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 September 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
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
x
 
 
 
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 October 15, 2019, there were 79,202,216 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 


TABLE OF CONTENTS
 
 
 
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45
 
 
 
 
 
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47



PART I. FINANCIAL INFORMATION
ITEM 1.
FINANCIAL STATEMENTS
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
September 30,
2019
 
December 31,
2018
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
26,955

 
$
53,566

Restricted cash
998

 
998

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
81,039

 
76,924

Unbilled receivables
20,906

 
24,822

Insurance recoveries
23,186

 
23,656

Other receivables
7,421

 
5,479

Inventory
22,086

 
18,898

Assets held for sale
6,233

 
3,582

Prepaid expenses and other current assets
6,991

 
7,109

Total current assets
195,815

 
215,034

Property and equipment, at cost
1,118,488

 
1,118,215

Less accumulated depreciation
633,233

 
593,357

Net property and equipment
485,255

 
524,858

Operating lease assets
7,692

 
—

Other noncurrent assets
931

 
1,658

Total assets
$
689,693

 
$
741,550

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
32,127

 
$
34,134

Deferred revenues
1,616

 
1,722

Accrued expenses:
 
 
 
Employee compensation and related costs
22,489

 
24,598

Insurance claims and settlements
22,991

 
23,593

Insurance premiums and deductibles
6,036

 
5,482

Interest
1,008

 
6,148

Other
12,035

 
9,091

Total current liabilities
98,302

 
104,768

Long-term debt, less unamortized discount and debt issuance costs
466,887

 
464,552

Noncurrent operating lease liabilities
6,189

 
—

Deferred income taxes
4,708

 
3,688

Other noncurrent liabilities
459

 
3,484

Total liabilities
576,545

 
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; 79,202,216 and 78,214,550 shares outstanding at September 30, 2019 and December 31, 2018, respectively
8,008

 
7,900

Additional paid-in capital
552,453

 
550,548

Treasury stock, at cost; 877,047 and 789,532 shares at September 30, 2019 and December 31, 2018, respectively
(5,090
)
 
(4,965
)
Accumulated deficit
(442,223
)
 
(388,425
)
Total shareholders’ equity
113,148

 
165,058

Total liabilities and shareholders’ equity
$
689,693

 
$
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 September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
 
(in thousands, except per share data)
 
 
 
 
 
 
 
 
Revenues
$
146,398

 
$
149,332

 
$
445,809

 
$
448,592

 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
Operating costs
108,059

 
108,961

 
332,614

 
325,924

Depreciation
22,924

 
23,501

 
68,428

 
70,535

General and administrative
30,485

 
14,043

 
68,271

 
58,066

Bad debt expense (recovery), net
196

 
111

 
(90
)
 
(311
)
Impairment
—

 
239

 
1,378

 
2,607

Loss (gain) on dispositions of property and equipment, net
17

 
(1,861
)
 
(2,184
)
 
(2,922
)
Total costs and expenses
161,681

 
144,994

 
468,417

 
453,899

Income (loss) from operations
(15,283
)
 
4,338

 
(22,608
)
 
(5,307
)
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(10,013
)
 
(9,811
)
 
(30,003
)
 
(28,966
)
Other income (expense), net
(588
)
 
498

 
445

 
1,046

Total other expense, net
(10,601
)
 
(9,313
)
 
(29,558
)
 
(27,920
)
 
 
 
 
 
 
 
 
Loss before income taxes
(25,884
)
 
(4,975
)
 
(52,166
)
 
(33,227
)
Income tax expense
(132
)
 
(258
)
 
(1,909
)
 
(1,297
)
Net loss
$
(26,016
)
 
$
(5,233
)
 
$
(54,075
)
 
$
(34,524
)
 
 
 
 
 
 
 
 
Loss per common share - Basic
$
(0.33
)
 
$
(0.07
)
 
$
(0.69
)
 
$
(0.44
)
 
 
 
 
 
 
 
 
Loss per common share - Diluted
$
(0.33
)
 
$
(0.07
)
 
$
(0.69
)
 
$
(0.44
)
 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
78,473

 
78,136

 
78,405

 
77,897

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
78,473

 
78,136

 
78,405

 
77,897















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 nine months ended September 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

Net loss
—

 
—

 
—

 
—

 
—

 
(26,016
)
 
(26,016
)
Issuance of restricted stock
81

 
—

 
8

 
—

 
(8
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
819

 
—

 
819

Balance as of September 30, 2019
80,079

 
(877
)
 
$
8,008

 
$
(5,090
)
 
$
552,453

 
$
(442,223
)
 
$
113,148




See accompanying notes to condensed consolidated financial statements.
5


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

 
As of and for the nine months ended September 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

Net loss
—

 
—

 
—

 
—

 
—

 
(5,233
)
 
(5,233
)
Stock-based compensation expense
—

 
—

 
—

 
—

 
1,039

 
—

 
1,039

Balance as of September 30, 2018
79,005

 
(790
)
 
$
7,900

 
$
(4,965
)
 
$
549,500

 
$
(373,938
)
 
$
178,497



See accompanying notes to condensed consolidated financial statements.
6


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Nine months ended September 30,
 
2019
 
2018
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(54,075
)
 
$
(34,524
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation
68,428

 
70,535

Allowance for doubtful accounts, net of recoveries
(90
)
 
(311
)
Write-off of obsolete inventory
502

 
—

Gain on dispositions of property and equipment, net
(2,184
)
 
(2,922
)
Stock-based compensation expense
2,013

 
3,395

Phantom stock compensation expense
(99
)
 
2,808

Amortization of debt issuance costs and discount
2,335

 
2,153

Impairment
1,378

 
2,607

Deferred income taxes
1,020

 
189

Change in other noncurrent assets
3,125

 
541

Change in other noncurrent liabilities
(4,163
)
 
(735
)
Changes in current assets and liabilities:
 
 
 
Receivables
(2,126
)
 
(16,549
)
Inventory
(3,652
)
 
(4,934
)
Prepaid expenses and other current assets
30

 
329

Accounts payable
2,346

 
1,527

Deferred revenues
(106
)
 
(173
)
Accrued expenses
(6,044
)
 
(2,446
)
Net cash provided by operating activities
8,638

 
21,490

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(40,543
)
 
(48,778
)
Proceeds from sale of property and equipment
4,778

 
4,665

Proceeds from insurance recoveries
641

 
980

Net cash used in investing activities
(35,124
)
 
(43,133
)
 
 
 
 
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
(26,611
)
 
(22,180
)
Beginning cash, cash equivalents and restricted cash
54,564

 
75,648

Ending cash, cash equivalents and restricted cash
$
27,953

 
$
53,468

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
32,773

 
$
31,872

Income tax paid
$
3,103

 
$
2,739

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
(4,267
)
 
$
3,564



See accompanying notes to condensed consolidated financial statements.
7


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 well, wireline and coiled tubing services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi. As of September 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
112
 
12
 
124
 
 
 
 
 
 
 
 
 
 
 
Total
Wireline services units
 
93
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.



