10-Q 1 form10q-3q2015.htm 10-Q 10-Q

 
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, 2015
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 NE Loop 410, Suite 1000
San Antonio, Texas
 
78209
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code: (855) 884-0575
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
x
Accelerated filer
o
 
 
 
 
Non-accelerated filer
o
Smaller reporting company
o
   (Do not check if a small reporting company.)
 
 
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, 2015, there were 64,497,915 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 



PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
September 30,
2015
 
December 31,
2014
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
35,679

 
$
34,924

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
51,963

 
136,161

Unbilled receivables
7,653

 
38,002

Insurance recoveries
14,947

 
10,900

Other receivables
7,410

 
5,138

Deferred income taxes
6,299

 
10,998

Inventory
8,995

 
14,117

Assets held for sale
2,065

 
9,909

Prepaid expenses and other current assets
5,927

 
8,925

Total current assets
140,938

 
269,074

Property and equipment, at cost
1,509,931

 
1,702,273

Less accumulated depreciation
731,235

 
845,732

Net property and equipment
778,696

 
856,541

Intangible assets, net of accumulated amortization of $46.1 million and $40.3 million at September 30, 2015 and December 31, 2014, respectively
18,268

 
24,223

Noncurrent deferred income taxes

 
2,753

Other long-term assets
11,226

 
18,998

Total assets
$
949,128

 
$
1,171,589

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
35,072

 
$
64,305

Current portion of long-term debt

 
27

Deferred revenues
14,772

 
3,315

Accrued expenses:
 
 
 
Payroll and related employee costs
16,934

 
40,058

Insurance premiums and deductibles
8,302

 
12,829

Insurance claims and settlements
14,947

 
10,900

Interest
861

 
5,432

Other
6,419

 
10,326

Total current liabilities
97,307

 
147,192

Long-term debt, less current portion
410,000

 
455,053

Noncurrent deferred income taxes
48,745

 
69,578

Other long-term liabilities
4,193

 
4,702

Total liabilities
560,245

 
676,525

Commitments and contingencies (Note 9)

 

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

 

Common stock $.10 par value; 100,000,000 shares authorized; 64,497,915 and 63,820,126 shares outstanding at September 30, 2015 and December 31, 2014, respectively
6,496

 
6,414

Additional paid-in capital
473,763

 
472,457

Treasury stock, at cost; 458,170 and 317,103 shares at September 30, 2015 and December 31, 2014, respectively
(3,759
)
 
(3,030
)
Accumulated earnings (deficit)
(87,617
)
 
19,223

Total shareholders’ equity
388,883

 
495,064

Total liabilities and shareholders’ equity
$
949,128

 
$
1,171,589

See accompanying notes to condensed consolidated financial statements.

2




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
 
Three months ended September 30,
 
Nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share data)
Revenues:
 
 
 
 
 
 
 
Drilling services
$
41,238

 
$
128,117

 
$
198,212

 
$
373,627

Production services
66,242

 
145,150

 
238,093

 
398,486

Total revenues
107,480

 
273,267

 
436,305

 
772,113

 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
Drilling services
22,875

 
88,963

 
118,114

 
250,904

Production services
48,643

 
89,993

 
170,517

 
250,140

Depreciation and amortization
35,257

 
46,081

 
115,528

 
137,398

General and administrative
16,814

 
26,613

 
56,909

 
76,372

Bad debt expense (recovery)
(1,071
)
 
19

 
(358
)
 
456

Impairment charges
2,329

 
678

 
79,648

 
678

Loss (gain) on dispositions of property and equipment
605

 
142

 
(2,639
)
 
(1,589
)
Gain on sale of fishing and rental services operations

 
(10,702
)
 

 
(10,702
)
Gain on litigation

 
(1,324
)
 

 
(4,200
)
Total costs and expenses
125,452

 
240,463

 
537,719

 
699,457

Income (loss) from operations
(17,972
)
 
32,804

 
(101,414
)
 
72,656

 
 
 
 
 
 
 
 
Other (expense) income:
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(5,465
)
 
(8,969
)
 
(16,165
)
 
(32,085
)
Loss on extinguishment of debt

 

 

 
(22,482
)
Other
(785
)
 
(1,455
)
 
(2,979
)
 
360

Total other expense
(6,250
)
 
(10,424
)
 
(19,144
)
 
(54,207
)
 
 
 
 
 
 
 
 
Income (loss) before income taxes
(24,222
)
 
22,380

 
(120,558
)
 
18,449

Income tax (expense) benefit
6,682

 
(9,927
)
 
13,718

 
(8,894
)
Net income (loss)
$
(17,540
)
 
$
12,453

 
$
(106,840
)
 
$
9,555

 
 
 
 
 
 
 
 
Income (loss) per common share—Basic
$
(0.27
)
 
$
0.20

 
$
(1.66
)
 
$
0.15

 
 
 
 
 
 
 
 
Income (loss) per common share—Diluted
$
(0.27
)
 
$
0.19

 
$
(1.66
)
 
$
0.15

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
64,449

 
63,451

 
64,262

 
62,960

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
64,449

 
65,876

 
64,262

 
65,167







See accompanying notes to condensed consolidated financial statements.

