10-Q 1 form10q-2q2015.htm 10-Q Form 10Q - 2Q 2015

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
______________________________________________ 
FORM 10-Q
______________________________________________ 
(Mark one)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 July 15, 2015, there were 64,496,689 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 



PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
2015
 
December 31,
2014
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
62,468

 
$
34,924

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
67,663

 
136,161

Unbilled receivables
12,635

 
38,002

Insurance recoveries
15,782

 
10,900

Other receivables
7,158

 
5,138

Deferred income taxes
5,996

 
10,998

Inventory
9,528

 
14,117

Assets held for sale
4,056

 
9,909

Prepaid expenses and other current assets
7,679

 
8,925

Total current assets
192,965

 
269,074

Property and equipment, at cost
1,510,666

 
1,702,273

Less accumulated depreciation
729,575

 
845,732

Net property and equipment
781,091

 
856,541

Intangible assets, net of accumulated amortization of $44.1 million and $40.3 million at June 30, 2015 and December 31, 2014, respectively
20,253

 
24,223

Noncurrent deferred income taxes

 
2,753

Other long-term assets
10,588

 
18,998

Total assets
$
1,004,897

 
$
1,171,589

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
49,302

 
$
64,305

Current portion of long-term debt

 
27

Deferred revenues
26,113

 
3,315

Accrued expenses:
 
 
 
Payroll and related employee costs
17,113

 
40,058

Insurance premiums and deductibles
9,501

 
12,829

Insurance claims and settlements
15,782

 
10,900

Interest
5,467

 
5,432

Other
7,920

 
10,326

Total current liabilities
131,198

 
147,192

Long-term debt, less current portion
410,000

 
455,053

Noncurrent deferred income taxes
54,556

 
69,578

Other long-term liabilities
3,097

 
4,702

Total liabilities
598,851

 
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; 64,481,110 and 63,820,126 shares outstanding at June 30, 2015 and December 31, 2014, respectively
6,494

 
6,414

Additional paid-in capital
473,370

 
472,457

Treasury stock, at cost; 454,577 and 317,103 shares at June 30, 2015 and December 31, 2014, respectively
(3,741
)
 
(3,030
)
Accumulated earnings
(70,077
)
 
19,223

Total shareholders’ equity
406,046

 
495,064

Total liabilities and shareholders’ equity
$
1,004,897

 
$
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 June 30,
 
Six months ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share data)
Revenues:
 
 
 
 
 
 
 
Drilling services
$
58,559

 
$
127,553

 
$
156,974

 
$
245,510

Production services
76,452

 
132,259

 
171,851

 
253,336

Total revenues
135,011

 
259,812

 
328,825

 
498,846

 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
Drilling services
32,815

 
84,022

 
95,111

 
161,941

Production services
53,106

 
82,576

 
121,874

 
160,147

Depreciation and amortization
38,489

 
45,791

 
80,271

 
91,317

General and administrative
18,363

 
25,276

 
40,223

 
49,759

Bad debt expense
394

 
561

 
713

 
437

Impairment charges
71,329

 

 
77,319

 

Gain on dispositions of property and equipment
(4,377
)
 
(331
)
 
(3,244
)
 
(1,731
)
Gain on litigation

 

 

 
(2,876
)
Total costs and expenses
210,119

 
237,895

 
412,267

 
458,994

Income (loss) from operations
(75,108
)
 
21,917

 
(83,442
)
 
39,852

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(5,245
)
 
(10,728
)
 
(10,700
)
 
(23,116
)
Loss on extinguishment of debt

 
(14,595
)
 

 
(22,482
)
Other
486

 
2,017

 
(2,194
)
 
1,815

Total other expense
(4,759
)
 
(23,306
)
 
(12,894
)
 
(43,783
)
 
 
 
 
 
 
 
 
Loss before income taxes
(79,867
)
 
(1,389
)
 
(96,336
)
 
(3,931
)
Income tax benefit
2,586

 
1,070

 
7,036

 
1,033

Net loss
$
(77,281
)
 