8


Subsequent Events — In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after September 30, 2019, through the filing of this Form 10-Q, for inclusion as necessary.
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 September 30, 2019 and December 31, 2018 were $13.9 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 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.
Other Accrued Expenses — Our other accrued expenses include accruals for items such as sales taxes, property taxes, withholding tax liabilities 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.



9


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 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



10


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 September 30, 2019 and December 31, 2018 were as follows (amounts in thousands):
 
September 30, 2019
 
December 31, 2018
Current deferred revenues
$
1,616

 
$
1,722

Current deferred costs
2,418

 
1,543

 
 
 
 
Noncurrent deferred revenues
$
77

 
$
437

Noncurrent deferred costs
130

 
679

The changes in deferred revenue and cost balances during the nine months ended September 30, 2019 are primarily related to increases in deferred revenue and costs for the deployment of rigs under five new domestic and four new international contracts in 2019, offset by decreases related to the amortization of deferred revenues and costs during the period. Amortization of deferred revenues and costs during the three and nine months ended September 30, 2019 and 2018 were as follows (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Amortization of deferred revenues
$
1,219

 
$
720

 
$
3,453

 
$
1,762

Amortization of deferred costs
1,293

 
1,100

 
3,389

 
2,050

In 2019, two of our domestic clients elected to early terminate their contract with us and make upfront early termination payments based on a per day rate for the respective remaining contract term, resulting in $2.2 million and $2.6 million of revenue recognized for the three and nine months ended September 30, 2019, respectively. Currently, 21 of our 25 rigs are earning under daywork contracts, 12 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 and 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 25 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, 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



11


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 $0.9 million during the three and nine months ended September 30, 2019. The following table summarizes our lease expense recognized, excluding variable lease costs (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2019
Long-term operating lease expense
$
1,272

 
$
2,943

Short-term operating lease expense
$
3,754

 
$
11,490

The following table summarizes the amount and timing of our obligations associated with our long-term operating leases (amounts in thousands):
 
September 30, 2019
 
December 31, 2018
Within 1 year
$
2,499

 
$
3,318

In the second year
1,970

 
2,032

In the third year
1,624

 
1,721

In the fourth year
1,235

 
1,407

In the fifth year
909

 
1,110

Thereafter
1,041

 
1,738

Total undiscounted lease obligations
$
9,278

 
$
11,326

Impact of discounting
(909
)
 
 
Discounted value of operating lease obligations
$
8,369

 
 
 
 
 
 
Current operating lease liabilities
$
2,180

 
 
Noncurrent operating lease liabilities
6,189

 
 
 
$
8,369

 
 
The following table summarizes the weighted-average remaining lease term and discount rate associated with our long-term operating leases:
 
September 30, 2019
Weighted-average remaining lease term (in years)
4.7

Weighted-average discount rate
4.5
%
4.    Property and Equipment
Capital Expenditures — Our capital expenditures were $36.3 million and $52.3 million during the nine months ended September 30, 2019 and 2018, respectively. Capital expenditures during the nine months ended September 30, 2019 primarily related to various upgrades and refurbishments of our drilling and production services fleets, vehicle and ancillary equipment purchases, and the completion of construction on our 17th AC drilling rig, which we deployed in March. Capital expenditures during the nine months ended September 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, capital projects to upgrade and refurbish certain components of our international and domestic drilling rigs and begin construction of one new-build drilling rig, and vehicle fleet upgrades in all domestic business segments.
At September 30, 2019, capital expenditures incurred for property and equipment not yet placed in service was $3.3 million, primarily related to capital projects to upgrade and refurbish certain components of our drilling and well servicing rig fleets. 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.



12


Gain/Loss on Disposition of Property — During the nine months ended September 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 nine months ended September 30, 2018, we recognized a net gain of $2.9 million on the disposition of various property and equipment, including the sale of five coiled tubing units, twelve wireline units, and one drilling rig, which was previously held for sale.
Assets Held for Sale — As of September 30, 2019, our condensed consolidated balance sheet reflects assets held for sale of $6.2 million, which includes the fair value of buildings and yards for one domestic drilling yard and two closed wireline locations, both of which were designated as held for sale in 2019, one domestic SCR drilling rig, two coiled tubing units, and spare support equipment. 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 nine months ended September 30, 2019 and 2018, we recognized impairment charges of $1.4 million and $2.6 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. 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 asset groups 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.
Due to lower than anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2019. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the carrying value.
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. 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. If commodity prices decrease or 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 our estimates of the fair value of certain assets may decrease as well. If any of the foregoing were to occur, we could incur impairment charges on the related assets.
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):
 
September 30, 2019
 
December 31, 2018
Domestic net operating loss carryforward
$
101,332

 
$
96,777

Foreign net operating loss carryforward
6,931

 
9,582

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.



13


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 September 30, 2019 and December 31, 2018, we had valuation allowances of $69.7 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 a portion of the valuation allowance relating to our foreign deferred tax assets.
6.     Debt
Our debt consists of the following (amounts in thousands):
 
September 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%)
(2,077
)
 
(2,668
)
Less unamortized debt issuance costs
(6,036
)
 
(7,780
)
 
$
466,887

 
$
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.



14


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 September 30, 2019, we had $9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $50.6 million. Borrowings available under the ABL Facility are available for general corporate purposes, and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. Additionally, if our availability under the ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month basis.
The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to:
•
declare dividends and make other distributions;
•
issue or sell certain equity interests;
•
optionally prepay, redeem or repurchase certain of our subordinated indebtedness;
•
make loans or investments (including acquisitions);
•
incur additional indebtedness or modify the terms of permitted indebtedness;
•
grant liens;
•
change our business or the business of our subsidiaries;
•
merge, consolidate, reorganize, recapitalize, or reclassify our equity interests;
•
sell our assets, and
•
enter into certain types of transactions with affiliates.
Our obligations under the ABL Facility are guaranteed by us and our domestic subsidiaries, subject to certain exceptions, and are secured by (i) a first-priority perfected security interest in all inventory and cash, and (ii) a second-priority perfected security in substantially all of our tangible and intangible assets, in each case, subject to certain exceptions and permitted liens.