3




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Nine months ended September 30,
 
2015
 
2014
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(106,840
)
 
$
9,555

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation and amortization
115,528

 
137,398

Allowance for doubtful accounts
(358
)
 
408

Gain on dispositions of property and equipment
(2,639
)
 
(1,589
)
Stock-based compensation expense
2,275

 
5,761

Amortization of debt issuance costs, discount and premium
1,737

 
2,193

Gain on sale of fishing and rental services operations

 
(10,702
)
Loss on extinguishment of debt

 
22,482

Impairment charges
79,648

 
678

Deferred income taxes
(15,048
)
 
5,395

Change in other long-term assets
438

 
8,247

Change in other long-term liabilities
(509
)
 
(1,385
)
Changes in current assets and liabilities:
 
 
 
Receivables
113,686

 
(29,428
)
Inventory
1,533

 
(1,094
)
Prepaid expenses and other current assets
3,233

 
3,030

Accounts payable
(29,547
)
 
11,802

Deferred revenues
11,457

 
2,545

Accrued expenses
(35,529
)
 
(10,366
)
Net cash provided by operating activities
139,065

 
154,930

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(130,390
)
 
(120,738
)
Proceeds from sale of fishing and rental services operations

 
15,090

Proceeds from sale of property and equipment
37,803

 
7,197

Proceeds from insurance recoveries
227

 

Net cash used in investing activities
(92,360
)
 
(98,451
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
(45,003
)
 
(360,019
)
Proceeds from issuance of debt

 
320,000

Debt issuance costs
(999
)
 
(9,173
)
Tender premium costs

 
(15,381
)
Proceeds from exercise of options
781

 
8,280

Purchase of treasury stock
(729
)
 
(1,132
)
Net cash used in financing activities
(45,950
)
 
(57,425
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
755

 
(946
)
Beginning cash and cash equivalents
34,924

 
27,385

Ending cash and cash equivalents
$
35,679

 
$
26,439

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
21,543

 
$
41,188

Income tax paid
$
2,659

 
$
3,475

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
308

 
$
9,840

 
See accompanying notes to condensed consolidated financial statements.

4




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Business
Pioneer Energy Services Corp. provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico.
Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies through our four drilling divisions in the US, and internationally in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our fleet are currently assigned to the following divisions:
Drilling Division
Rig Count
South Texas
10

West Texas
8

North Dakota
8

Appalachia
4

Colombia
8

 
38

Beginning in October 2014, domestic and international oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. In drilling, all rig classes were severely impacted by the industry downturn. However, AC drilling rigs equipped with either a walking or skidding system are the best suited for horizontal pad drilling and we believe they are the most desirable rig design available.
We have deployed four new-build 1,500 horsepower AC drilling rigs under multi-year term contracts during 2015 and expect to complete construction of one more new-build drilling rig by the end of the year. We also sold 28 of our mechanical and lower horsepower electric drilling rigs during 2015 which were the most negatively impacted by the industry downturn.
We expect to end 2015 with a drilling fleet of 39 rigs, of which 95% will be capable of drilling horizontally, with all but one of our AC rigs built within the last five years. The removal of older, less capable rigs from our fleet and the recent and ongoing investments in the construction of new-builds is transforming our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market.
Currently, 21 of our 38 drilling rigs are earning revenues under drilling contracts, 16 of which are earning under domestic term contracts, and three of which are under term contracts in Colombia. We are actively marketing our five remaining idle drilling rigs in Colombia to various operators to diversify our client base, and evaluating other options including the possibility of the sale of some or all of our assets in Colombia.

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Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of September 30, 2015, we have a fleet of 124 well servicing rigs, consisting of 113 rigs with 550 horsepower and 11 rigs with 600 horsepower, 125 wireline units and 17 coiled tubing units. Our well servicing and coiled tubing utilization rates for the quarter ended September 30, 2015 were 62% and 25%, respectively, based on total fleet count, and we are currently actively marketing approximately 50% of our wireline fleet.
Drilling Contracts
We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork or turnkey basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. We enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand. Currently, we have contracts with original terms of six months to four years in duration.
With most term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally, these revenues are billed and collected over the remaining term of the contract, as the rig is placed on standby rather than fully released from the contract, and thus may go back to work at the client's decision any time before the end of the contract. Some of our drilling contracts contain "make-whole" provisions whereby if we are able to secure additional work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.
In response to the significant decline in oil prices over the last year, term contracts for 16 of our drilling rigs have been early terminated, including five of our 19 drilling rigs that are currently earning revenues under term contracts, resulting in approximately $53.0 million of early termination revenues. Revenues derived from these early terminations are deferred and recognized over the remainder of the original term of the drilling contracts. We recognized $11.7 million and $39.0 million of revenue for early termination payments during the three and nine months ended September 30, 2015, respectively, and $0.3 million in the fourth quarter of 2014.
In September 2015, we entered into long-term contracts for three of our drilling rigs in Colombia which are cancelable without penalty provided that our client gives 30 days notice. Including these three contracts in Colombia and the new-build drilling rig that we deployed in early October 2015, 19 of our drilling rigs are currently earning revenues under term contracts, which if not renewed prior to the end of their terms, will expire as follows:
 
 
 
 
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
United States
 
16

 
6

 
5

 

