
$
154,782

 
$
299,411

 
$
299,260

 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
Operating costs
115,970

 
114,197

 
224,555

 
216,963

Depreciation
22,851

 
23,287

 
45,504

 
47,034

General and administrative
18,028

 
24,829

 
37,786

 
44,023

Bad debt recovery, net
(348
)
 
(370
)
 
(286
)
 
(422
)
Impairment
332

 
2,368

 
1,378

 
2,368

Gain on dispositions of property and equipment, net
(1,126
)
 
(726
)
 
(2,201
)
 
(1,061
)
Total costs and expenses
155,707

 
163,585

 
306,736

 
308,905

Loss from operations
(2,864
)
 
(8,803
)
 
(7,325
)
 
(9,645
)
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(10,105
)
 
(9,642
)
 
(19,990
)
 
(19,155
)
Other income, net
349

 
44

 
1,033

 
548

Total other expense, net
(9,756
)
 
(9,598
)
 
(18,957
)
 
(18,607
)
 
 
 
 
 
 
 
 
Loss before income taxes
(12,620
)
 
(18,401
)
 
(26,282
)
 
(28,252
)
Income tax (expense) benefit
(324
)
 
249

 
(1,777
)
 
(1,039
)
Net loss
$
(12,944
)
 
$
(18,152
)
 
$
(28,059
)
 
$
(29,291
)
 
 
 
 
 
 
 
 
Loss per common share - Basic
$
(0.17
)
 
$
(0.23
)
 
$
(0.36
)
 
$
(0.38
)
 
 
 
 
 
 
 
 
Loss per common share - Diluted
$
(0.17
)
 
$
(0.23
)
 
$
(0.36
)
 
$
(0.38
)
 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
78,430

 
77,944

 
78,371

 
77,776

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
78,430

 
77,944

 
78,371

 
77,776
















See accompanying notes to condensed consolidated financial statements.



4


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(unaudited)

 
As of and for the six months ended June 30, 2019
 
Shares
 
Amount
 
Additional Paid In Capital
 
Accumulated
Deficit
 
Total Shareholders’ Equity
Common
 
Treasury
Common
 
Treasury
 
(in thousands)
Balance as of December 31, 2018
79,005

 
(790
)
 
$
7,900

 
$
(4,965
)
 
$
550,548

 
$
(388,425
)
 
$
165,058

Net loss
—

 
—

 
—

 
—

 
—

 
(15,115
)
 
(15,115
)
Purchase of treasury stock
—

 
(84
)
 
—

 
(120
)
 
—

 
—

 
(120
)
Cumulative-effect adjustment due to adoption of ASC Topic 842
—

 
—

 
—

 
—

 
—

 
277

 
277

Issuance of restricted stock
326

 
—

 
33

 
—

 
(33
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
867

 
—

 
867

Balance as of March 31, 2019
79,331

 
(874
)
 
$
7,933

 
$
(5,085
)
 
$
551,382

 
$
(403,263
)
 
$
150,967

Net loss
—

 
—

 
—

 
—

 
—

 
(12,944
)
 
(12,944
)
Purchase of treasury stock
—

 
(3
)
 
—

 
(5
)
 
—

 
—

 
(5
)
Issuance of restricted stock
667

 
—

 
67

 
—

 
(67
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
327

 
—

 
327

Balance as of June 30, 2019
79,998

 
(877
)
 
$
8,000

 
$
(5,090
)
 
$
551,642

 
$
(416,207
)
 
$
138,345



 
As of and for the six months ended June 30, 2018
 
Shares
 
Amount
 
Additional Paid In Capital
 
Accumulated
Deficit
 
Total Shareholders’ Equity
Common
 
Treasury
Common
 
Treasury
 
(in thousands)
Balance as of December 31, 2017
78,350

 
(631
)
 
$
7,835

 
$
(4,416
)
 
$
546,158

 
$
(339,481
)
 
$
210,096

Net loss
—

 
—

 
—

 
—

 
—

 
(11,139
)
 
(11,139
)
Purchase of treasury stock
—

 
(28
)
 
—

 
(96
)
 
—

 
—

 
(96
)
Cumulative-effect adjustment due to adoption of ASC Topic 606
—

 
—

 
—

 
—

 
—

 
67

 
67

Issuance of restricted stock
105

 
—

 
10

 
—

 
(10
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
1,259

 
—

 
1,259

Balance as of March 31, 2018
78,455

 
(659
)
 
$
7,845

 
$
(4,512
)
 
$
547,407

 
$
(350,553
)
 
$
200,187

Net loss
—

 
—

 
—

 
—

 
—

 
(18,152
)
 
(18,152
)
Exercise of options
3

 
—

 
—

 
—

 
12

 
—

 
12

Purchase of treasury stock
—

 
(131
)
 
—

 
(453
)
 
—

 
—

 
(453
)
Issuance of restricted stock
547

 
—

 
55

 
—

 
(55
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
1,097

 
—

 
1,097

Balance as of June 30, 2018
79,005

 
(790
)
 
$
7,900

 
$
(4,965
)
 
$
548,461

 
$
(368,705
)
 
$
182,691







See accompanying notes to condensed consolidated financial statements.



5


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Six months ended June 30,
 
2019
 
2018
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(28,059
)
 
$
(29,291
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Depreciation
45,504

 
47,034

Allowance for doubtful accounts, net of recoveries
(286
)
 
(422
)
Gain on dispositions of property and equipment, net
(2,201
)
 
(1,061
)
Stock-based compensation expense
1,194

 
2,356

Phantom stock compensation expense
51

 
6,529

Amortization of debt issuance costs and discount
1,541

 
1,422

Impairment
1,378

 
2,368

Deferred income taxes
1,225

 
273

Change in other noncurrent assets
1,476

 
(199
)
Change in other noncurrent liabilities
(2,493
)
 
(10,009
)
Changes in current assets and liabilities:
 
 
 
Receivables
(14,858
)
 
(12,368
)
Inventory
(3,864
)
 
(3,662
)
Prepaid expenses and other current assets
(108
)
 
(785
)
Accounts payable
10,697

 
5,858

Deferred revenues
(302
)
 
619

Accrued expenses
(6,849
)
 
8,463

Net cash provided by operating activities
4,046

 
17,125

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(31,382
)
 
(31,485
)
Proceeds from sale of property and equipment
3,439

 
2,225

Proceeds from insurance recoveries
588

 
541

Net cash used in investing activities
(27,355
)
 
(28,719
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from exercise of options
—

 
12

Purchase of treasury stock
(125
)
 
(549
)
Net cash used in financing activities
(125
)
 
(537
)
 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
(23,434
)
 
(12,131
)
Beginning cash, cash equivalents and restricted cash
54,564

 
75,648

Ending cash, cash equivalents and restricted cash
$
31,130

 
$
63,517

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
18,832

 
$
18,073

Income tax paid
$
2,156

 
$
1,789

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
(3,766
)
 
$
2,440

 








See accompanying notes to condensed consolidated financial statements.



6


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. We provide a comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling rigs . Our drilling rigs are equipped with 1,500 horsepower or greater drawworks, are 100% pad-capable and offer 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
17

 
—

 
17
International drilling
—

 
8

 
8
 
 
 
 
 
25
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. As of June 30, 2019 , the fleet count for each of our production services business segments are as follows:
 
550 HP
 
600 HP
 
Total
Well servicing rigs, by horsepower (HP) rating
113
 
12
 
125
 
 
 
 
 
 
 
 
 
 
 
Total
Wireline services units
 
95
Coiled tubing services units
 
9
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, 2018 .
Use of Estimates — In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our estimates of certain variable revenues and amortization periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance and our estimate of compensation related accruals.



7


Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after June 30, 2019 , 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.
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.
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 former lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements , which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC Topic 606,  Revenue from Contracts with Customers , when the non-lease component is the predominant element of the combined component.
As a lessor, we elected to apply the practical expedient which allows us to continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our unaudited condensed consolidated statements of operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and office equipment leases, for which we recognized an operating lease asset and a corresponding operating lease liability on our unaudited condensed consolidated balance sheet of $9.8 million at the adoption date of January 1, 2019. For leases that commenced prior to adoption of ASC Topic 842 , we elected to apply the package of practical expedients which allows us to carry forward the historical lease classification. The adoption of ASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related to the write off of previously unamortized deferred lease liabilities at the date of adoption. For more information about the accounting under ASC Topic 842, and disclosures under the new standard, see Note 3 , Leases .
Additional Detail of Account Balances
Cash Equivalents and Restricted Cash — Cash equivalents at June 30, 2019 and December 31, 2018 were $11.8 million and $40.6 million , respectively, consisting of investments in highly-liquid money-market mutual funds . Our restricted cash balance reflects the portion of net proceeds from the issuance of our senior secured term loan which are currently held in a restricted account until the completion of certain administrative tasks related to providing access rights to certain of our real property.
Other Receivables — Our other receivables primarily consist of recoverable taxes related to our international operations, as well as net income and sales tax receivables.
Prepaid Expenses and Other Current Assets — Prepaid expenses and other current assets include items such as insurance, rent deposits, software subscriptions and other fees. We routinely expense these items in the normal course of business over the periods that we benefit from these expenses. Prepaid expenses and other current assets also include deferred mobilization costs for short-term drilling contracts.
Other Noncurrent Assets — Other noncurrent assets consist of deferred mobilization costs on long-term drilling contracts, cash deposits related to the deductibles on our workers’ compensation insurance policies, and deferred compensation plan investments.