15


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 Consolidating 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.
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. 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. At September 30, 2019, the estimated aggregate fair value of our phantom stock unit awards was $0.1 million.



16


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):
 
 
 
September 30, 2019
 
December 31, 2018
 
Hierarchy Level
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Senior notes
2
 
$
297,628

 
$
114,000

 
$
296,988

 
$
186,750

Senior secured term loan
3
 
169,259

 
$
166,250

 
167,564

 
175,875

 
 
 
$
466,887

 
$
280,250

 
$
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 September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Numerator (both basic and diluted):
 
 
 
 
 
 
 
Net loss
$
(26,016
)
 
$
(5,233
)
 
$
(54,075
)
 
$
(34,524
)
Denominator:
 
 
 
 
 
 
 
Weighted-average shares (denominator for basic earnings (loss) per share)
78,473

 
78,136

 
78,405

 
77,897

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

 
—

 
—

 
—

Denominator for diluted earnings (loss) per share
78,473

 
78,136

 
78,405

 
77,897

Loss per common share - Basic
$
(0.33
)
 
$
(0.07
)
 
$
(0.69
)
 
$
(0.44
)
Loss per common share - Diluted
$
(0.33
)
 
$
(0.07
)
 
$
(0.69
)
 
$
(0.44
)
Potentially dilutive securities excluded as anti-dilutive
5,577

 
3,964

 
4,962

 
4,895

9.
Stock-Based Compensation Plans
We currently have outstanding stock option and restricted stock awards with vesting based on time of service conditions; restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions; and 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. At this time, however, we have temporarily discontinued the grants of any new equity-based incentive awards.



17


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 nine months ended September 30, 2019 and 2018 (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Stock option awards
$
31

 
$
101

 
$
105

 
$
342

Restricted stock awards
135

 
116

 
370

 
344

Restricted stock unit awards
653

 
822

 
1,538

 
2,709

 
$
819

 
$
1,039

 
$
2,013

 
$
3,395

Phantom stock unit awards
$
(150
)
 
$
(3,722
)
 
$
(99
)
 
$
2,808

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 nine months ended September 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.
The following table summarizes the number and weighted-average grant-date fair value of the restricted stock and restricted stock unit awards granted during the nine months ended September 30, 2019 and 2018:
 
Nine months ended September 30,
 
2019
 
2018
Restricted Stock:
 
 
 
Restricted stock awards granted
729,112

 
78,632

Weighted-average grant-date fair value (per share)
$
0.73

 
$
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 September 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.



18


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.
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 nine months ended September 30, 2019 and 2018:
 
Nine months ended September 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 $0.06 as of September 30, 2019, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $1.2 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 September 30, 2019, we estimate the weighted-average achievement level for our outstanding phantom stock unit awards granted in 2018 and 2019 to be 67%.
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.



19


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 producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi.



20


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 September 30,
 
As of and for the nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
38,168

 
$
36,586

 
$
115,829

 
$
108,146

International drilling
21,617

 
23,131

 
68,682

 
62,515

Drilling services
59,785

 
59,717

 
184,511

 
170,661

Well servicing
30,293

 
24,369

 
86,053

 
68,645

Wireline services
43,874

 
52,654

 
137,134

 
171,392

Coiled tubing services
12,446

 
12,592

 
38,111

 
37,894

Production services
86,613

 
89,615

 
261,298

 
277,931

Consolidated revenues
$
146,398

 
$
149,332

 
$
445,809

 
$
448,592

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
21,931

 
$
21,650

 
$
69,098

 
$
64,297

International drilling
15,844

 
19,013

 
50,884

 
49,038

Drilling services
37,775

 
40,663

 
119,982

 
113,335

Well servicing
21,414

 
17,193

 
61,348

 
49,443

Wireline services
38,349

 
40,840

 
119,500

 
130,042

Coiled tubing services
10,521

 
10,265

 
31,784

 
33,104

Production services
70,284

 
68,298

 
212,632

 
212,589

Consolidated operating costs
$
108,059

 
$
108,961

 
$
332,614

 
$
325,924

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
16,237

 
$
14,936

 
$
46,731

 
$
43,849

International drilling
5,773

 
4,118

 
17,798

 
13,477

Drilling services
22,010

 
19,054

 
64,529

 
57,326

Well servicing
8,879

 
7,176

 
24,705

 
19,202

Wireline services
5,525

 
11,814

 
17,634

 
41,350

Coiled tubing services
1,925

 
2,327

 
6,327

 
4,790

Production services
16,329

 
21,317

 
48,666

 
65,342

Consolidated gross margin
$
38,339

 
$
40,371

 
$
113,195

 
$
122,668

 
 
 
 
 
 
 
 
Identifiable Assets:
 
 
 
 
 
 
 
Domestic drilling (1)
$
354,534

 
$
375,982

 
$
354,534

 
$
375,982

International drilling (1) (2)
47,320

 
41,807

 
47,320

 
41,807

Drilling services
401,854

 
417,789

 
401,854

 
417,789

Well servicing
118,686

 
123,933

 
118,686

 
123,933

Wireline services
80,054

 
96,585

 
80,054

 
96,585

Coiled tubing services
34,339

 
34,866

 
34,339

 
34,866

Production services
233,079

 
255,384

 
233,079

 
255,384

Corporate
54,760

 
79,702

 
54,760

 
79,702

Consolidated identifiable assets
$
689,693

 
$
752,875

 
$
689,693

 
$
752,875

 
 
 
 
 
 
 
 
Depreciation:
 
 
 
 
 
 
 
Domestic drilling
$
10,864

 
$
10,358

 
$
32,297

 
$
30,946

International drilling
1,512

 
1,463

 
4,228

 
4,211

Drilling services
12,376

 
11,821

 
36,525

 
35,157

Well servicing
5,132

 
4,903

 
14,956

 
14,688

Wireline services
3,537

 
4,518

 
11,519

 
13,727

Coiled tubing services
1,660

 
1,991

 
4,719

 
6,137

Production services
10,329

 
11,412

 
31,194

 
34,552

Corporate
219

 
268

 
709

 
826

Consolidated depreciation
$
22,924

 
$
23,501

 
$
68,428

 
$
70,535

 
 
 
 
 
 
 
 



21


 
As of and for the three months ended September 30,
 
As of and for the nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Capital Expenditures:
 
 
 
 
 
 
 