 

 
5

Colombia
 
3

 

 
1

 

 

 
2

 
 
19

 
6

 
6

 

 

 
7

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

6




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 ("GAAP") 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 fiscal year ended December 31, 2014.
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 recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, and our estimate of compensation related accruals.
In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after September 30, 2015, through the filing of this Form 10-Q, for inclusion as necessary.
Unbilled Accounts Receivable
The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. We typically invoice our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey drilling contracts are invoiced upon completion of the contract.
Our unbilled receivables totaled $7.7 million at September 30, 2015, of which $6.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at September 30, 2015 and $0.9 million related to unbilled receivables for our Production Services Segment. At December 31, 2014, our unbilled receivables totaled $38.0 million, of which $32.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2014, $0.8 million related to turnkey drilling contract revenues, and $4.4 million related to unbilled receivables for our Production Services Segment. As of September 30, 2015, we did not have any turnkey contracts in progress.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets include items such as insurance, rent deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses and other current assets also include the current portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.
Intangible Assets
Our intangible assets were recorded in connection with the acquisitions of production services businesses and are subject to amortization. We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). If the sum of the estimated future undiscounted net cash flows is less

7




than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Other Long-Term Assets
Other long-term assets consist of debt issuance costs net of amortization, cash deposits related to the deductibles on our workers’ compensation insurance policies and the long-term portion of deferred mobilization costs.
Other Current Liabilities
Our other accrued expenses include accruals for items such as property tax, sales tax, Colombian net wealth tax, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of liabilities associated with our long-term compensation plans, the long-term portion of deferred revenues and other deferred liabilities.
Related-Party Transactions
During the nine months ended September 30, 2015 and 2014, the Company paid approximately $0.1 million and $0.3 million, respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service, a trucking and construction company. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Services, which is owned and operated by Mr. Freeman's two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.
Recently Issued Accounting Standards
Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning with our first quarterly filing in 2018. We are currently evaluating the potential impact of this guidance, but at this time, do not expect that the adoption of this new standard will have a material effect on our financial position or results of operations.
Debt Issuance Costs. On April 7, 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. This ASU requires retrospective adoption and will be effective for us beginning with our first quarterly filing in 2016. Early adoption is permitted. We do not expect this adoption to have a material impact on our financial position or results of operations.
Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.

8




2.    Property and Equipment
During the nine months ended September 30, 2015 and 2014, we had capital expenditures of $130.7 million and $130.6 million, respectively, which includes $2.5 million and $0.3 million, respectively, of capitalized interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment. Capital expenditures during 2015 primarily relate to our five new-build drilling rigs which began construction during 2014, as well as unit additions to our production services fleets. As of September 30, 2015 and December 31, 2014, capital expenditures incurred for property and equipment not yet placed in service was $67.3 million and $82.7 million, respectively.
During the nine months ended September 30, 2015, we recorded total gains on disposition of our property and equipment of $2.6 million, primarily for the sales of 28 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment which we sold for aggregate net proceeds of $36.3 million, of which $1.1 million was recognized as a receivable at September 30, 2015. During the nine months ended September 30, 2014, we recorded total gains on disposition of our property and equipment of $1.6 million, of which $1.1 million was related to the sale of our trucking assets in February 2014. Additionally, in September 2014, we sold our fishing and rental services operations for total consideration of $16.1 million, resulting in a pretax gain of $10.7 million.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Beginning in October 2014, domestic and international oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. In drilling, all rig classes were severely impacted by the industry downturn. However, AC drilling rigs equipped with either a walking or skidding system are the best suited for horizontal pad drilling and we believe they are the most desirable rig design available. As the downturn worsened through 2015 resulting in significantly reduced revenue and utilization rates, and projections that reflect a more delayed recovery than previously anticipated, we performed impairment testing on all the non-AC electric drilling rigs in our fleet, including the eight drilling rigs in Colombia, and our coiled tubing operations as of June 30, 2015.
Our analysis at June 30, 2015 indicated that the carrying value of our coiled tubing reporting unit and the carrying value of our six pad-capable non-AC drilling rigs in our fleet (those that are equipped with either a walking or skidding system) were recoverable and thus there was no impairment present at June 30, 2015. However, our analysis indicated that the carrying values of the six non-AC drilling rigs in our domestic fleet which are not pad-capable, and our Colombian assets as a group, exceeded our estimated undiscounted cash flows for these assets. Therefore, an impairment charge was necessary to reduce the carrying values of these assets to their estimated fair values, which were based on market appraisals which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. As a result, we recognized impairment charges of $50.2 million during the second quarter of 2015 to reduce the carrying values of all eight drilling rigs in Colombia and related drilling equipment, $3.6 million to reduce the carrying value of inventory in Colombia, $6.4 million to reduce the carrying value of nonrecoverable prepaid taxes associated with our Colombian operations, and $9.7 million to reduce the carrying values of the six non-AC electric drilling rigs in our domestic fleet that are not pad-capable, to their estimated fair values.