8


Other Accrued Expenses — Our other accrued expenses include accruals for items such as sales taxes, property taxes, withholding tax liability related to our international operations, and professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Our other accrued expenses also includes the current portion of the lease liability associated with our long-term operating leases.
Other Noncurrent Liabilities — Our other noncurrent liabilities consist of the noncurrent portion of deferred mobilization revenues and liabilities associated with our long-term compensation plans.
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 (ranging in duration from several hours to 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. Daywork contracts are comprehensive agreements under which we provide a comprehensive service offering, including the drilling rig, crew, supplies and most of the ancillary equipment necessary to operate the rig. Contract modifications that extend the term of a dayrate contract are generally accounted for prospectively as a separate dayrate contract. We account for our services provided under daywork contracts as a single performance obligation comprised of a series of distinct time increments which are satisfied over time. Accordingly, dayrate revenues are recognized in the period during which the services are performed.
With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service and are recognized ratably over the related contract term.
The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced (or no) payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.
The upfront costs that we incur to mobilize the drilling rig to our client’s initial drilling site are capitalized and recognized ratably over the term of the related contract, including any contracted renewal or extension periods, which is our estimate of the period during which we expect to benefit from the cost of mobilizing the rig. Costs associated with the final demobilization at the end of the contract term are expensed when incurred, when the demobilization activity is performed.
We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues, many of which are variable, or dependent upon the activity that is actually performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments.
All of our revenues are recognized net of sales taxes, when applicable.
Contract Asset and Liability Balances and Contract Cost Assets
Contract asset and contract liability balances relate to demobilization and mobilization revenues, respectively. Demobilization revenue that we expect to receive is recognized ratably over the related contract term, but invoiced upon completion of the demobilization activity. Mobilization revenue, which is typically collected upon the completion of the initial mobilization activity, is deferred and recognized ratably over the related contract term. Contract asset and liability



9


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, 2019 and December 31, 2018 were as follows (amounts in thousands):
 
June 30, 2019
 
December 31, 2018
Current deferred revenues
$
1,420

 
$
1,722

Current deferred costs
978

 
1,543

 
 
 
 
Noncurrent deferred revenues
$
313

 
$
437

Noncurrent deferred costs
581

 
679

The changes in deferred revenue and cost balances during the six months ended June 30, 2019 are primarily related to the amortization of deferred revenues and costs during the period, largely offset by increases related to the deployment of four domestic rigs and one international rig under new term contracts in 2019. Amortization of deferred revenues and costs during the three and six months ended June 30, 2019 and 2018 were as follows (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Amortization of deferred revenues
$
1,280

 
$
542

 
$
2,235

 
$
1,041

Amortization of deferred costs
1,110

 
486

 
2,096

 
949

In February 2019, one of our domestic clients elected to early terminate their contract with us and make an upfront early termination payment based on a per day rate for the remaining term of the contract, resulting in $0.4 million of revenues associated with the 34 days that were remaining under the contract term. We subsequently placed this rig with another client. As of June 30, 2019 , all but two of our 25 rigs are earning under daywork contracts, 14 of which are domestic term contracts . Unlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 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.
3 .      Leases
As a drilling and production services provider, we provide the drilling rigs and production services equipment which are necessary to fulfill our performance obligations and which are considered leases under ASU No. 2016-02, Leases, ( together with its amendments, herein referred to as “ASC Topic 842”). However, ASU No. 2018-11, Leases: Targeted Improvements , allows lessors to (i) combine the lease and non-lease components of revenues when the revenue recognition pattern is the same and when the lease component, when accounted for separately, would be considered an operating lease, and (ii) account for the combined lease and non-lease components under ASC Topic 606,  Revenue from Contracts with Customers , when the non-lease component is the predominant element of the combined component. We elected to apply this expedient and therefore continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our unaudited condensed consolidated statements of operations.
As a lessee, we lease our corporate office headquarters in San Antonio, Texas, and we conduct our business operations through 27 other regional offices located throughout the United States and internationally in Colombia. These operating locations typically include regional offices, storage and maintenance yards and employee housing sufficient to support our operations in the area . We lease most of these properties under non-cancelable term and month-to-month operating leases, many of which contain renewal options that can extend the lease term from one to five years and some of which contain escalation clauses. We also lease supplemental equipment, typically under cancelable short-term and very short term (less than 30 days) leases. Due to the nature of our business, any option to renew these short-term leases, and the options to extend certain of our long-term real estate leases, are generally not considered reasonably certain to be exercised. Therefore,



10


the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease liability balances.
In accordance with ASC Topic 842, we recognize an operating lease asset and a corresponding operating lease liability for all our long-term leases, which include real estate and office equipment leases, for which we elected to combine, or not separate, the lease and non-lease components, and therefore, all fixed charges associated with non-lease components are included in the lease payments and the calculation of the operating lease asset and associated lease liability. The operating lease asset and operating lease liability are discounted at the rate which represents our secured incremental borrowing rate, as most of our leases do not provide an implicit rate, and which we estimate based on the rate in effect under our asset-based lending facility.
We recognize rent expense on a straight-line basis, except for certain variable expenses which are recognized when the variability is resolved, typically during the period in which they are paid. Variable lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of office equipment (for example, copiers), which totaled approximately $0.3 million and $0.6 million during the three and six months ended June 30, 2019 . The following table summarizes our lease expense recognized for the three and six months ending June 30, 2019 , excluding variable lease costs (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2019
Long-term operating lease expense
$
829

 
$
1,671

Short-term operating lease expense
$
4,333

 
$
7,736

The following table summarizes the amount and timing of our obligations associated with our long-term operating leases (amounts in thousands):
 
June 30, 2019
 
December 31, 2018
Within 1 year
$
2,659

 
$
3,318

In the second year
1,964

 
2,032

In the third year
1,658

 
1,721

In the fourth year
1,358

 
1,407

In the fifth year
905

 
1,110

Thereafter
1,268

 
1,738

Total undiscounted lease obligations
$
9,812

 
$
11,326

Impact of discounting
(995
)
 
 
Discounted value of operating lease obligations
$
8,817

 
 
 
 
 
 
Current operating lease liabilities
$
2,322

 
 
Noncurrent operating lease liabilities
6,495

 
 
 
$
8,817

 
 
The following table summarizes the weighted-average remaining lease term and discount rate associated with our long-term operating leases:
 
June 30, 2019
Weighted-average remaining lease term (in years)
4.8

Weighted-average discount rate
4.5
%
4 .     Property and Equipment
Capital Expenditures — Our capital expenditures were $27.6 million and $33.9 million during the six months ended June 30, 2019 and 2018 , respectively. Capital expenditures during the six months ended June 30, 2019 primarily related to various upgrades and refurbishments of our drilling and production services fleets, various vehicle and ancillary equipment purchases, and the completion of construction on our 17 th AC drilling rig which we deployed in March. 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

11



in all business segments, and capital projects to upgrade and refurbish certain of our international and domestic drilling rigs.
At June 30, 2019 , capital expenditures incurred for property and equipment not yet placed in service was $6.0 million , primarily related to support equipment for our coiled tubing and drilling rig services fleets and capital projects to upgrade and refurbish certain components of our drilling rig fleet. At December 31, 2018 , property and equipment not yet placed in service was $19.6 million , primarily related to approximately $8.0 million of costs for the construction of a new-build drilling rig, various refurbishments and upgrades of drilling and production services equipment, and the purchase of other new ancillary equipment.
Gain/Loss on Disposition of Property — During the six months ended June 30, 2019 , we recognized a net gain of $2.2 million on the disposition of drill pipe and various other property and equipment, including some assets which were previously held for sale, as well as insurance proceeds received for damaged equipment . During the six months ended June 30, 2018 , we recognized a net gain 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.
Assets Held for Sale — As of June 30, 2019 , our condensed consolidated balance sheet reflects assets held for sale of $6.0 million , which includes the fair value of one domestic SCR drilling rig, two coiled tubing units, 12 wireline units, spare support equipment, and buildings and yards for two closed wireline locations, both of which were designated as held for sale in the second quarter of 2019. As of December 31, 2018 , our condensed consolidated balance sheet reflects assets held for sale of $3.6 million , which primarily represents the fair value of one domestic SCR drilling rig and related spare equipment and three coiled tubing units.
During the six months ended June 30, 2019 and 2018 , we recognized impairment charges of $1.4 million and $2.4 million 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 .
Impairments — In accordance with ASC Topic 360, Property, Plant and Equipment , we monitor all indicators of potential impairments, and concluded there are no triggers present that require impairment testing as of June 30, 2019 , other than the placement of certain assets as held for sale.
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). In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of the assets grouped at the lowest level that independent cash flows can be identified. We perform an impairment evaluation and estimate future undiscounted cash flows for each of our reporting units separately, which are our domestic drilling services, international drilling services, well servicing, wireline services and coiled tubing services segments. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group, and the amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of the assets.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures . 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 analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions.
5 .
Valuation Allowances on Deferred Tax Assets
Our deferred tax assets related to net operating losses, which are available to reduce future taxable income, consist of the following (amounts in thousands):
 