Domestic drilling
$
2,777

 
$
6,274

 
$
14,344

 
$
13,768

International drilling
1,162

 
264

 
3,444

 
4,177

Drilling services
3,939

 
6,538

 
17,788

 
17,945

Well servicing
2,146

 
2,989

 
8,182

 
8,441

Wireline services
775

 
3,973

 
5,198

 
12,563

Coiled tubing services
1,756

 
4,498

 
4,567

 
12,479

Production services
4,677

 
11,460

 
17,947

 
33,483

Corporate
44

 
419

 
541

 
914

Consolidated capital expenditures
$
8,660

 
$
18,417

 
$
36,276

 
$
52,342

(1)
Identifiable assets for our drilling segments include the impact of a $37.5 million and $39.4 million intercompany balance, as of September 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 September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Consolidated gross margin
$
38,339

 
$
40,371

 
$
113,195

 
$
122,668

Depreciation
(22,924
)
 
(23,501
)
 
(68,428
)
 
(70,535
)
General and administrative
(30,485
)
 
(14,043
)
 
(68,271
)
 
(58,066
)
Bad debt (expense) recovery, net
(196
)
 
(111
)
 
90

 
311

Impairment
—

 
(239
)
 
(1,378
)
 
(2,607
)
Gain (loss) on dispositions of property and equipment, net
(17
)
 
1,861

 
2,184

 
2,922

Income (loss) from operations
$
(15,283
)
 
$
4,338

 
$
(22,608
)
 
$
(5,307
)
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 $70.2 million relating to our performance under these bonds as of September 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 September 30, 2019 and December 31, 2018, our accrued liability was $1.9 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.



22


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 September 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.



23


CONDENSED CONSOLIDATING BALANCE SHEETS
(unaudited, in thousands)
 
September 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
22,195

 
$
—

 
$
4,760

 
$
—

 
$
26,955

Restricted cash
998

 
—

 
—

 
—

 
998

Receivables, net of allowance
258

 
96,704

 
34,979

 
611

 
132,552

Intercompany receivable (payable)
(28,105
)
 
65,374

 
(37,269
)
 
—

 
—

Inventory
—

 
10,103

 
11,983

 
—

 
22,086

Assets held for sale
—

 
6,233

 
—

 
—

 
6,233

Prepaid expenses and other current assets
2,497

 
2,994

 
1,500

 
—

 
6,991

Total current assets
(2,157
)
 
181,408

 
15,953

 
611

 
195,815

Net property and equipment
1,853

 
456,106

 
27,296

 
—

 
485,255

Investment in subsidiaries
545,141

 
32,086

 
—

 
(577,227
)
 
—

Deferred income taxes
44,277

 
—

 
—

 
(44,277
)
 
—

Operating lease assets
3,234

 
3,852

 
606

 
—

 
7,692

Other noncurrent assets
512

 
415

 
4

 
—

 
931

Total assets
$
592,860

 
$
673,867

 
$
43,859

 
$
(620,893
)
 
$
689,693

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,441

 
$
26,000

 
$
4,686

 
$
—

 
$
32,127

Deferred revenues
—

 
424

 
1,192

 
—

 
1,616

Accrued expenses
8,342

 
50,166

 
5,440

 
611

 
64,559

Total current liabilities
9,783

 
76,590

 
11,318

 
611

 
98,302

Long-term debt, less unamortized discount and debt issuance costs
466,887

 
—

 
—

 
—

 
466,887

Noncurrent operating lease liabilities
2,859

 
2,875

 
455

 
—

 
6,189

Deferred income taxes
—

 
48,985

 
—

 
(44,277
)
 
4,708

Other noncurrent liabilities
183

 
276

 
—

 
—

 
459

Total liabilities
479,712

 
128,726

 
11,773

 
(43,666
)
 
576,545

Total shareholders’ equity
113,148

 
545,141

 
32,086

 
(577,227
)
 
113,148

Total liabilities and shareholders’ equity
$
592,860

 
$
673,867

 
$
43,859

 
$
(620,893
)
 
$
689,693

 
 
 
 
 
 
 
 
 
 
 
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




24


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)

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

 
$
124,781

 
$
21,617

 
$
—

 
$
146,398

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
92,216

 
15,843

 
—

 
108,059

Depreciation
219

 
21,193

 
1,512

 
—

 
22,924

General and administrative
15,979

 
13,640

 
1,001

 
(135
)
 
30,485

Intercompany leasing
—

 
(1,215
)
 
1,215

 
—

 
—

Bad debt expense, net of recovery
—

 
196

 
—

 
—

 
196

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

 
28

 
(11
)
 
—

 
17

Total costs and expenses
16,198

 
126,058

 
19,560

 
(135
)
 
161,681

Income (loss) from operations
(16,198
)
 
(1,277
)
 
2,057

 
135

 
(15,283
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(640
)
 
1,164

 
—

 
(524
)
 
—

Interest expense
(10,020
)
 
3

 
4

 
—

 
(10,013
)
Other income (expense)
86

 
236

 
(775
)
 
(135
)
 
(588
)
Total other income (expense), net
(10,574
)
 
1,403

 
(771
)
 
(659
)
 
(10,601
)
Income (loss) before income taxes
(26,772
)
 
126

 
1,286

 
(524
)
 
(25,884
)
Income tax (expense) benefit 1
756

 
(766
)
 
(122
)
 
—

 
(132
)
Net income (loss)
$
(26,016
)
 
$
(640
)
 
$
1,164

 
$
(524
)
 
$
(26,016
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
126,202

 
$
23,130

 
$
—

 
$
149,332

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
89,950

 
19,011

 
—

 
108,961

Depreciation
269

 
21,769

 
1,463

 
—

 
23,501

General and administrative
2,260

 
11,152

 
736

 
(105
)
 
14,043

Intercompany leasing
—

 
(1,215
)
 
1,215

 
—

 
—

Bad debt expense, net of recovery
—

 
111

 
—

 
—

 
111

Impairment
—

 
239

 
—

 
—

 
239

Gain on dispositions of property and equipment, net
—

 
(1,856
)
 
(5
)
 
—

 
(1,861
)
Total costs and expenses
2,529

 
120,150

 
22,420

 
(105
)
 
144,994

Income (loss) from operations
(2,529
)
 
6,052

 
710

 
105

 
4,338

Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
5,011

 
618

 
—

 
(5,629
)
 
—

Interest expense
(9,802
)
 
(12
)
 
3

 
—

 
(9,811
)
Other income
244

 
222

 
137

 
(105
)
 