9




During the three and nine months ended September 30, 2015, we also recognized impairment charges of $2.3 million and $9.7 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices. As of September 30, 2015, our condensed consolidated balance sheet reflects assets held for sale of $2.1 million, which represents the fair value of certain drilling equipment, one real estate property and other production services equipment. During the nine months ended September 30, 2014, we recorded impairment charges of $0.7 million to reduce the carrying value of certain drilling equipment and real estate property which were held for sale to their estimated fair value less costs to sell.
These impairment charges are not expected to have an impact on our liquidity or debt covenants; however, they are a reflection of the overall downturn in our industry and decline in our projected future cash flows.
With the downturn persisting through 2015, our projected cash flows have declined further as compared to our projections made earlier in the year. At September 30, 2015, we performed impairment testing on our coiled tubing operations and seven drilling rigs, including our domestic pad-capable non-AC rigs, which have a net book value of $83.2 million and $55.7 million, respectively. We concluded that the carrying value of these assets is recoverable, but that these assets are at risk for future impairment if our projected cash flows decline further.
In order to estimate our future undiscounted cash flows from the use and eventual disposition of our drilling assets, we incorporated probabilities of selling these assets in the near term, versus working them at a significantly reduced expected rate of utilization through the end of their remaining useful lives. The most significant assumptions used in our analysis are the expected margin per day and utilization, as well as the estimated proceeds upon any future sale or disposal of the assets. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. If the demand for our drilling services remains at current levels or declines further and any of our rigs become or remain idle for an extended amount of time, then our estimated cash flows may further decrease, and the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.
The most significant inputs used in our impairment analysis of our coiled tubing operations include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.
3.
Valuation Allowances on Deferred Tax Assets
As of September 30, 2015, we had $82.3 million of deferred tax assets related to domestic and foreign net operating losses that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our domestic operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods. The domestic net operating losses have a 20 year carryforward period and can be used to offset future domestic taxable income until their expiration, beginning in 2029, with the latest expiration in 2033. The foreign net operating losses have an indefinite carryforward period. However, as a result of the conditions leading to the impairment of our assets in Colombia, we recorded a valuation allowance of $18.7 million that fully offsets our foreign deferred tax assets relating to net operating losses and other tax benefits.

10




4.     Debt
Our debt consists of the following (amounts in thousands):
 
September 30, 2015
 
December 31, 2014
Senior secured revolving credit facility
$
110,000

 
$
155,000

Senior notes
300,000

 
300,000

Other

 
80

 
410,000

 
455,080

Less current portion

 
(27
)
 
$
410,000

 
$
455,053

Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on September 15, 2015, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $300 million, all of which matures in September 2019 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $300 million.
Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin that ranges from 2.25% to 4.5% and 1.25% to 3.5%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 2.25% and 1.25%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.
As of September 30, 2015, we had $110.0 million outstanding under our Revolving Credit Facility and $17.3 million in committed letters of credit, which resulted in borrowing availability of $172.7 million under our Revolving Credit Facility. There are no limitations on our ability to access the borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At September 30, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.7 to 1.0, our senior consolidated leverage ratio was 0.8 to 1.0, and our interest coverage ratio was 6.9 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:
A maximum total leverage ratio at the end of forthcoming fiscal quarters that cannot exceed: 4.00 to 1.00 on September 30, 2015, 4.50 to 1.00 on December 31, 2015, 5.00 to 1.00 on March 31, 2016, 5.50 to 1.00 during the period commencing June 30, 2016 through and including March 31, 2017, 5.25 to 1.00 on June 30, 2017, 5.00 to 1.00 on September 30, 2017, 4.50 to 1.00 on December 31, 2017, and 4.00 to 1.00 at any time thereafter;
A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed 2.50 to 1.00;
A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and
If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our minimum asset coverage ratio cannot be less than 1.00 to 1.00.

11




The Revolving Credit Facility does not restrict repurchases of capital stock as long as the following conditions are met: (a) no event of default under the Revolving Credit Facility exists or would result from such repurchase, (b) if such repurchase occurs prior to the date on which financial statements for the fiscal quarter ending December 31, 2017 are delivered, after giving effect to such repurchase there is availability under the Revolving Credit Facility of at least $50 million, and the total leverage ratio as of the end of the most recent reported fiscal quarter is not more than 2.50 to 1.00, and (c) if such repurchase occurs on or after such date, after giving effect to such repurchase, there is availability under the Revolving Credit Facility of at least $25 million, and the senior consolidated leverage ratio as of the end of the most recently completed fiscal quarter prior to such repurchase is not greater than 2.00 to 1.00. In addition, the repurchase of capital stock requires, on a pro-forma basis, compliance with the maximum total leverage ratio, minimum interest coverage ratio, and, if applicable, the minimum asset coverage ratio as set forth in the Revolving Credit Facility, both before and after giving effect to such repurchase.
The Revolving Credit Facility also does not restrict capital expenditures as long as (a) no event of default under the Revolving Credit Facility exists or would result from such expenditures, and (b) after giving effect to such expenditures, there is availability under the Revolving Credit Facility of at least $50 million. If the senior consolidated leverage ratio as of the end of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.
At September 30, 2015, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.
The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.
Senior Notes
In March 2010 and November 2011, we issued an aggregate $425 million of unregistered senior notes with a coupon interest rate of 9.875% that were set to mature in 2018 (the “2010 and 2011 Senior Notes”). The net proceeds from the 2010 issuance were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility and a portion of the net proceeds from the 2011 issuance were used to fund the acquisition of the coiled tubing business in December 2011. In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, during 2014, we redeemed all of our outstanding 2010 and 2011 Senior Notes, funded primarily by proceeds from the issuance of our 2014 Senior Notes and additional borrowings under our Revolving Credit Facility, as well as some cash on hand.
In March 2014, we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125% that are due in 2022 (the “2014 Senior Notes”). The 2014 Senior Notes were sold at 100% of their face value. After deductions were made for the $6.1 million for underwriters’ fees and other debt offering costs, we received $293.9 million of net proceeds which were used to fund the repayment of $300 million of aggregate principal amount of 2010 and 2011 Senior Notes in March and May 2014. During the nine months ended September 30, 2014, we recognized a loss on debt extinguishment of $22.5 million for the redemption of $300 million of 2010 and 2011 Senior Notes, which included redemption premiums of $15.4 million, $3.6 million of net unamortized discount and $3.5 million of unamortized debt issuance costs.
The 2014 Senior Notes will mature on March 15, 2022 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the 2014 Senior Notes, in whole or in part, at any time on or after March 15, 2017 in each case at the redemption price specified in the Indenture dated March 18, 2014 (the Indenture) plus any accrued and unpaid interest and any additional interest (as defined in the Indenture) thereon to the date of redemption. Prior to March 15, 2017, we may also redeem the 2014 Senior Notes, in whole or in part, at a