June 30, 2019
 
December 31, 2018
Domestic net operating loss carryforward
$
100,110

 
$
96,777

Foreign net operating loss carryforward
8,083

 
9,582


12



The majority of our domestic net operating losses will begin to expire in 2030 , while losses generated after 2017 are carried forward indefinitely but are limited in usage to 80% of taxable income. The majority of our foreign net operating losses are carried forward indefinitely, but losses generated after 2016 are carried forward for 12 years and will begin to expire in 2029.
We provide a valuation allowance when it is more likely than not that some portion of the deferred tax assets will not be realized. As result, as of June 30, 2019 and December 31, 2018 , we had valuation allowances of $67.2 million and $62.6 million that offset a portion of our domestic and foreign net deferred tax assets.
Since 2017, market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we may determine that there is sufficient evidence that future taxable income will be generated to utilize our foreign deferred tax assets which would result in the reversal of the valuation allowance relating to our foreign deferred tax assets.
6 .      Debt
Our debt consists of the following (amounts in thousands):
 
June 30, 2019
 
December 31, 2018
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%)
(2,278
)
 
(2,668
)
Less unamortized debt issuance costs
(6,629
)
 
(7,780
)
 
$
466,093

 
$
464,552

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 previous 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.

13



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, 2019 , we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $59.8 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.



14


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, 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 12 , 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.
7 .
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.



15


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, 2019 and December 31, 2018 , the aggregate estimated fair value of our phantom stock unit awards was $0.8 million and $5.1 million , respectively, for which the vested portion recognized as a liability in our condensed consolidated balance sheets was $0.2 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 9 , 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, 2019
 
December 31, 2018
 
Hierarchy Level
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Senior notes
2
 
$
297,411

 
$
141,000

 
$
296,988

 
$
186,750

Senior secured term loan
3
 
168,682

 
$
166,250

 
167,564

 
175,875

 
 
 
$
466,093

 
$
307,250

 
$
464,552

 
$
362,625

8 .
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,
 
2019
 
2018
 
2019
 
2018
Numerator (both basic and diluted):
 
 
 
 
 
 
 
Net loss
$
(12,944
)
 
$
(18,152
)
 
$
(28,059
)
 
$
(29,291
)
Denominator:
 
 
 
 
 
 
 
Weighted-average shares (denominator for basic earnings (loss) per share)
78,430

 
77,944

 
78,371

 
77,776

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

 
—

 
—

 
—

Denominator for diluted earnings (loss) per share
78,430

 
77,944

 
78,371

 
77,776

Loss per common share - Basic
$
(0.17
)
 
$
(0.23
)
 
$
(0.36
)
 
$
(0.38
)
Loss per common share - Diluted
$
(0.17
)
 
$
(0.23
)
 
$
(0.36
)
 
$
(0.38
)
Potentially dilutive securities excluded as anti-dilutive
4,858

 
4,055

 
3,709

 
5,015

9 .
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.



16


We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation, and we recognize forfeitures when they occur. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense (benefit) recognized for phantom stock unit awards during the three and six months ended June 30, 2019 and 2018 (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Stock option awards
$
23

 
$
99

 
$
74

 
$
241

Restricted stock awards
121

 
115

 
235

 
228

Restricted stock unit awards
183

 
883

 
885

 
1,887

 
$
327

 
$
1,097

 
$
1,194

 
$
2,356

Phantom stock unit awards
$
(797
)
 
$
6,099

 
$
51

 
$
6,529

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. We did not grant any stock option awards during the six months ended June 30, 2019 or 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.
There were no performance-based restricted stock unit awards granted during the six months ended June 30, 2019 or 2018 . The following table summarizes the number and weighted-average grant-date fair value of the restricted stock and time-based restricted stock unit awards granted during the three and six months ended June 30, 2019 and 2018 :
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Restricted Stock:
 
 
 
 
 
 
 
Restricted stock awards granted
648,100

 
78,632

 
648,100

 
78,632

Weighted-average grant-date fair value (per share)
$
0.79

 
$
5.85

 
$
0.79

 
$
5.85

Time-based RSUs:
 
 
 
 
 
 
 
Time-based RSUs granted
—

 
—

 
870,648

 
788,377

Weighted-average grant-date fair value (per unit)
$
—

 
$
—

 
$
1.38

 
$
3.85

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 cliff vest at 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. As of June 30, 2019 , we estimate that the achievement level for our outstanding performance-based RSUs granted in 2017 will be approximately 80% of the predetermined performance conditions .

17



Phantom Stock Unit Awards
We grant phantom stock unit awards with vesting based on time of service, performance and market conditions. Time-based phantom stock unit awards, which were granted in 2019, vest annually in thirds over a three-year vesting period. Performance-based phantom stock unit awards, which were granted in 2016, 2018 and 2019, cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of performance-based 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. 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 an applicable maximum payout feature that is based on a multiple of the grant date stock price.
The fair value of time-based phantom stock unit awards is measured using a Black-Scholes pricing model and the fair value of performance-based phantom stock unit awards is measured using a Monte Carlo simulation model, with inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures .
There were no phantom stock unit awards granted during the three months ended June 30, 2019 or 2018 . The following table summarizes the number, weighted-average grant-date fair value, and applicable maximum cash value of the phantom stock unit awards granted during the six months ended June 30, 2019 and 2018 :
 
Six months ended June 30,
 
2019
 
2018
Performance-based:
 
 
 
Phantom stock unit awards granted
2,467,776

 
1,188,216

Weighted-average grant-date fair value (per unit)
$
1.10

 
$
3.06

Maximum cash value per unit (three times the grant date stock price)
$
4.62

 
$
9.66

Time-based:
 
 
 
Phantom stock unit awards granted
810,648

 
—

Weighted-average grant-date fair value (per unit)
$
1.17

 
$
—

Maximum cash value per unit (three times the grant date stock price)
$
4.62

 
$
—

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, which was $0.25 as of June 30, 2019 , if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $1.0 million , which represents the hypothetical increase in fair value of the liability for the 2018 and 2019 phantom stock unit awards. The maximum payout feature of these awards would limit this volatility if the stock price exceeds the maximum payout threshold. As of June 30, 2019 , we estimate the weighted-average achievement level for our outstanding phantom stock unit awards granted in 2018 and 2019 to be 100% .
In April 2019 , we determined that 175% of the target number of phantom stock unit awards granted during 2016 were earned based on the Company’s achievement of the performance measures, as compared to the predefined peer group, which resulted in an aggregate cash payment of $3.5 million to settle these awards .

18



10 .
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), which reflects the basis used by management in making decisions regarding our business for resource allocation and performance assessment, as required by ASC Topic 280, Segment Reporting .
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. We provide a comprehensive service offering which includes the drilling rig, crews, supplies 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.