$
(319
)
 
$
(89,300
)
 
$
(2,898
)
 
 
 
 
 
 
 
 
Loss per common share—Basic
$
(1.20
)
 
$
(0.01
)
 
$
(1.39
)
 
$
(0.05
)
 
 
 
 
 
 
 
 
Loss per common share—Diluted
$
(1.20
)
 
$
(0.01
)
 
$
(1.39
)
 
$
(0.05
)
 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
64,342

 
62,877

 
64,168

 
62,710

 
 
 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
64,342

 
62,877

 
64,168

 
62,710









See accompanying notes to condensed consolidated financial statements.

3




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Six months ended June 30,
 
2015
 
2014
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(89,300
)
 
$
(2,898
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
80,271

 
91,317

Allowance for doubtful accounts
713

 
396

Gain on dispositions of property and equipment
(3,244
)
 
(1,731
)
Stock-based compensation expense
1,240

 
3,827

Amortization of debt issuance costs, discount and premium
827

 
1,504

Loss on extinguishment of debt

 
22,482

Impairment charges
77,319

 

Deferred income taxes
(8,267
)
 
(3,762
)
Change in other long-term assets
1,018

 
4,448

Change in other long-term liabilities
(1,606
)
 
(1,284
)
Changes in current assets and liabilities:
 
 
 
Receivables
91,881

 
(23,463
)
Inventory
1,001

 
(234
)
Prepaid expenses and other current assets
1,384

 
(77
)
Accounts payable
(26,220
)
 
7,667

Deferred revenues
22,798

 
2,607

Accrued expenses
(28,044
)
 
(5,312
)
Net cash provided by operating activities
121,771

 
95,487

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(84,027
)
 
(74,567
)
Proceeds from sale of property and equipment
34,538

 
6,538

Proceeds from insurance recoveries
227

 

Net cash used in investing activities
(49,262
)
 
(68,029
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
(45,002
)
 
(330,013
)
Proceeds from issuance of debt

 
320,000

Debt issuance costs
(5
)
 
(6,187
)
Tender premium costs

 
(15,381
)
Proceeds from exercise of options
753

 
1,581

Purchase of treasury stock
(711
)
 
(1,132
)
Net cash used in financing activities
(44,965
)
 
(31,132
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
27,544

 
(3,674
)
Beginning cash and cash equivalents
34,924

 
27,385

Ending cash and cash equivalents
$
62,468

 
$
23,711

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
11,385

 
$
25,250

Income tax paid
$
2,331

 
$
2,131

Noncash investing and financing activity:
 
 
 
Change in capital expenditure accruals
$
11,133

 
$
3,346

 
See accompanying notes to condensed consolidated financial statements.

4




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO 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.
Since 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 are the most desirable rig design available. During the first half of 2015, we sold 27 of our mechanical and lower horsepower electric drilling rigs. As of June 30, 2015, we continue to have three of this type of rig remaining in our fleet that are well suited for certain higher margin turnkey or horizontal drilling projects, and one rig classified as held for sale.
As the downturn worsened through the first half of 2015 resulting in significantly reduced revenue and utilization rates, and as current projections 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 which are currently idle. As a result, we recognized $71.3 million of impairment charges during the second quarter of 2015, primarily to reduce the carrying values of all eight drilling rigs in Colombia and certain other assets associated with our Colombian operations, as well as the six non-AC electric drilling rigs in our domestic fleet that are not pad-capable, to their estimated fair values.
As of June 30, 2015, the drilling rigs in our fleet, excluding the one rig classified as held for sale, are assigned to the following divisions:
Drilling Division
Rig Count
South Texas
11