12




“make-whole” redemption price specified in the 2014 Indenture, plus any accrued and unpaid interest and any additional interest thereon to the date of redemption. In addition, prior to March 15, 2017, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the 2014 Senior Notes at a redemption price equal to 106.125% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the 2014 Senior Notes remains outstanding after the occurrence of such redemption and that the redemption occurs within 120 days of the date of the closing of such equity offering.
In accordance with a registration rights agreement with the holders of our 2014 Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on October 2, 2014. 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 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;
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
consolidate with or merge with or into, or sell all or substantially all of our properties to any other person;
enter into transactions with affiliates; and
enter into new lines of business.
The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. (See Note 10, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)
Debt Issuance Costs
Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in September 2019. Costs incurred in connection with the issuance of our 2014 Senior Notes were capitalized and are being amortized using the straight-line method (which approximates amortization using the interest method) over the term of the Senior Notes which mature in March 2022.
Capitalized debt costs related to the issuance of our long-term debt were $9.0 million and $9.8 million as of September 30, 2015 and December 31, 2014, respectively. We recognized $1.7 million of associated amortization during the nine months ended September 30, 2015, which includes the write-off of $0.5 million of debt issuance costs associated with the reduced borrowing capacity of the Revolving Credit Facility that was amended in September 2015, and we recognized $1.5 million of associated amortization during the nine months ended September 30, 2014.
5.
Fair Value of Financial Instruments
ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value.
At September 30, 2015 and December 31, 2014, our financial instruments consist primarily of cash, trade and other receivables, trade payables and long-term debt. The carrying value of cash, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.
The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents the supplemental fair value information about long-term debt at September 30, 2015 and December 31, 2014 (amounts in thousands):
 
September 30, 2015
 
December 31, 2014
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
410,000

 
$
281,555

 
$
455,080

 
$
415,785


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6.
Earnings Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic income per share and diluted income per share computations (amounts in thousands, except per share data):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
Basic
 
 
 
 
 
 
 
Net income (loss)
$
(17,540
)
 
$
12,453

 
$
(106,840
)
 
$
9,555

 
 
 
 
 
 
 
 
Weighted-average shares
64,449

 
63,451

 
64,262

 
62,960

 
 
 
 
 
 
 
 
Income (loss) per common share—Basic
$
(0.27
)
 
$
0.20

 
$
(1.66
)
 
$
0.15

 
 
 
 
 
 
 
 
Diluted
 
 
 
 
 
 
 
Net income (loss)
$
(17,540
)
 
$
12,453

 
$
(106,840
)
 
$
9,555

 
 
 
 
 
 
 
 
Weighted-average shares
 
 
 
 
 
 
 
Outstanding
64,449

 
63,451

 
64,262

 
62,960

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

 
2,425

 

 
2,207

 
64,449

 
65,876

 
64,262

 
65,167

 
 
 
 
 
 
 
 
Income (loss) per common share—Diluted
$
(0.27
)
 
$
0.19

 
$
(1.66
)
 
$
0.15

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 5,272,734 and 4,862,081 shares of common stock for the three and nine months ended September 30, 2015, respectively, and 735,624 and 1,692,549 for the three and nine months ended September 30, 2014, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.
7.
Equity Transactions and Stock-Based Compensation Plans
Equity Transactions
In May 2015, 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, 2015, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity and/or debt offerings, as appropriate, to meet our liquidity needs.
Stock-based Compensation Plans
We grant stock option and restricted stock awards with vesting based on time of service conditions. We also grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

14




The following table summarizes the compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
Stock option awards
$
240