19


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,
 
2019
 
2018
 
2019
 
2018
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
39,652

 
$
35,634

 
$
77,661

 
$
71,560

International drilling
25,422

 
21,773

 
47,065

 
39,384

Drilling services
65,074

 
57,407

 
124,726

 
110,944

Well servicing
29,506

 
23,162

 
55,760

 
44,276

Wireline services
47,386

 
62,137

 
93,260

 
118,738

Coiled tubing services
10,877

 
12,076

 
25,665

 
25,302

Production services
87,769

 
97,375

 
174,685

 
188,316

Consolidated revenues
$
152,843

 
$
154,782

 
$
299,411

 
$
299,260

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
24,698

 
$
21,749

 
$
47,167

 
$
42,647

International drilling
18,555

 
17,064

 
35,040

 
30,025

Drilling services
43,253

 
38,813

 
82,207

 
72,672

Well servicing
21,038

 
16,680

 
39,934

 
32,250

Wireline services
41,804

 
46,716

 
81,151

 
89,202

Coiled tubing services
9,875

 
11,988

 
21,263

 
22,839

Production services
72,717

 
75,384

 
142,348

 
144,291

Consolidated operating costs
$
115,970

 
$
114,197

 
$
224,555

 
$
216,963

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
14,954

 
$
13,885

 
$
30,494

 
$
28,913

International drilling
6,867

 
4,709

 
12,025

 
9,359

Drilling services
21,821

 
18,594

 
42,519

 
38,272

Well servicing
8,468

 
6,482

 
15,826

 
12,026

Wireline services
5,582

 
15,421

 
12,109

 
29,536

Coiled tubing services
1,002

 
88

 
4,402

 
2,463

Production services
15,052

 
21,991

 
32,337

 
44,025

Consolidated gross margin
$
36,873

 
$
40,585

 
$
74,856

 
$
82,297

 
 
 
 
 
 
 
 
Identifiable Assets:
 
 
 
 
 
 
 
Domestic drilling  (1)
$
365,477

 
$
380,355

 
$
365,477

 
$
380,355

International drilling (1) (2)
47,158

 
42,457

 
47,158

 
42,457

Drilling services
412,635

 
422,812

 
412,635

 
422,812

Well servicing
121,180

 
124,458

 
121,180

 
124,458

Wireline services
94,413

 
99,243

 
94,413

 
99,243

Coiled tubing services
37,292

 
31,889

 
37,292

 
31,889

Production services
252,885

 
255,590

 
252,885

 
255,590

Corporate
58,149

 
78,642

 
58,149

 
78,642

Consolidated identifiable assets
$
723,669

 
$
757,044

 
$
723,669

 
$
757,044

 
 
 
 
 
 
 
 
Depreciation:
 
 
 
 
 
 
 
Domestic drilling
$
10,888

 
$
10,139

 
$
21,433

 
$
20,588

International drilling
1,373

 
1,301

 
2,716

 
2,748

Drilling services
12,261

 
11,440

 
24,149

 
23,336

Well servicing
4,942

 
4,865

 
9,824

 
9,785

Wireline services
3,907

 
4,601

 
7,982

 
9,209

Coiled tubing services
1,531

 
2,114

 
3,059

 
4,146

Production services
10,380

 
11,580

 
20,865

 
23,140

Corporate
210

 
267

 
490

 
558

Consolidated depreciation
$
22,851

 
$
23,287

 
$
45,504

 
$
47,034

 
 
 
 
 
 
 
 



20


 
As of and for the three months ended June 30,
 
As of and for the six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Capital Expenditures:
 
 
 
 
 
 
 
Domestic drilling
$
3,325

 
$
4,736

 
$
11,567

 
$
7,494

International drilling
524

 
1,213

 
2,282

 
3,913

Drilling services
3,849

 
5,949

 
13,849

 
11,407

Well servicing
2,141

 
3,403

 
6,036

 
5,452

Wireline services
1,588

 
4,917

 
4,423

 
8,590

Coiled tubing services
1,287

 
4,817

 
2,811

 
7,981

Production services
5,016

 
13,137

 
13,270

 
22,023

Corporate
376

 
251

 
497

 
495

Consolidated capital expenditures
$
9,241

 
$
19,337

 
$
27,616

 
$
33,925

(1)
Identifiable assets for our drilling segments include the impact of a $38.6 million and $35.1 million intercompany balance, as of June 30, 2019 and 2018 , 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,
 
2019
 
2018
 
2019
 
2018
Consolidated gross margin
$
36,873

 
$
40,585

 
$
74,856

 
$
82,297

Depreciation
(22,851
)
 
(23,287
)
 
(45,504
)
 
(47,034
)
General and administrative
(18,028
)
 
(24,829
)
 
(37,786
)
 
(44,023
)
Bad debt recovery, net
348

 
370

 
286

 
422

Impairment
(332
)
 
(2,368
)
 
(1,378
)
 
(2,368
)
Gain on dispositions of property and equipment, net
1,126

 
726

 
2,201

 
1,061

Loss from operations
$
(2,864
)
 
$
(8,803
)
 
$
(7,325
)
 
$
(9,645
)
11 .
Commitments and Contingencies
In connection with our operations in Colombia, our foreign subsidiaries routinely obtain bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $63.0 million relating to our performance under these bonds as of June 30, 2019 . Based on historical experience and information currently available, we believe the likelihood of demand for payment under these bonds and guarantees is remote.
We are currently undergoing sales and use tax audits for multi-year periods. As of June 30, 2019 and December 31, 2018 , our accrued liability was $1.8 million and $1.7 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.



21


12 .
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, 2019 , 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.



22


CONDENSED CONSOLIDATING BALANCE SHEETS
(unaudited, in thousands)
 
June 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
25,591

 
$
—

 
$
4,541

 
$
—

 
$
30,132

Restricted cash
998

 
—

 
—

 
—

 
998

Receivables, net of allowance
169

 
108,747

 
36,088

 
568

 
145,572

Intercompany receivable (payable)
(27,363
)
 
65,708

 
(38,345
)
 
—

 
—

Inventory
—

 
11,784

 
11,016

 
—

 
22,800

Assets held for sale
—

 
5,962

 
—

 
—

 
5,962

Prepaid expenses and other current assets
2,301

 
3,591

 
1,169

 
—

 
7,061

Total current assets
1,696

 
195,792

 
14,469

 
568

 
212,525

Net property and equipment
2,029

 
471,153

 
27,661

 
—

 
500,843

Investment in subsidiaries
570,070

 
31,020

 
—

 
(601,090
)
 
—

Deferred income taxes
43,490

 
—

 
—

 
(43,490
)
 
—

Operating lease assets
3,353

 
4,779

 
643

 
—

 
8,775

Other noncurrent assets
616

 
485

 
425

 
—

 
1,526

Total assets
$
621,254

 
$
703,229

 
$
43,198

 
$
(644,012
)
 
$
723,669

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
2,798

 
$
32,324

 
$
5,897

 
$
—

 
$
41,019

Deferred revenues
—

 
528

 
892

 
—

 
1,420

Accrued expenses
10,266

 
48,063

 
4,664

 
568

 
63,561

Total current liabilities
13,064

 
80,915

 
11,453

 
568

 
106,000

Long-term debt, less unamortized discount and debt issuance costs
466,093

 
—

 
—

 
—

 
466,093

Noncurrent operating lease liabilities
2,968

 
3,034

 
493

 
—

 
6,495

Deferred income taxes
—

 
48,403

 
—

 
(43,490
)
 
4,913

Other noncurrent liabilities
784

 
807

 
232

 
—

 
1,823

Total liabilities
482,909

 
133,159

 
12,178

 
(42,922
)
 
585,324

Total shareholders’ equity
138,345

 
570,070

 
31,020

 
(601,090
)
 
138,345

Total liabilities and shareholders’ equity
$
621,254

 
$
703,229

 
$
43,198

 
$
(644,012
)
 
$
723,669

 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
50,350

 
$
—

 
$
3,216

 
$
—

 
$
53,566

Restricted cash
998

 
—

 
—

 
—

 
998

Receivables, net of allowance
436

 
95,030

 
35,219

 
196

 
130,881

Intercompany receivable (payable)
(27,245
)
 
67,098

 
(39,853
)
 
—

 
—

Inventory
—

 
9,945

 
8,953

 
—

 
18,898

Assets held for sale
—

 
3,582

 
—

 
—

 
3,582

Prepaid expenses and other current assets
1,743

 
3,197

 
2,169

 
—

 
7,109

Total current assets
26,282

 
178,852

 
9,704

 
196

 
215,034

Net property and equipment
2,022

 
494,376

 
28,460

 
—

 
524,858

Investment in subsidiaries
574,695

 
25,370

 
—

 
(600,065
)
 
—

Deferred income taxes
42,585

 
—

 
—

 
(42,585
)
 
—

Other noncurrent assets
596

 
511

 
551

 
—

 
1,658

Total assets
$
646,180

 
$
699,109

 
$
38,715

 
$
(642,454
)
 
$
741,550

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,093

 
$
26,795

 
$
6,246

 
$
—

 
$
34,134

Deferred revenues
—

 
95

 
1,627

 
—

 
1,722

Accrued expenses
14,020

 
49,640

 
5,056

 
196

 
68,912

Total current liabilities
15,113

 
76,530

 
12,929

 
196

 
104,768

Long-term debt, less unamortized discount and debt issuance costs
464,552

 
—

 
—

 
—

 
464,552

Deferred income taxes
—

 
46,273

 
—

 
(42,585
)
 
3,688

Other noncurrent liabilities
1,457

 
1,611

 
416

 
—

 
3,484

Total liabilities
481,122

 
124,414

 
13,345

 
(42,389
)
 