498

Total other income (expense), net
(4,547
)
 
828

 
140

 
(5,734
)
 
(9,313
)
Income (loss) before income taxes
(7,076
)
 
6,880

 
850

 
(5,629
)
 
(4,975
)
Income tax (expense) benefit 1
1,843

 
(1,869
)
 
(232
)
 
—

 
(258
)
Net income (loss)
$
(5,233
)
 
$
5,011

 
$
618

 
$
(5,629
)
 
$
(5,233
)
 
 
 
 
 
 
 
 
 
 
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 CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)
 
Nine months ended September 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
377,127

 
$
68,682

 
$
—

 
$
445,809

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
281,735

 
50,879

 
—

 
332,614

Depreciation
709

 
63,491

 
4,228

 
—

 
68,428

General and administrative
30,882

 
35,665

 
2,129

 
(405
)
 
68,271

Intercompany leasing
—

 
(3,645
)
 
3,645

 
—

 
—

Bad debt recovery, net of expense
—

 
(90
)
 
—

 
—

 
(90
)
Impairment
—

 
1,378

 
—

 
—

 
1,378

Gain on dispositions of property and equipment, net
—

 
(2,077
)
 
(107
)
 
—

 
(2,184
)
Total costs and expenses
31,591

 
376,457

 
60,774

 
(405
)
 
468,417

Income (loss) from operations
(31,591
)
 
670

 
7,908

 
405

 
(22,608
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
5,433

 
7,059

 
—

 
(12,492
)
 
—

Interest expense
(29,953
)
 
(12
)
 
(38
)
 
—

 
(30,003
)
Other income (expense)
383

 
903

 
(436
)
 
(405
)
 
445

Total other income (expense), net
(24,137
)
 
7,950

 
(474
)
 
(12,897
)
 
(29,558
)
Income (loss) before income taxes
(55,728
)
 
8,620

 
7,434

 
(12,492
)
 
(52,166
)
Income tax (expense) benefit 1
1,653

 
(3,187
)
 
(375
)
 
—

 
(1,909
)
Net income (loss)
$
(54,075
)
 
$
5,433

 
$
7,059

 
$
(12,492
)
 
$
(54,075
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
386,077

 
$
62,515

 
$
—

 
$
448,592

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
276,893

 
49,031

 
—

 
325,924

Depreciation
826

 
65,498

 
4,211

 
—

 
70,535

General and administrative
18,628

 
37,781

 
1,972

 
(315
)
 
58,066

Intercompany leasing
—

 
(3,645
)
 
3,645

 
—

 
—

Bad debt recovery, net of expense
—

 
(311
)
 
—

 
—

 
(311
)
Impairment
—

 
2,607

 
—

 
—

 
2,607

Gain on dispositions of property and equipment, net
—

 
(2,890
)
 
(32
)
 
—

 
(2,922
)
Total costs and expenses
19,454

 
375,933

 
58,827

 
(315
)
 
453,899

Income (loss) from operations
(19,454
)
 
10,144

 
3,688

 
315

 
(5,307
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
10,081

 
3,305

 
—

 
(13,386
)
 
—

Interest expense
(28,963
)
 
(14
)
 
11

 
—

 
(28,966
)
Other income
405

 
664

 
292

 
(315
)
 
1,046

Total other income (expense), net
(18,477
)
 
3,955

 
303

 
(13,701
)
 
(27,920
)
Income (loss) before income taxes
(37,931
)
 
14,099

 
3,991

 
(13,386
)
 
(33,227
)
Income tax (expense) benefit 1
3,407

 
(4,018
)
 
(686
)
 
—

 
(1,297
)
Net income (loss)
$
(34,524
)
 
$
10,081

 
$
3,305

 
$
(13,386
)
 
$
(34,524
)
 
 
 
 
 
 
 
 
 
 
1  The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.



26


CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 
Nine months ended September 30, 2019
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(38,177
)
 
$
41,854

 
$
4,961

 
$
—

 
$
8,638

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(637
)
 
(36,644
)
 
(3,262
)
 
—

 
(40,543
)
Proceeds from sale of property and equipment
—

 
4,688

 
90

 
—

 
4,778

Proceeds from insurance recoveries
—

 
641

 
—

 
—

 
641

 
(637
)
 
(31,315
)
 
(3,172
)
 
—

 
(35,124
)
 
 
 
 
 
 
 
 
 
 
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
(28,155
)
 
—

 
1,544

 
—

 
(26,611
)
Beginning cash, cash equivalents and restricted cash
51,348

 
—

 
3,216

 
—

 
54,564

Ending cash, cash equivalents and restricted cash
$
23,193

 
$
—

 
$
4,760

 
$
—

 
$
27,953

 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2018
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(43,466
)
 
$
60,269

 
$
4,687

 
$
—

 
$
21,490

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(762
)
 
(43,374
)
 
(4,642
)
 
—

 
(48,778
)
Proceeds from sale of property and equipment
—

 
4,648

 
17

 
—

 
4,665

Proceeds from insurance recoveries
—

 
965

 
15

 
—

 
980

 
(762
)
 
(37,761
)
 
(4,610
)
 
—

 
(43,133
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from exercise of options
12

 
—

 
—

 
—

 
12

Purchase of treasury stock
(549
)
 
—

 
—

 
—

 
(549
)
Intercompany contributions/distributions
22,784

 
(22,508
)
 
(276
)
 
—

 
—

 
22,247

 
(22,508
)
 
(276
)
 
—

 
(537
)
 
 
 
 
 
 
 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
(21,981
)
 
—

 
(199
)
 
—

 
(22,180
)
Beginning cash, cash equivalents and restricted cash
72,385

 
—

 
3,263

 
—

 
75,648

Ending cash, cash equivalents and restricted cash
$
50,404

 
$
—

 
$
3,064

 
$
—

 
$
53,468

 
 






27


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, 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.



28


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 8 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
 
5

Permian Basin and Eagle Ford
 
10

Bakken
 
2

International drilling
 
8

 
 
25

•
Production Services— Our production services business segments provide well, wireline and coiled tubing services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi.
•
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 September 30, 2019, we have a fleet of 112 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 9 locations concentrated in Texas, as well as in North Dakota, Colorado and Mississippi.
•
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 September 30, 2019, we have a fleet of 93 wireline units, including 2 greaseless, EcoQuietTM units designed to reduce noise when operating in proximity to urban areas and an additional 6 units that offer greaseless electric wireline used to reach further depths in longer laterals. Our fleet is deployed through 10 operating locations concentrated in Texas and the Rocky Mountain and Mid-Continent regions, as well as in Louisiana and North Dakota.
•
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 September 30, 2019, we have a current fleet of 9 coiled tubing units, consisting of 4 small-diameter and 5 large-diameter units (larger than two inches), deployed through 2 operating locations that provide services in Texas, Wyoming and surrounding areas.