 
$
311

 
$
717

 
$
964

Restricted stock awards
88

 
127

 
311

 
421

Restricted stock unit awards
707

 
1,496

 
1,247

 
4,376

 
$
1,035

 
$
1,934

 
$
2,275

 
$
5,761

Stock Options
We grant stock option awards which generally become exercisable over a three-year period and expire ten years after the date of grant. Our stock-based compensation plans require that all stock option awards have an exercise price that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised.
We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. There were no stock options granted during the three months ended September 30, 2015 or 2014. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the nine months ended September 30, 2015 and 2014:
 
Nine months ended September 30,
 
2015
 
2014
Expected volatility
64
%
 
66
%
Risk-free interest rates
1.4
%
 
1.7
%
Expected life in years
5.52

 
5.49

Options granted
341,638
 
221,440
Grant-date fair value
$2.31
 
$4.87
The assumptions used in the Black-Scholes option pricing model are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.
During the three and nine months ended September 30, 2015, 7,200 and 203,300 stock options, respectively, were exercised at a weighted-average exercise price of $3.84 for both periods. During the three and nine months ended September 30, 2014, 690,877 and 906,277 stock options were exercised at a weighted-average exercise price of $9.70 and $9.14, respectively. We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the fair market value of our stock on the date of exercise over the exercise price of the options. In accordance with ASC Topic 718, when we have excess tax benefits resulting from the exercise of stock options, we report them as financing cash flows in our condensed consolidated statement of cash flows, unless otherwise disallowed under ASC Topic 740, Income Taxes.
Restricted Stock
Historically, we have generally granted restricted stock awards that vest over a three-year period with a fair value based on the closing price of our common stock on the date of the grant. However, beginning in 2013, we began granting restricted stock awards with a vesting period of one year. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions. During the nine months ended September 30, 2015 and 2014, we granted 47,296 and 32,100 shares of restricted stock awards, with a weighted-average grant-date fair value of $7.40 and $14.33, respectively.

15




Restricted Stock Units
We grant restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we grant restricted stock unit awards with vesting based on time of service, which are also subject to performance and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.
There were no restricted stock units granted during the three months ended September 30, 2015. The following table summarizes the number and weighted-average grant-date fair value of the restricted stock unit awards granted during the three months ended September 30, 2014, and nine months ended September 30, 2015 and 2014:
 
Three months ended September 30,
 
Nine months ended September 30,
 
2014
 
2015
 
2014
Time-based RSUs:
 
 
 
 
 
Time-based RSUs granted
13,330

 
151,919

 
360,665

Weighted-average grant-date fair value
$
13.73

 
$
4.08

 
$
8.64

 
 
 
 
 
 
Performance-based RSUs:
 
 
 
 
 
Performance-based RSUs granted

 
531,522

 
321,606

Weighted-average grant-date fair value
$

 
$
6.18

 
$
9.90

Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant.
Our performance-based RSUs generally cliff vest after 39 months from the date of grant and are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years.
Approximately one-third of the performance-based RSUs granted during 2012 and 2013, and half of the performance-based RSUs granted during 2014 and 2015, are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued. The remaining performance-based RSUs are subject to performance conditions, based on our EBITDA and return on capital employed, relative to our predetermined peer group, and therefore the fair value is based on the closing price of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensation expense ultimately recognized for awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.
In April 2015, we determined that 64% of the target number of shares granted during 2012 were actually earned based on the Company’s achievement of certain performance measures, as compared to the predefined peer group, over the performance period from January 1, 2012 through December 31, 2014. The performance-based RSUs granted during 2012 vested and were converted to common stock at the end of April 2015. As of September 30, 2015, we estimated that our actual achievement level for the performance-based RSUs granted during 2013, 2014 and 2015 will be approximately 40%, 80% and 100% of the predetermined performance conditions, respectively.

16




8.
Segment Information
We have two operating segments referred to as the Drilling Services Segment and the Production Services Segment which is the basis management uses for making operating decisions and assessing performance.
Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies through our four drilling divisions in the US, and internationally in Colombia. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.
Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.
The following tables set forth certain financial information for our two operating segments and corporate as of and for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):
 
As of and for the three months ended September 30, 2015
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
571,203

 
$
335,206

 
$
42,719

 
$
949,128

Revenues
$
41,238

 
$
66,242

 
$

 
$
107,480

Operating costs
22,875

 
48,643

 

 
71,518

Segment margin
$
18,363

 
$
17,599

 
$

 
$
35,962

Depreciation and amortization
$
17,648

 
$
17,284

 
$
325

 
$
35,257

Capital expenditures
$
30,757

 
$
4,633

 
$
148

 
$
35,538


 
As of and for the three months ended September 30, 2014
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
779,482

 
$
442,014

 
$
43,261

 
$
1,264,757

Revenues
$
128,117

 
$
145,150

 
$

 
$
273,267

Operating costs
88,963

 
89,993

 

 
178,956

Segment margin
$
39,154

 
$
55,157

 
$

 
$
94,311

Depreciation and amortization
$
28,728

 
$
16,993

 
$
360

 
$
46,081

Capital expenditures
$
36,249

 
$
16,265

 
$
151

 
$
52,665


17





 
As of and for the nine months ended September 30, 2015
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
571,203

 
$
335,206

 
$
42,719

 
$
949,128

Revenues
$
198,212

 
$
238,093

 
$

 
$
436,305

Operating costs
118,114

 
170,517

 