576,492

Total shareholders’ equity
165,058

 
574,695

 
25,370

 
(600,065
)
 
165,058

Total liabilities and shareholders’ equity
$
646,180

 
$
699,109

 
$
38,715

 
$
(642,454
)
 
$
741,550




23


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)

 
Three months ended June 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
127,421

 
$
25,422

 
$
—

 
$
152,843

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
97,417

 
18,553

 
—

 
115,970

Depreciation and amortization
210

 
21,268

 
1,373

 
—

 
22,851

General and administrative
6,907

 
10,579

 
677

 
(135
)
 
18,028

Intercompany leasing
—

 
(1,215
)
 
1,215

 
—

 
—

Bad debt expense (recovery), net
—

 
(348
)
 
—

 
—

 
(348
)
Impairment
—

 
332

 
—

 
—

 
332

Gain on dispositions of property and equipment, net
—

 
(1,121
)
 
(5
)
 
—

 
(1,126
)
Total costs and expenses
7,117

 
126,912

 
21,813

 
(135
)
 
155,707

Income (loss) from operations
(7,117
)
 
509

 
3,609

 
135

 
(2,864
)
Other income (expense):

 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
3,305

 
3,431

 
—

 
(6,736
)
 
—

Interest expense
(10,059
)
 
(1
)
 
(45
)
 
—

 
(10,105
)
Other income (expense)
91

 
401

 
(8
)
 
(135
)
 
349

Total other income (expense), net
(6,663
)
 
3,831

 
(53
)
 
(6,871
)
 
(9,756
)
Income (loss) before income taxes
(13,780
)
 
4,340

 
3,556

 
(6,736
)
 
(12,620
)
Income tax (expense) benefit 1
836

 
(1,035
)
 
(125
)
 
—

 
(324
)
Net income (loss)
$
(12,944
)
 
$
3,305

 
$
3,431

 
$
(6,736
)
 
$
(12,944
)
 
 
 
 
 
 
 
 
 
 
 
 
 
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 expense (recovery), net
—

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


24



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)
 
Six months ended June 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
252,346

 
$
47,065

 
$
—

 
$
299,411

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
189,519

 
35,036

 
—

 
224,555

Depreciation and amortization
490

 
42,298

 
2,716

 
—

 
45,504

General and administrative
14,903

 
22,025

 
1,128

 
(270
)
 
37,786

Intercompany leasing
—

 
(2,430
)
 
2,430

 
—

 
—

Bad debt recovery, net of expense
—

 
(286
)
 
—

 
—

 
(286
)
Impairment
—

 
1,378

 
—

 
—

 
1,378

Gain on dispositions of property and equipment, net
—

 
(2,105
)
 
(96
)
 
—

 
(2,201
)
Total costs and expenses
15,393

 
250,399

 
41,214

 
(270
)
 
306,736

Income (loss) from operations
(15,393
)
 
1,947

 
5,851

 
270

 
(7,325
)
Other income (expense):

 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
6,073

 
5,895

 
—

 
(11,968
)
 
—

Interest expense
(19,933
)
 
(15
)
 
(42
)
 
—

 
(19,990
)
Other income
297

 
667

 
339

 
(270
)
 
1,033

Total other income (expense), net
(13,563
)
 
6,547

 
297

 
(12,238
)
 
(18,957
)
Income (loss) before income taxes
(28,956
)
 
8,494

 
6,148

 
(11,968
)
 
(26,282
)
Income tax (expense) benefit 1
897

 
(2,421
)
 
(253
)
 
—

 
(1,777
)
Net income (loss)
$
(28,059
)
 
$
6,073

 
$
5,895

 
$
(11,968
)
 
$
(28,059
)
 
 
 
 
 
 
 
 
 
 
 
 
 
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
)
 
 
 
 
 
 
 
 
 
 
1   The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

25



CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 
Six months ended June 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(35,104
)
 
$
35,209

 
$
3,941

 
$
—

 
$
4,046

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(314
)
 
(28,634
)
 
(2,434
)
 
—

 
(31,382
)
Proceeds from sale of property and equipment
—

 
3,376

 
63

 
—

 
3,439

Proceeds from insurance recoveries
—

 
588

 
—

 
—

 
588

 
(314
)
 
(24,670
)
 
(2,371
)
 
—

 
(27,355
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Purchase of treasury stock
(125
)
 
—

 
—

 
—

 
(125
)
Intercompany contributions/distributions
10,784

 
(10,539
)
 
(245
)
 
—

 
—

 
10,659

 
(10,539
)
 
(245
)
 
—

 
(125
)
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
(24,759
)
 
—

 
1,325

 
—

 
(23,434
)
Beginning cash, cash equivalents and restricted cash
51,348

 
—

 
3,216

 
—

 
54,564

Ending cash, cash equivalents and restricted cash
$
26,589

 
$
—

 
$
4,541

 
$
—

 
$
31,130

 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(26,626
)
 
$
37,071

 
$
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
(14,722
)
 
—

 
2,591

 
—

 
(12,131
)
Beginning cash, cash equivalents and restricted cash
72,385

 
—

 
3,263

 
—

 
75,648

Ending cash, cash equivalents and restricted cash
$
57,663

 
$
—

 
$
5,854

 
$
—

 
$
63,517

 
 






26


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. These forward-looking statements are based on our current beliefs, intentions, and expectations and are not guarantees or indicators of future performance. 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, future compliance with the listing requirements of the NYSE, 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, the occurrence of cybersecurity incidents, 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, 2018, including under the headings “Risk Factors” in Item 1A and “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I . 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.



27


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 17 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks . We provide a comprehensive service offering which includes the drilling rig, crews, supplies and most of the ancillary equipment needed to operate our drilling rigs which are deployed through our division offices in the following regions:
 
 
Rig Count
Domestic drilling:
 
 
Marcellus/Utica
 
6

Permian Basin and Eagle Ford
 
9

Bakken
 
2

International drilling
 
8

 
 
25

•
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. As of June 30, 2019 , we have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 9 locations, mostly in the Gulf Coast states, as well as in North Dakota and Colorado.
•
Wireline Services . Oil and gas exploration and production companies require wireline services to better understand the reservoirs they are drilling or producing and use logging services to accurately characterize reservoir rocks and fluids. To complete a cased-hole well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services in addition to a range of other mechanical services that are needed in order to place equipment in or retrieve equipment or debris from the wellbore, install bridge plugs and control pressure. As of June 30, 2019 , we have a fleet of 95 wireline units, including two greaseless, EcoQuiet TM units designed to reduce noise when operating in proximity to urban areas and an additional five units that offer greaseless electric wireline used to reach further depths in longer laterals. Our fleet is deployed through 12 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 flexible metal pipe which is spooled on a large reel and inserted into the wellbore to perform a variety of oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications, such as milling temporary plugs between frac stages. As of June 30, 2019 , we have a current fleet of nine coiled tubing units, consisting of four small-diameter and five large-diameter units (larger than two inches), deployed through two operating locations that provide services in Texas, Wyoming and surrounding areas.

28



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. Since then, 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. Financial information about our operating segments is included in Note 10 , Segment Information , of the Notes to Unaudited 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 reduces our exposure to the impact of regional constraints and fluctuations in demand.
Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well, and reduce the overall number of wells needed to achieve the desired production. This trend toward longer lateral wellbores also increases demand for the more specialized equipment, such as high-spec drilling rigs, higher horsepower well servicing rigs equipped with taller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed in order to drill, complete and provide services to the full length of the wellbore. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral, pad-

29



oriented environment.
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, 2018 .
Market Conditions — Our industry experienced a severe down cycle from late 2014 through 2016, during which WTI oil prices dipped below $30 per barrel 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 a high of $75 per barrel in October, but then decreased to $45 per barrel at the end of 2018. The average WTI oil price in the second quarter of 2019 increased to almost $60 per barrel.
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.
A3YRSPOTPRICESANDRIGCOUNTQ21.JPG
The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:
A1YRSPOTPRICESANDRIGCOUNTQ21.JPG



30


As of June 30, 2019 , 23 of our 25 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