29


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. The trend in our industry toward fewer, but longer lateral wellbores has led to an overall reduction in drilling and completion activity and demand for the equipment in our industry that is more heavily weighted toward the more specialized equipment available, 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



30


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-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. Despite some improvement in 2019, oil prices have averaged just over $55 per barrel through September 2019.
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.
SPOTPRICESANDRIGCOUNTS3YEARS.JPG
The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:
SPOTPRICESANDRIGCOUNTS1YEAR.JPG



31


Currently, 21 of our 25 drilling rigs are earning revenues, 18 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
3

 
12

 
6

 
3

 
2

 
—

 
1

International rigs
—

 
6

 
4

 
2

 
—

 
—

 
—

 
3

 
18

 
10

 
5

 
2

 
—

 
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 and 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.
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 second quarter of 2019, overall demand for our well servicing business was consistent with some slight pricing improvement, our wireline business experienced slight pricing improvements despite a 9% decline in the total number of jobs performed, and our coiled tubing business experienced both improved utilization and pricing during the 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 September 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.
The continuing trend toward longer lateral wellbores and the enhanced efficiency of the equipment in our industry, in combination with current commodity prices and more disciplined spending by exploration and production companies, has contributed to some oversupply of equipment in our industry, declining rig counts and reduced completion activity. Although we expect a competitive market environment and some additional clients to decrease their activity during the remainder of 2019 due to budget constraints, we remain focused on improving margins through realignment of certain businesses and reducing costs, and we believe our high-quality equipment, services and excellent safety record position us well to compete.



32


Liquidity and Capital Resources
Sources of Capital Resources
Our principal sources of liquidity currently consist of:
•
total cash and cash equivalents ($28.0 million as of September 30, 2019);
•
cash generated from operations ($8.6 million during the nine months ended September 30, 2019);
•
proceeds from sales of assets; ($4.8 million during the nine months ended September 30, 2019); and
•
the availability under our asset-based lending facility ($50.6 million as of September 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 September 30, 2019, we had $9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $50.6 million. Borrowings available under the ABL Facility are available for general corporate purposes, and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. 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 September 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. Our ability to access the capital markets by issuing debt or equity securities will be dependent on market conditions, our financial condition, and other factors beyond our control.
We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of assets, and available funds 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 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 is not expected to mature until December 2021, we continue to proactively explore various strategic and other alternatives to address the uncertainties related to our ability to refinance our outstanding debts as their maturities approach.



33


Working Capital — Our working capital was $97.5 million at September 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 September 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:
 
September 30,
2019
 
December 31,
2018
 
Change
Cash and cash equivalents
$
26,955

 
$
53,566

 
$
(26,611
)
Restricted cash
998

 
998

 
—

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
81,039

 
76,924

 
4,115

Unbilled receivables
20,906

 
24,822

 
(3,916
)
Insurance recoveries
23,186

 
23,656

 
(470
)
Other receivables
7,421

 
5,479

 
1,942

Inventory
22,086

 
18,898

 
3,188

Assets held for sale
6,233

 
3,582

 
2,651

Prepaid expenses and other current assets
6,991

 
7,109

 
(118
)
Current assets
195,815

 
215,034

 
(19,219
)
Accounts payable
32,127

 
34,134

 
(2,007
)
Deferred revenues
1,616

 
1,722

 
(106
)
Accrued expenses:
 
 
 
 
 
Employee compensation and related costs
22,489

 
24,598

 
(2,109
)
Insurance claims and settlements
22,991

 
23,593

 
(602
)
Insurance premiums and deductibles
6,036

 
5,482

 
554

Interest
1,008

 
6,148

 
(5,140
)
Other
12,035

 
9,091

 
2,944

Current liabilities
98,302

 
104,768

 
(6,466
)
Working capital
$
97,513

 
$
110,266

 
$
(12,753
)
•
Cash and cash equivalents — The decrease in cash and cash equivalents during 2019 is primarily due to $40.5 million of cash used for the purchase of property and equipment, offset in part by $8.6 million of cash provided by operating activities and $4.8 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 3% increase in our revenues during the quarter ended September 30, 2019, as compared to the quarter ended December 31, 2018. Our domestic trade receivables generally turn over within 60 days, and our Colombian trade receivables generally turn over within 120 days.
•
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 primarily due to an increase in inventory for our international operations’ spare parts and supplies supporting rigs working in remote locations.
•
Assets held for sale — As of September 30, 2019, our condensed consolidated balance sheet reflects assets held for sale of $6.2 million, which includes the fair value of buildings and yards for one domestic drilling yard and two closed wireline locations, both of which were designated as held for sale in 2019, one domestic SCR drilling rig, two coiled tubing units, and spare support equipment. 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 of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
•
Prepaid expenses and other current assets — The decrease in prepaid expenses and other current assets during 2019 is primarily due to the amortization of prepaid insurance premiums which are generally paid annually in October, which



34


was largely offset by an increase in deferred mobilization costs for one domestic drilling rig that moved between geographic regions.
•
Accounts payable — Our accounts payable generally turn over within 90 days. The decrease in accounts payable during 2019 is primarily due to a $4.3 million decrease in our accruals for capital expenditures, which was partially offset by an increase in accounts payable primarily attributable to the 4% increase in our operating costs for the quarter ended September 30, 2019 as compared to the quarter ended December 31, 2018.
•
Deferred revenues — The decrease in deferred revenues during 2019 is primarily due to deferred revenue amortization, offset by increases associated with the deployment of rigs under five new domestic and four new international contracts in 2019.
•
Employee compensation and related costs — The decrease in employee compensation and related costs during 2019 resulted from a decrease in accrued incentive cash compensation associated with the payment of 2018 annual bonuses in the first quarter of $6.6 million, the $3.5 million settlement of our phantom stock unit awards that vested in April 2019, and the termination of both our annual and long-term cash incentive awards in September 2019. The overall decrease was net of $9.8 million of incentive compensation that was granted in September 2019 and paid in October 2019.
•
Accrued interest — The decrease in accrued interest expense during 2019 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15th and September 15th each year.
•
Other accrued expenses — The increase in other accrued expenses during 2019 is primarily due to the recognition of $2.2 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 in other accrued expenses during 2019 is also related to an increase in accrued taxes associated with the increase in revenues for our international operations.
Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at September 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
93,713

 
35,525

 
58,188

 
—

 
—

Purchase commitments
4,238

 
4,238

 
—

 
—

 
—

Operating leases
9,278

 
2,499

 
3,594

 
2,144

 
1,041

Incentive compensation
10,820

 
10,163

 
657

 
—

 
—

 
$
593,049

 
$
52,425

 
$
537,439

 
$
2,144

 
$
1,041

•
Debt — Debt obligations at September 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 September 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 9.8% interest rate that was in effect at September 30, 2019, and (2) the principal balance of $175 million at September 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 September 30, 2019, our purchase commitments primarily pertain to $1.8 million of inventory and job supplies for our coiled tubing operations as well as various refurbishments and upgrades to our drilling and production services fleets.