 
288,631

Segment margin
$
80,098

 
$
67,576

 
$

 
$
147,674

Depreciation and amortization
$
62,063

 
$
52,445

 
$
1,020

 
$
115,528

Capital expenditures
$
106,447

 
$
23,786

 
$
465

 
$
130,698

 
As of and for the nine months ended September 30, 2014
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
779,482

 
$
442,014

 
$
43,261

 
$
1,264,757

Revenues
$
373,627

 
$
398,486

 
$

 
$
772,113

Operating costs
250,904

 
250,140

 

 
501,044

Segment margin
$
122,723

 
$
148,346

 
$

 
$
271,069

Depreciation and amortization
$
86,936

 
$
49,478

 
$
984

 
$
137,398

Capital expenditures
$
76,888

 
$
53,094

 
$
596

 
$
130,578

The following table reconciles the segment profits reported above to income from operations as reported on the consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):
 
Three months ended September 30,
 
Nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
Segment margin
$
35,962

 
$
94,311

 
$
147,674

 
$
271,069

Depreciation and amortization
(35,257
)
 
(46,081
)
 
(115,528
)
 
(137,398
)
General and administrative
(16,814
)
 
(26,613
)
 
(56,909
)
 
(76,372
)
Bad debt recovery (expense)
1,071

 
(19
)
 
358

 
(456
)
Impairment charges
(2,329
)
 
(678
)
 
(79,648
)
 
(678
)
Gain (loss) on dispositions of property and equipment
(605
)
 
(142
)
 
2,639

 
1,589

Gain on sale of fishing and rental services operations

 
10,702

 

 
10,702

Gain on litigation

 
1,324

 

 
4,200

Income (loss) from operations
$
(17,972
)
 
$
32,804

 
$
(101,414
)
 
$
72,656


18




The following table sets forth certain financial information for our international operations in Colombia as of and for the three and nine months ended September 30, 2015 and 2014 (amounts in thousands):
 
As of and for the three months ended September 30,
 
As of and for the nine months ended September 30,
 
2015
 
2014
 
2015
 
2014
Identifiable assets
$
57,777

 
$
150,287

 
$
57,777

 
$
150,287

Revenues
$
2,670

 
$
22,904

 
$
36,709

 
$
70,595

Identifiable assets for our international operations in Colombia include five drilling rigs that are owned by our Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.
9.
Commitments and Contingencies
In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $45.3 million relating to our performance under these bonds as of September 30, 2015.
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.
10.
Guarantor/Non-Guarantor Condensed Consolidated Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all existing domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.
In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of September 30, 2015, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of the guarantee arrangements, we are presenting the following condensed consolidated balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.


19




CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands)
 
September 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
26,349

 
$
1,770

 
$
7,560

 
$

 
$
35,679

Receivables, net of allowance
2,310

 
68,008

 
11,655

 

 
81,973

Intercompany receivable (payable)
(24,836
)
 
34,169

 
(9,333
)
 

 

Deferred income taxes
751

 
5,472

 
76

 

 
6,299

Inventory

 
5,841

 
3,154

 

 
8,995

Assets held for sale

 
2,065

 

 

 
2,065

Prepaid expenses and other current assets
1,309

 
3,052

 
1,566

 

 
5,927

Total current assets
5,883

 
120,377

 
14,678

 

 
140,938

Net property and equipment
3,475

 
741,288

 
33,933

 

 
778,696

Investment in subsidiaries
706,106

 
43,254

 

 
(749,360
)
 

Intangible assets, net of accumulated amortization

 
18,268

 

 

 
18,268

Noncurrent deferred income taxes
78,664

 

 

 
(78,664
)
 

Other long-term assets
9,530

 
919

 
777

 

 
11,226

Total assets
$
803,658

 
$
924,106

 
$
49,388

 
$
(828,024
)
 
$
949,128

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
582

 
$
32,562

 
$
1,928

 
$

 
$
35,072

Deferred revenues

 
13,993

 
779

 

 
14,772

Accrued expenses
3,629

 
41,042

 
2,792

 

 
47,463

Total current liabilities
4,211

 
87,597

 
5,499

 

 
97,307

Long-term debt, less current portion
410,000

 

 

 

 
410,000

Noncurrent deferred income taxes

 
127,409

 

 
(78,664
)
 
48,745

Other long-term liabilities
564

 
2,994

 
635

 

 
4,193

Total liabilities
414,775

 
218,000

 
6,134

 
(78,664
)
 
560,245

Total shareholders’ equity
388,883

 
706,106

 
43,254

 
(749,360
)
 
388,883

Total liabilities and shareholders’ equity
$
803,658

 
$
924,106

 
$
49,388

 
$
(828,024
)
 
$
949,128

 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
27,688

 
$
(5,516
)
 
$
12,752

 
$

 
$
34,924

Receivables, net of allowance
1,641

 
151,048

 
37,512

 

 
190,201

Intercompany receivable (payable)
(24,836
)
 
55,567

 
(30,728
)
 
(3
)
 

Deferred income taxes
1,827

 
8,196

 
975

 

 
10,998

Inventory

 
7,208

 
6,909

 