 
10

 
1

 
2

 
—

 
1

International rigs
—

 
7

 
3

 
3

 
—

 
1

 
—

 
2

 
21

 
13

 
4

 
2

 
1

 
1

Unlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 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. We are actively marketing our idle drilling rigs , as well as those that have terms expiring in the near term or that we otherwise expect to complete their current contracts in the short term. We are currently negotiating renewals and new contracts for certain rigs which are set to expire in the second half of 2019, and we continue to evaluate the possibility of selling some or all of our assets in Colombia.
As compared to our drilling services businesses which generally perform one type of service under longer-term contracts, our production services businesses perform a range of services that are more short-term in nature, and for which demand can, at times, experience quicker adjustments to regional demand and capacity. As compared to the first quarter of 2019, overall demand for our well servicing business improved, our wireline business experienced relatively consistent demand with some increase in activity, and our coiled tubing business experienced decreased utilization. In addition, both our wireline and coiled tubing businesses experienced increased pricing pressure during the current quarter.
The level of exploration and production activity within a region can fluctuate due to a variety of factors which may directly or indirectly impact our operations in the region. A recent influx of coiled tubing equipment has led to excess capacity and increased competition in the South Texas and Rocky Mountain regions, while certain seasonal factors surrounding wildlife migration during the second quarter caused an interruption to the operations in affected areas of the Rocky Mountains. In Colorado, Senate Bill 19-181 was enacted in April 2019, which gives the state’s oil and gas conservation commission and the state’s local governments more authority over oil and gas operations, and which could lead to newly imposed regulations that may impede our clients’ ability to operate in the region, and similarly reduce demand for the services that we provide in this region. At the end of June 2019, we were operating ten wireline units and six well servicing rigs in Colorado, which we believe can be redeployed to other markets should future regulations negatively impact demand.
Although we expect a competitive market environment with some clients that may decrease their activity during the second half of 2019 due to budget constraints, we believe our high-quality equipment and services and our excellent safety record position us well to compete. We are focused on improving margins through realignment of certain businesses and reducing costs .
Liquidity and Capital Resources
Sources of Capital Resources
Our principal sources of liquidity currently consist of:
•
total cash and cash equivalents ( $31.1 million as of June 30, 2019 );
•
cash generated from operations ( $4.0 million during the six months ended June 30, 2019 );
•
proceeds from sales of assets ; ( $3.4 million during the six months ended June 30, 2019 ); and
•
the availability under our asset-based lending facility ( $59.8 million as of June 30, 2019 ).
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, 2019 , we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $59.8 million . Borrowings available under



31


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, 2019 , 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 assets , and available borrowings under our ABL Facility are adequate to cover our liquidity requirements for at least the next 12 months.
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.
We believe that we will have sufficient liquidity to fund our business and operations for at least the next 12 months. While the Term Loan does not mature until December 2021, we are proactively exploring various strategic and other alternatives to address the uncertainties related to our ability to refinance our outstanding debts as their maturities approach .

32



Working Capital — Our working capital was $106.5 million at June 30, 2019 , compared to $110.3 million at December 31, 2018 . Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.0 at June 30, 2019 , as compared to 2.1 at December 31, 2018 . The changes in the components of our working capital were as follows (amounts in thousands), and as described below:
 
June 30,
2019
 
December 31,
2018
 
Change
Cash and cash equivalents
$
30,132

 
$
53,566

 
$
(23,434
)
Restricted cash
998

 
998

 
—

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
90,288

 
76,924

 
13,364

Unbilled receivables
24,691

 
24,822

 
(131
)
Insurance recoveries
22,902

 
23,656

 
(754
)
Other receivables
7,691

 
5,479

 
2,212

Inventory
22,800

 
18,898

 
3,902

Assets held for sale
5,962

 
3,582

 
2,380

Prepaid expenses and other current assets
7,061

 
7,109

 
(48
)
Current assets
212,525

 
215,034

 
(2,509
)
Accounts payable
41,019

 
34,134

 
6,885

Deferred revenues
1,420

 
1,722

 
(302
)
Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
19,484

 
24,598

 
(5,114
)
Insurance claims and settlements
22,637

 
23,593

 
(956
)
Insurance premiums and deductibles
4,989

 
5,482

 
(493
)
Interest
5,754

 
6,148

 
(394
)
Other
10,697

 
9,091

 
1,606

Current liabilities
106,000

 
104,768

 
1,232

Working capital
$
106,525

 
$
110,266

 
$
(3,741
)
•
Cash and cash equivalents — The change in cash and cash equivalents during 2019 is primarily due to $31.4 million of cash used for the purchase of property and equipment, offset in part by $4.0 million of cash provided by operating activities and $3.4 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 2019 is primarily due to the 8% increase in our revenues during the quarter ended June 30, 2019 , as compared to the quarter ended December 31, 2018 , as well as lengthened collection cycles in our domestic segments, which was partially offset by a decrease in accounts receivable for our international operations which experienced higher collections during the quarter ended June 30, 2019 . Our domestic trade receivables generally turn over within 60 days, and our Colombian trade receivables generally turn over within 120 days.
•
Insurance recoveries and Insurance claims and settlements — The decrease in our insurance recoveries receivables and our insurance claims and settlements accrued expenses during 2019 is primarily due to a decrease in our insurance company’s reserve for workers’ compensation claims in excess of our deductibles.
•
Other receivables — The increase in other receivables during 2019 is primarily due to an increase in recoverable income tax receivables attributable to the increase in activity for our international operations.
•
Inventory — The increase in inventory during 2019 is due to an increase in inventory for our international operations and purchases of supplies and job materials for our wireline operations.
•
Assets held for sale — As of June 30, 2019 , our condensed consolidated balance sheet reflects assets held for sale of $6.0 million , which includes the fair value of one domestic SCR drilling rig, two coiled tubing units, 12 wireline units, spare support equipment, and buildings and yards for two closed wireline locations, both of which were designated as held for sale in the second quarter of 2019. As of December 31, 2018 , our condensed consolidated balance sheet reflects assets held for sale of $3.6 million , which primarily represents the fair value of one domestic SCR drilling rig and related spare equipment and three coiled tubing units. For additional information, see Note 4 , Property and Equipment

33



of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .
•
Accounts payable — Our accounts payable generally turn over within 90 days. The increase in accounts payable during 2019 is primarily due to lengthened payment cycles and the 12% increase in our operating costs for the quarter ended June 30, 2019 as compared to the quarter ended December 31, 2018 , partially offset by a $3.8 million decrease in our accruals for capital expenditures.
•
Accrued payroll and related employee costs — The decrease in accrued payroll and related employee costs during 2019 resulted primarily from a decrease in annual incentive compensation associated with the payment of 2018 annual bonuses which were fully accrued at December 31, 2018 and were paid in the first quarter of 2019 as well as a decrease in accrued incentive compensation for our phantom stock unit awards which were granted in 2016 and settled in cash for $3.5 million in April 2019. These decreases were partially offset by an increase in payroll-related accruals attributable in part to the timing of payments for payroll taxes as well as the 7% increase in headcount during 2019.
•
Other accrued expenses — The increase in other accrued expenses during 2019 is primarily due to the recognition of $2.3 million of current operating lease liabilities upon our adoption of ASU No. 2016-02, Leases , and its related amendments, as of January 1, 2019. For additional information about adoption of this standard, see Note 1 , Organization and Summary of Significant Accounting Policies and Note 3 , Leases , of the Notes to Unaudited Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q . The increase is partially offset, however, by a decrease in property and sales tax accruals due to the timing of payments.
Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at June 30, 2019 (amounts are undiscounted and 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
99,750

 
36,225

 
63,525

 
—

 
—

Purchase commitments
7,481

 
7,481

 
—

 
—

 
—

Operating leases
9,812

 
2,659

 
3,622

 
2,263

 
1,268

Incentive compensation
10,133

 
4,778

 
5,355

 
—

 
—

 
$
602,176

 
$
51,143

 
$
547,502

 
$
2,263

 
$
1,268

•
Debt — Debt obligations at June 30, 2019 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, 2019 , 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 10.2% interest rate that was in effect at June 30, 2019 , and (2) the principal balance of $175 million at June 30, 2019 , 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, 2019 , our purchase commitments primarily pertain to $2.5 million of inventory and job supplies for our coiled tubing operations and $1.9 million of service equipment for our coiled tubing operations . Other purchase commitments include various refurbishments and upgrades to our drilling and production services fleets as well as drilling equipment on order.
•
Operating leases — Our operating lease obligations relate to long-term lease agreements for office space, operating facilities, field personnel housing, and office equipment.
•
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.

34



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 6 , Debt , and Note 12 , Guarantor/Non-Guarantor Condensed Consolidating Financial Statements , of the Notes to Unaudited 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, 2019 , the asset coverage ratio, as calculated under the Term Loan, was 2.41 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, 2019 , 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, 2019 , we spent $31.4 million on purchases of property and equipment and placed into service property and equipment of $27.6 million . Currently, we expect to spend approximately $50 million on capital expenditures during 2019 , which includes approximately $8 million for final payments on the construction of the new-build drilling rig that began operations in the first quarter, and previous commitments on high-pressure pump packages for coiled tubing completion operations .
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 2019 from operating cash flow in excess of our working capital requirements, although proceeds from sales of assets , remaining proceeds from our Term Loan issuance, and available borrowings under our ABL Facility are also available, if necessary.