35


•
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. At September 30, 2019, our incentive compensation payable primarily relates to $9.8 million of incentive compensation for awards which were granted in September, in conjunction with the termination of the 2019 annual bonus incentive awards and the cancellation of all prior long-term cash incentive awards, and which was subsequently paid in October 2019.
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 September 30, 2019, we were in compliance with all covenants required by our Term Loan, ABL Facility and Senior Notes.
Capital Expenditures — During the nine months ended September 30, 2019, we spent $40.5 million on purchases of property and equipment and placed into service property and equipment of $36.3 million. Currently, we expect to spend approximately $46 million to $49 million on capital expenditures during 2019, which includes approximately $8 million for final payments on the construction of the new-build drilling rig and previous commitments on high-pressure pump packages for coiled tubing completion operations, all of which were made earlier in the year.
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



36


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.
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 nine months ended September 30, 2019 and 2018 (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
38,168

 
$
36,586

 
$
115,829

 
$
108,146

International drilling
21,617

 
23,131

 
68,682

 
62,515

Drilling services
59,785

 
59,717

 
184,511

 
170,661

Well servicing
30,293

 
24,369

 
86,053

 
68,645

Wireline services
43,874

 
52,654

 
137,134

 
171,392

Coiled tubing services
12,446

 
12,592

 
38,111

 
37,894

Production services
86,613

 
89,615

 
261,298

 
277,931

Consolidated revenues
$
146,398

 
$
149,332

 
$
445,809

 
$
448,592

 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
21,931

 
$
21,650

 
$
69,098

 
$
64,297

International drilling
15,844

 
19,013

 
50,884

 
49,038

Drilling services
37,775

 
40,663

 
119,982

 
113,335

Well servicing
21,414

 
17,193

 
61,348

 
49,443

Wireline services
38,349

 
40,840

 
119,500

 
130,042

Coiled tubing services
10,521

 
10,265

 
31,784

 
33,104

Production services
70,284

 
68,298

 
212,632

 
212,589

Consolidated operating costs
$
108,059

 
$
108,961

 
$
332,614

 
$
325,924

 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
16,237

 
$
14,936

 
$
46,731

 
$
43,849

International drilling
5,773

 
4,118

 
17,798

 
13,477

Drilling services
22,010

 
19,054

 
64,529

 
57,326

Well servicing
8,879

 
7,176

 
24,705

 
19,202

Wireline services
5,525

 
11,814

 
17,634

 
41,350

Coiled tubing services
1,925

 
2,327

 
6,327

 
4,790

Production services
16,329

 
21,317

 
48,666

 
65,342

Consolidated gross margin
$
38,339

 
$
40,371

 
$
113,195

 
$
122,668

 
 
 
 
 
 
 
 
Consolidated:
 
 
 
 
 
 
 
Net loss
$
(26,016
)
 
$
(5,233
)
 
$
(54,075
)
 
$
(34,524
)
Adjusted EBITDA (1)
$
7,053

 
$
28,576

 
$
47,643

 
$
68,881

(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,



37


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.
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 September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
 
(amounts in thousands)
Net loss
$
(26,016
)
 
$
(5,233
)
 
$
(54,075
)
 
$
(34,524
)
Depreciation
22,924

 
23,501

 
68,428

 
70,535

Impairment
—

 
239

 
1,378

 
2,607

Interest expense
10,013

 
9,811

 
30,003

 
28,966

Income tax expense
132

 
258

 
1,909

 
1,297

Adjusted EBITDA
7,053

 
28,576

 
47,643

 
68,881

General and administrative
30,485

 
14,043

 
68,271

 
58,066

Bad debt expense (recovery), net
196

 
111

 
(90
)
 
(311
)
Loss (gain) on dispositions of property and equipment, net
17

 
(1,861
)
 
(2,184
)
 
(2,922
)
Other expense (income)
588

 
(498
)
 
(445
)
 
(1,046
)
Consolidated gross margin
$
38,339

 
$
40,371

 
$
113,195

 
$
122,668

Consolidated gross margin — Our consolidated gross margin decreased by $2.0 million, or 5%, and $9.5 million, or 8%, for the three and nine months ended September 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 in 2019. The $2.0 million and $9.5 million overall decreases in consolidated gross margin were net of $4.7 million and $12.7 million combined increases in gross margin for our drilling services and well servicing segments.



38


•
Drilling Services — Our drilling services revenues increased slightly for the three months ended September 30, 2019 and by $13.9 million, or 8%, for the nine months ended September 30, 2019, as compared to the corresponding periods in 2018, while operating costs decreased by $2.9 million, or 7%, and increased by $6.6 million, or 6%, respectively. The increases in margin for the three and nine months ended September 30, 2019 are primarily due to the deployment of our newest AC drilling rig in March 2019, the benefit of early termination revenues during 2019 on two domestic drilling contracts and increased revenues associated with the demobilization of rigs in Colombia. The following table provides operating statistics for each of our drilling services segments:
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Domestic drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
17

 
16

 
17

 
16

Utilization rate
88
%
 
99
%
 
94
%
 
100
%
Revenue days
1,383

 
1,459

 
4,279

 
4,353

 
 
 
 
 
 
 
 
Average revenues per day
$
27,598

 
$
25,076

 
$
27,069

 
$
24,844

Average operating costs per day
15,858

 
14,839

 
16,148

 
14,771

Average margin per day
$
11,740

 
$
10,237

 
$
10,921

 
$
10,073

 
 
 
 
 
 
 
 
International drilling:
 
 
 
 
 
 
 
Average number of drilling rigs
8

 
8

 
8

 
8

Utilization rate
71
%
 
76
%
 
79
%
 
79
%
Revenue days
521

 
562

 
1,724

 
1,733

 
 