 
14,117

Assets held for sale

 
9,909

 

 

 
9,909

Prepaid expenses and other current assets
1,217

 
6,554

 
1,154

 

 
8,925

Total current assets
7,537

 
232,966

 
28,574

 
(3
)
 
269,074

Net property and equipment
4,179

 
763,994

 
89,118

 
(750
)
 
856,541

Investment in subsidiaries
850,807

 
116,799

 

 
(967,606
)
 

Intangible assets, net of accumulated amortization

 
24,223

 

 

 
24,223

Noncurrent deferred income taxes
90,664

 

 
2,753

 
(90,664
)
 
2,753

Other long-term assets
10,122

 
1,955

 
6,921

 

 
18,998

Total assets
$
963,309

 
$
1,139,937

 
$
127,366

 
$
(1,059,023
)
 
$
1,171,589

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
735

 
$
57,910

 
$
5,660

 
$

 
$
64,305

Current portion of long-term debt

 
27

 

 

 
27

Deferred revenues

 
3,315

 

 

 
3,315

Accrued expenses
11,109

 
64,063

 
4,376

 
(3
)
 
79,545

Total current liabilities
11,844

 
125,315

 
10,036

 
(3
)
 
147,192

Long-term debt, less current portion
455,000

 
53

 

 

 
455,053

Noncurrent deferred income taxes
138

 
160,104

 

 
(90,664
)
 
69,578

Other long-term liabilities
513

 
3,658

 
531

 

 
4,702

Total liabilities
467,495

 
289,130

 
10,567

 
(90,667
)
 
676,525

Total shareholders’ equity
495,814

 
850,807

 
116,799

 
(968,356
)
 
495,064

Total liabilities and shareholders’ equity
$
963,309

 
$
1,139,937

 
$
127,366

 
$
(1,059,023
)
 
$
1,171,589


20




CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)

 
Three months ended September 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
104,810

 
$
2,670

 
$

 
$
107,480

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
67,554

 
3,964

 

 
71,518

Depreciation and amortization
325

 
32,797

 
2,135

 

 
35,257

General and administrative
4,864

 
11,671

 
417

 
(138
)
 
16,814

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense (recovery)

 
(1,071
)
 

 

 
(1,071
)
Impairment charges

 
2,329

 

 

 
2,329

Gain on dispositions of property and equipment
128

 
651

 
(174
)
 

 
605

Total costs and expenses
5,317

 
112,716

 
7,557

 
(138
)
 
125,452

Income (loss) from operations
(5,317
)
 
(7,906
)
 
(4,887
)
 
138

 
(17,972
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(11,208
)
 
(6,309
)
 

 
17,517

 

Interest expense
(5,473
)
 
2

 
6

 

 
(5,465
)
Other
(21
)
 
472

 
(1,098
)
 
(138
)
 
(785
)
Total other income (expense)
(16,702
)
 
(5,835
)
 
(1,092
)
 
17,379

 
(6,250
)
Income (loss) before income taxes
(22,019
)
 
(13,741
)
 
(5,979
)
 
17,517

 
(24,222
)
Income tax (expense) benefit 1
4,479

 
2,533

 
(330
)
 

 
6,682

Net income (loss)
$
(17,540
)
 
$
(11,208
)
 
$
(6,309
)
 
$
17,517

 
$
(17,540
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended September 30, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
250,363

 
$
22,904

 
$

 
$
273,267

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
159,958

 
18,998

 

 
178,956

Depreciation and amortization
358

 
42,250

 
3,473

 

 
46,081

General and administrative
7,110

 
18,665

 
976

 
(138
)
 
26,613

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense (recovery)

 
19

 

 

 
19

Impairment charges

 
678

 

 

 
678

Gain on dispositions of property and equipment

 
147

 
(5
)
 

 
142

Gain on sale of fishing and rental services operations

 
(10,702
)
 

 

 
(10,702
)
Gain on litigation
(1,324
)
 

 

 

 
(1,324
)
Total costs and expenses
6,144

 
209,800

 
24,657

 
(138
)
 
240,463

Income (loss) from operations
(6,144
)
 
40,563

 
(1,753
)
 
138

 
32,804

Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
21,908

 
(3,742
)
 

 
(18,166
)
 

Interest expense
(8,943
)
 
(22
)
 
(4
)
 

 
(8,969
)
Loss on extinguishment of debt

 

 

 

 

Other
(2
)
 
707

 
(2,022
)
 
(138
)
 
(1,455
)
Total other income (expense)
12,963

 
(3,057
)
 
(2,026
)
 
(18,304
)
 
(10,424
)
Income (loss) before income taxes
6,819

 
37,506

 
(3,779
)
 
(18,166
)
 
22,380

Income tax (expense) benefit 1
5,634

 
(15,598
)
 
37

 

 
(9,927
)
Net income (loss)
$
12,453

 
$
21,908

 
$
(3,742
)
 
$
(18,166
)
 
$
12,453

 
 
 
 
 
 
 
 
 
 

21





CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)
 
Nine months ended September 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
399,596

 
$
36,709

 
$

 
$
436,305

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
258,125

 
30,506

 

 
288,631

Depreciation and amortization
1,020

 
104,841

 
9,667

 

 
115,528

General and administrative