35



Results of Operations
Statements of Operations Analysis
The following table provides certain information about our operations, including details of each of our business segments’ revenues, operating costs and gross margin for the three and six months ended June 30, 2019 and 2018 (amounts in thousands) :
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
39,652

 
$
35,634

 
$
77,661

 
$
71,560

International drilling
25,422

 
21,773

 
47,065

 
39,384

Drilling services
65,074

 
57,407

 
124,726

 
110,944

Well servicing
29,506

 
23,162

 
55,760

 
44,276

Wireline services
47,386

 
62,137

 
93,260

 
118,738

Coiled tubing services
10,877

 
12,076

 
25,665

 
25,302

Production services
87,769

 
97,375

 
174,685

 
188,316

Consolidated revenues
$
152,843

 
$
154,782

 
$
299,411

 
$
299,260

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
24,698

 
$
21,749

 
$
47,167

 
$
42,647

International drilling
18,555

 
17,064

 
35,040

 
30,025

Drilling services
43,253

 
38,813

 
82,207

 
72,672

Well servicing
21,038

 
16,680

 
39,934

 
32,250

Wireline services
41,804

 
46,716

 
81,151

 
89,202

Coiled tubing services
9,875

 
11,988

 
21,263

 
22,839

Production services
72,717

 
75,384

 
142,348

 
144,291

Consolidated operating costs
$
115,970

 
$
114,197

 
$
224,555

 
$
216,963

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
14,954

 
$
13,885

 
$
30,494

 
$
28,913

International drilling
6,867

 
4,709

 
12,025

 
9,359

Drilling services
21,821

 
18,594

 
42,519

 
38,272

Well servicing
8,468

 
6,482

 
15,826

 
12,026

Wireline services
5,582

 
15,421

 
12,109

 
29,536

Coiled tubing services
1,002

 
88

 
4,402

 
2,463

Production services
15,052

 
21,991

 
32,337

 
44,025

Consolidated gross margin
$
36,873

 
$
40,585

 
$
74,856

 
$
82,297

 
 
 
 
 
 
 
 
Consolidated:
 
 
 
 
 
 
 
Net loss
$
(12,944
)
 
$
(18,152
)
 
$
(28,059
)
 
$
(29,291
)
Adjusted EBITDA (1)
$
20,668

 
$
16,896

 
$
40,590

 
$
40,305

(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.



36


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,
 
2019
 
2018
 
2019
 
2018
 
(amounts in thousands)
Net loss
$
(12,944
)
 
$
(18,152
)
 
$
(28,059
)
 
$
(29,291
)
Depreciation
22,851

 
23,287

 
45,504

 
47,034

Impairment
332

 
2,368

 
1,378

 
2,368

Interest expense
10,105

 
9,642

 
19,990

 
19,155

Income tax expense (benefit)
324

 
(249
)
 
1,777

 
1,039

Adjusted EBITDA
20,668

 
16,896

 
40,590

 
40,305

General and administrative
18,028

 
24,829

 
37,786

 
44,023

Bad debt recovery, net
(348
)
 
(370
)
 
(286
)
 
(422
)
Gain on dispositions of property and equipment, net
(1,126
)
 
(726
)
 
(2,201
)
 
(1,061
)
Other income
(349
)
 
(44
)
 
(1,033
)
 
(548
)
Consolidated gross margin
$
36,873

 
$
40,585

 
$
74,856

 
$
82,297

Consolidated gross margin — Our consolidated gross margin decreased by $3.7 million , or 9% , and $7.4 million , or 9% , for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 , due to a decline in demand for our wireline services, despite an increase in gross margin for all our other business segments. The $3.7 million and $7.4 million overall decreases in consolidated gross margin were net of $6.1 million and $10.0 million combined increases in gross margin for our drilling services, well servicing, and coiled tubing services segments.
•
Drilling Services — Our drilling services revenues increased by $7.7 million , or 13% , and $13.8 million , or 12% , for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 , while operating costs increased by $4.4 million , or 11% , and $9.5 million , or 13% , respectively. The increases in our drilling services revenues and operating costs during both periods are primarily due to higher dayrates and the deployment of our newest AC drilling rig in March 2019. The following table provides operating statistics for each of our drilling services segments:
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Domestic drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
17

 
16

 
17

 
16

Utilization rate
95
%
 
100
%
 
96
%
 
100
%
Revenue days
1,476

 
1,454

 
2,896

 
2,894

 
 
 
 
 
 
 
 
Average revenues per day
$
26,864

 
$
24,508

 
$
26,817

 
$
24,727

Average operating costs per day
16,733

 
14,958

 
16,287

 
14,736

Average margin per day
$
10,131

 
$
9,550

 
$
10,530

 
$
9,991

 
 
 
 
 
 
 
 
International drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
8

 
8

 
8

 
8

Utilization rate
86
%
 
85
%
 
83
%
 
81
%
Revenue days
623

 
621

 
1,203

 
1,171

 
 
 
 
 
 
 
 
Average revenues per day
$
40,806

 
$
35,061

 
$
39,123

 
$
33,633

Average operating costs per day
29,783

 
27,478

 
29,127

 
25,640

Average margin per day
$
11,023

 
$
7,583

 
$
9,996

 
$
7,993

Our domestic drilling average revenues and margin per day for the three and six months ended June 30, 2019 increased as compared to the corresponding periods in 2018 , primarily due to an increase in dayrates on new and extended contracts in late 2018 and early 2019, despite four rigs that re-priced downward in the second half of 2018 from historically high pre-downturn rates, as well as the deployment of our newest AC drilling rig in early 2019. Our average domestic drilling revenues and operating costs per day for the three and six months ended June 30, 2019 also increased



37


from the corresponding periods in 2018 partially due to higher mobilization and demobilization activity during 2019. Our margin per day during 2019 also benefited from $0.4 million of revenues associated with the early termination of one of our drilling contracts in February 2019.
Our international margin per day increased for the three and six months ended June 30, 2019 primarily due to reduced mobilization activity and costs during 2019, as compared to the corresponding periods in 2018 , increasing dayrates, lower standby time and additional costs incurred to deploy a previously idle rig in the first quarter of 2018. Our international drilling average revenues and operating costs per day also increased due to increased amortization of deferred mobilization revenues and costs during 2019.
•
Production Services — Our revenues from production services decreased by $9.6 million , or 10% , and $13.6 million , or 7% , for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 , while operating costs decreased $2.7 million , or 4% , and $1.9 million , or 1% , respectively. The decrease in revenue is a result of the decreased demand for wireline completion services, for which the decrease was partially offset by increased demand for our well servicing business, which experienced a 26% increase in revenue during 2019. The following table provides operating statistics for each of our production services segments:
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Well servicing:
 
 
 
 
 
 
 
Average number of rigs
125

 
125

 
125

 
125

Utilization rate
60
%
 
49
%
 
57
%
 
48
%
Rig hours
51,895

 
42,871

 
98,959

 
83,645

Average revenue per hour
$
569

 
$
540

 
$
563

 
$
529

 
 
 
 
 
 
 
 
Wireline services:
 
 
 
 
 
 
 
Average number of units
95

 
108

 
100

 
108

Number of jobs
2,278

 
3,022

 
4,620

 
5,852

Average revenue per job
$
20,802

 
$
20,562

 
$
20,186

 
$
20,290

 
 
 
 
 
 
 
 
Coiled tubing services:
 
 
 
 
 
 
 
Average number of units
9

 
14

 
9

 
14

Revenue days
307

 
350

 
658

 
764

Average revenue per day
$
35,430

 
$
34,503

 
$
39,005

 
$
33,118

Our well servicing business experienced increases in demand during the three and six months ended June 30, 2019 , as compared to the corresponding periods in 2018 , as the number of completed wells increased during the recovery of our industry, resulting in a larger inventory of producing wells that now require ongoing maintenance. Our well servicing rig hours increased by 21% and 18% , while revenues per hour increased by 5% and 6% for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 .
Our wireline services business segment experienced decreases of 25% and 21% in the number of jobs completed during the three and six months ended June 30, 2019 , as compared to the corresponding periods in 2018 , respectively, while average revenues per job during these periods were relatively consistent. These decreases in activity were primarily a result of decreased demand for completion-related activity as compared to the corresponding period in 2018, during which time we experienced higher demand for services to complete both newly drilled wells and the remaining inventory of wells which had been drilled in prior periods but were not yet completed.
Our coiled tubing services business experienced decreases of 12% and 14% in revenue days for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 , while average revenue per day increased 3% and 18% . A recent influx of coiled tubing equipment has led to excess capacity and increased competition in the South Texas and Rocky Mountain regions, while certain seasonal factors surrounding wildlife migration during the second quarter caused an interruption to the operations in affected areas of the Rocky Mountains. The increases in average revenue per day were primarily due to a larger proportion of the work performed with larger diameter coiled tubing units, including the addition of two new large-diameter coiled tubing units which were placed in service in July and December 2018. Large-diameter coiled tubing units typically earn higher revenue rates as compared to smaller diameter coiled tubing units.