 
 
 
 
 
 
Average revenues per day
$
41,491

 
$
41,158

 
$
39,839

 
$
36,073

Average operating costs per day
30,411

 
33,831

 
29,515

 
28,297

Average margin per day
$
11,080

 
$
7,327

 
$
10,324

 
$
7,776

Our domestic drilling average revenues and margin per day for the three and nine months ended September 30, 2019 increased as compared to the corresponding periods in 2018, primarily due to $2.2 million and $2.6 million of revenues, respectively, for the early termination of two of our drilling contracts and the deployment of our newest AC drilling rig in March 2019, as well as increasing dayrates during 2019, despite the impact of four rigs that re-priced downward in the second half of 2018 from historically high pre-downturn rates. These increases were partially offset by the impact of reduced utilization in 2019, as compared to 2018.
Our international average revenues and margin per day increased for the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, primarily due to $1.4 million of revenues associated with the demobilization of three rigs in Colombia during the third quarter of 2019, as well as increasing dayrates during late 2018 and early 2019. Average margin per day during these periods also benefited from reduced costs associated with mobilization and demobilization activity during 2019 as compared to 2018.



39


•
Production Services — Our revenues from production services decreased by $3.0 million, or 3%, and $16.6 million, or 6%, for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018, while operating costs increased $2.0 million, or 3%, for the three months ended September 30, 2019, and operating costs for the nine months ended September 30, 2019 were comparable with the corresponding period in 2018. The decrease in revenue is a result of the decreased demand for wireline completion services, partially offset by increased demand for our well servicing business which experienced a 25% increase in revenue and a 29% increase in gross margin during 2019. The following table provides operating statistics for each of our production services segments:
 
Three months ended September 30,
 
Nine months ended September 30,
 
2019
 
2018
 
2019
 
2018
Well servicing:
 
 
 
 
 
 
 
Average number of rigs
125

 
125

 
125

 
125

Utilization rate
59
%
 
51
%
 
58
%
 
49
%
Rig hours
52,210

 
44,155

 
151,169

 
127,800

Average revenue per hour
$
580

 
$
552

 
$
569

 
$
537

 
 
 
 
 
 
 
 
Wireline services:
 
 
 
 
 
 
 
Average number of units
94

 
104

 
98

 
107

Number of jobs
2,077

 
2,684

 
6,697

 
8,536

Average revenue per job
$
21,124

 
$
19,618

 
$
20,477

 
$
20,079

 
 
 
 
 
 
 
 
Coiled tubing services:
 
 
 
 
 
 
 
Average number of units
9

 
11

 
9

 
13

Revenue days
339

 
362

 
997

 
1,126

Average revenue per day
$
36,714

 
$
34,785

 
$
38,226

 
$
33,654

Our well servicing business experienced increases in demand during the three and nine months ended September 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 18% in each period, while revenues per hour increased by 5% and 6% for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018.
Our wireline services business segment experienced decreases of 23% and 22% in the number of jobs completed during the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, respectively, while average revenues per job increased 8% and 2%, respectively. These decreases in activity were primarily a result of decreased demand for completion-related activity during the three and nine months ended September 30, 2019, as compared to the corresponding periods in 2018, when 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 6% and 11% in revenue days for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018, while average revenue per day increased 6% and 14%. 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.
Depreciation expense — Our depreciation expense decreased by $0.6 million and $2.1 million for the three and nine months ended September 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 nine months ended September 30, 2019 and 2018, we recognized impairment charges of $1.4 million and $2.6 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



40


Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Interest expense — Our interest expense increased by $1.0 million during the nine months ended September 30, 2019, as compared to the corresponding period in 2018, primarily due to an increase in the LIBOR interest rate applicable to our Term Loan. For more detail see, Note 6, Debt, 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 — 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 increased by $16.4 million and $10.2 million for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding periods in 2018, primarily due to a net increase in incentive compensation of $9.7 million and $9.1 million, respectively, associated with retention and incentive compensation awards granted in the third quarter of 2019, concurrent with the termination of the previous annual and long-term cash incentive awards. The change in the fair value of our phantom stock unit awards also impacted our general and administrative expense, which resulted in an increase of $3.6 million during the three months ended September 30, 2019 and a decrease of $2.9 million during the nine months ended September 30, 2019, as compared to the corresponding periods in 2018, respectively. Various other expenses contributed to the overall increase in expenses during these periods, including an increase in professional fees of $1.5 million and $2.5 million for the three and nine months ended September 30, 2019, respectively, as compared to the corresponding period in 2018, as well as an increase in rent expense associated with the termination of several leases for locations closed during the third quarter.
Loss (gain) on dispositions of property and equipment, net — During the nine months ended September 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 nine months ended September 30, 2018, we recognized a net gain of $2.9 million on the disposition of various property and equipment, including the sale of five coiled tubing units, twelve wireline units, and one drilling rig, which was previously held for sale.
Other expense (income) — The decrease in our other expense (income) is primarily related to net foreign currency losses recognized for our Colombian operations during the three and nine months ended September 30, 2019, as compared to net foreign currency gains during the corresponding periods in 2018.
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 September 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



41


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 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. Due to lower than anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2019. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the carrying value. 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. 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. If commodity prices decrease or 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 our estimates of the fair value of certain assets may decrease as well. 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 September 30, 2019, we had $101.3 million and $6.9 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 September 30, 2019, we had a valuation allowance of $69.7 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 a portion 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



42


$250,000 under our general liability insurance. At September 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 $3.6 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 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.
Recent Developments
On October 19, 2019, the Colombian Constitutional Court declared Colombia’s 2018 Tax Reform unconstitutional due to procedural flaws in the approval process, however, the decision is not effective until January 1, 2020. The Colombian government is currently working to reenact the tax reform through the correct procedure, to take effect on January 1, 2020. If a new tax reform package is not agreed to by that time, the tax regime prior to 2018 will be in effect as of January 1, 2020, in which case we would account for any potential changes in the fourth quarter of 2019.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.



43

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 September 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 $1.3 million during the nine months ended September 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 losses of $0.5 million for the nine months ended September 30, 2019.




44


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





45

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
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.

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 September 30, 2019. We did not repurchase any common shares during the quarter ended September 30, 2019.

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
Not applicable.

ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.

ITEM 5.
OTHER INFORMATION
Not applicable.




46


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+*
-
 
 
 
10.2+*
-
 
 
 
10.3+*
-
 
 
 
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.




47


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: October 31, 2019




48
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