38


Depreciation expense — Our depreciation expense decreased by $0.4 million and $1.5 million for the three and six months ended June 30, 2019 , respectively, primarily in our wireline and coiled tubing segments, which currently operate with an overall smaller fleet as compared to the corresponding periods in 2018 .
Impairment — During the six months ended June 30, 2019 and 2018 , we recognized impairment charges of $1.4 million and $2.4 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 4 , 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 .
Income tax expense (benefit) — Our effective tax rates differ from the applicable U.S. statutory rates due to a number of factors, including valuation allowances, impact of permanent items and the mix of profit and loss between federal, state and international taxing jurisdictions.
General and administrative expense — Our general and administrative expense decreased by $6.8 million , or 27% , and $6.2 million , or 14% , for the three and six months ended June 30, 2019 , respectively, as compared to the corresponding periods in 2018 , primarily due to a $6.4 million decrease in our phantom stock compensation expense during 2019, attributable to the decrease in the fair value of our phantom stock unit awards.
Gain on dispositions of property and equipment, net — During the six months ended June 30, 2019 , we recognized a net gain of $2.2 million on the disposition of drill pipe and various other property and equipment, including some assets which were previously held for sale, as well as insurance proceeds received for damaged equipment . During the six months ended June 30, 2018 , we recognized a net gain 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.
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 842 discussed below, as of June 30, 2019 , 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, 2018 .
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 former lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements , which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC Topic 606,  Revenue from Contracts with Customers , when the non-lease component is the predominant element of the combined component.
As a lessor, we elected to apply the practical expedient which allows us to continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our unaudited condensed consolidated statements of operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and office equipment leases, for which we recognized an operating lease asset and a corresponding operating lease liability on our unaudited condensed consolidated balance sheet of $9.8 million at the adoption date of January 1, 2019. For leases that commenced prior to adoption of ASC Topic 842 , we elected to apply the package of practical expedients which allows us to carry forward the historical lease classification. The adoption of ASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related to the write off of previously unamortized deferred lease liabilities at the date of adoption. For more information about the accounting under ASC Topic 842, and disclosures under the new standard, see Note 3 , Leases , of the Notes to Unaudited 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



39


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. For more information, 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 .
•
In accordance with ASC Topic 360, Property, Plant and Equipment , we monitor all indicators of potential impairments, and concluded there are no triggers present that require impairment testing as of June 30, 2019 , other than the placement of certain assets as held for sale. The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures . 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 analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions. If commodity prices remain at current levels for an extended period of time, or if the demand for any of our services decreases below what we are currently projecting, our estimated cash flows may decrease, and if any of the foregoing were to occur, we could incur impairment charges on the related assets. For more information, see Note 4 , 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 .
•
As of June 30, 2019 , we had $100.1 million and $8.1 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 result, as of June 30, 2019 , we had a valuation allowance of $67.2 million that offsets a portion of our domestic and foreign net deferred tax assets. Since 2017, market conditions and operating results for our Colombian operations have improved, and if they continue to improve, then we may determine that there is sufficient evidence that future taxable income will be generated to utilize our foreign deferred tax assets which would result in the reversal of the valuation allowance relating to our foreign deferred tax assets. For more information, see Note 5 , Valuation Allowances on Deferred Tax Assets , of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1 , Financial Statements , of this Quarterly Report on Form 10-Q .
•
We use a combination of self-insurance and third-party insurance for various types of coverage. 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, as well as an additional annual aggregate deductible of $250,000 under our general liability insurance. At June 30, 2019 , our accrued insurance premiums and deductibles include approximately $1.1 million of accruals for costs incurred under the self-insurance portion of our health insurance and approximately $3.0 million of accruals for costs associated with our workers’ compensation 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 cost of administrative services associated with claims processing .
•
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



40


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 9 , 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
Our exposure to market risk primarily consists of (i) interest rate risk associated with our variable rate debt and (ii) foreign currency exchange rate risk associated with our Colombian operations.
Interest Rate Risk — We are exposed to interest rate market risk on our variable rate debt. We do not use financial instruments for trading or other speculative purposes. As of June 30, 2019 , 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, 2019 . 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, 2019 .
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 $0.2 million for the six months ended June 30, 2019 .




41


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, 2019 , 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 internal control environment.
T here has been no change in our internal control over financial reporting that occurred during the three months ended June 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



42


PART II - OTHER INFORMATION
ITEM 1 .
LEGAL PROCEEDINGS
From time to time, we are involved in routine litigation or subject to disputes or claims arising out of 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, results of operations or cash flows.

ITEM 1A.
RISK FACTORS
Except as discussed below, there has been no material change in our risk factors as previously disclosed in Item 1A – “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 (the “ 2018 Form 10-K”).  In addition to the other factors set forth in this Form 10-Q, you should carefully consider the factors discussed in Item 1A – “Risk Factors” in our 2018 Form 10-K, which could materially affect our business, financial condition or future results.
If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock.
On June 11, 2019 , we received written notification from the New York Stock Exchange (“NYSE”) that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average closing share price required to maintain listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. The notice has no immediate impact on the listing of our common stock, which will continue to be listed and traded on the NYSE during this period, subject to our compliance with other listing standards. Our common stock is permitted to continue to trade on the NYSE under the symbol “PES,” but will have an added designation of “.BC” to indicate the status of the common stock as “below compliance.”
We informed the NYSE that we intend to cure the deficiency and to return to compliance with the NYSE continued listing requirement. We have six months following receipt of the notification to regain compliance with the minimum share price requirement. We can regain compliance at any time during the six-month cure period if our common stock has a closing share price of at least $1.00 on the last trading day of any calendar month during the six-month period and also has an average closing share price of at least $1.00 over the 30-trading day period ending on the last trading day of that month.
Notwithstanding the foregoing, if we were to determine that we must cure the price condition by taking an action that would require approval of our shareholders (such as a reverse stock split), we could also regain compliance by (i) obtaining the requisite shareholder approval by no later than our next annual meeting and (ii) implementing the action promptly thereafter, such that the price of our common stock would promptly exceed $1.00 per share, provided that the price must remain above that level for at least the following 30 trading days. However, there is no assurance that our stockholders would vote for such proposal.
Further, our common stock could be delisted if (i) our average market capitalization over a consecutive 30 trading-day period is less than $15 million, or (ii) our common stock trades at an “abnormally low” price, which in either case, we would not have an opportunity to cure the deficiency, our common stock would be suspended from trading on the NYSE immediately, and the NYSE would begin the process to delist our common stock, subject to our right to appeal under NYSE rules. There is no assurance that any appeal we undertake in these or other circumstances will be successful. While we are considering various options, it may take a significant effort to cure this deficiency and regain compliance with this continued listing standard, and there can be no assurance that we will be able to cure this deficiency or if we will cease to comply with another NYSE continued listing standard.
If our common stock ultimately were to be delisted for any reason, it could negatively impact us by, among other things, reducing the liquidity and market price of our common stock, reducing the number of investors willing to hold or acquire our common stock, and negatively impacting our ability to access equity markets and obtain financing.

43



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, 2019 . The following table provides information relating to our repurchase of common shares during the quarter ended June 30, 2019 :
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
1,926

 
$
2.05

 
—

 
—

May 1 - May 31
730

 
$
0.42

 
—

 
—

June 1 - June 30
—

 
$
—

 
—

 
—

Total
2,656

 
$
1.60

 
—

 
—

(1)
The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended June 30, 2019 , 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
Not applicable.


44



ITEM 6 .
EXHIBITS
The following exhibits are filed as part of this report:

Exhibit
Number
 
Description
 
 
 
3.1*
-
 
 
 
3.2*
-
 
 
 
4.1*
-
 
 
 
4.2*
-
 
 
 
4.3*
-
 
 
 
10.1+*
 
 
 
 
31.1**
-
 
 
 
31.2**
-
 
 
 
32.1#
-
 
 
 
32.2#
-
 
 
 
101.INS
-
XBRL Instance Document
 
 
 
101.SCH
-
XBRL Taxonomy Schema Document
 
 
 
101.CAL
-
XBRL Calculation Linkbase Document
 
 
 
101.LAB
-
XBRL Label Linkbase Document
 
 
 
101.PRE
-
XBRL Presentation Linkbase Document
 
 
 
101.DEF
-
XBRL Definition Linkbase Document
 
 
 
*
Incorporated by reference to the filing indicated.
**
Filed herewith.
#
Furnished herewith.
+
Management contract or compensatory plan or arrangement.


45



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, 2019


46

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