West Texas
4

North Dakota
8

Appalachia
4

Colombia
8

 
35

As of June 30, 2015, 18 of our 35 drilling rigs are earning revenues under drilling contracts, 15 of which are earning under term contracts. Our eight drilling rigs in Colombia are currently idle. We are actively marketing them to various operators in Colombia to diversify our client base, and evaluating other options including the possibility of the sale of some or all of our assets in Colombia.
In April 2015, we deployed our first of five new-build 1,500 horsepower AC drilling rigs to be delivered this year. We expect to deploy three new-build rigs in the third quarter and the final rig by the end of the year. Three of the remaining new-build drilling rigs to be deployed are under multi-year term contracts. The multi-year contract that was initially assigned to the fifth new-build drilling rig has been transferred to an existing AC rig in North Dakota that has a contract expiring in November 2015, thereby allowing us to market the fifth new-build rig to a new domestic client.

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Including the five new-build drilling rigs, 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.
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 June 30, 2015, we have a fleet of 121 well servicing rigs, consisting of 110 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 June 30, 2015 were 73% and 24%, respectively, based on total fleet count.
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.
As of June 30, 2015, 18 of our 35 drilling rigs are earning revenues under drilling contracts, 15 of which are earning under term contracts, and which if not renewed prior to the end of their terms, will expire as follows:
 
 
 
 
Term Contract Expiration by Period
 
 
Total
 
Within
6 Months
 
6 Months
to 1 Year
 
1 Year to
18 Months
 
18 Months
to 2 Years
 
2 to 4 Years
Term Contracts
 
15

 
3

 
6

 
4

 

 
2

With most long-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 long-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 during recent months, term contracts for 16 of our drilling rigs have been early terminated, including seven of our 15 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 $11.3 million and $16.0 million of revenue for early termination payments during the first and second quarters of 2015, respectively, and $0.3 million in the fourth quarter of 2014.
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

6




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 June 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 $12.6 million at June 30, 2015, of which $11.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at June 30, 2015 and $0.8 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.
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
Substantially all of 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 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

7




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 and other deferred liabilities.
Related-Party Transactions
During the six months ended June 30, 2015 and 2014, the Company paid approximately $0.1 million and $0.2 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 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 2017. In July 2015, the FASB decided to defer the effective date by one year (until 2018), but the FASB still needs to issue an ASU to change the effective date. 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 Accounting Standards Update 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 six months ended June 30, 2015 and 2014, we had capital expenditures of $95.2 million and $77.9 million, respectively, which includes $1.5 million and $0.1 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 June 30, 2015 and December 31, 2014, capital expenditures incurred for property and equipment not yet placed in service was $98.2 million and $82.7 million, respectively.
During the six months ended June 30, 2015, we recorded total gains on disposition of our property and equipment of $3.2 million, primarily for the sales of 27 of our mechanical and lower horsepower electric drilling rigs and other drilling equipment which we sold for aggregate net proceeds of $33.4 million, of which $0.8 million was recognized as a receivable at June 30, 2015. During the six months ended June 30, 2014, we recorded total gains on disposition of our property and equipment of $1.7 million, of which $1.1 million was related to the sale of our trucking assets in February 2014.
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.
Since 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 are the most desirable rig design available. As the downturn worsened through the first half of 2015 resulting in significantly reduced revenue and utilization rates, and as current projections 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 which are currently idle. We also performed an impairment test on our coiled tubing operations, which have a net book value of $90.0 million at June 30, 2015.
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.
Our analysis indicated that the carrying value of our coiled tubing reporting unit was recoverable and thus there was no impairment present at June 30, 2015. Our analysis indicated that there was no impairment present for the six pad-capable non-AC drilling rigs in our fleet (those that are equipped with either a walking or skidding system), which have a total net book value of $47.4 million 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.

9




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.
Additionally, during the three and six months ended June 30, 2015, we recognized impairment charges of $1.5 million and $7.5 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 June 30, 2015, our condensed consolidated balance sheet reflects assets held for sale of $4.1 million, which represents the fair value of one drilling rig, two wireline units, one real estate property and other drilling equipment.
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. 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.
3.
Valuation Allowances on Deferred Tax Assets
As of June 30, 2015, we had $80.7 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 drilling rigs and other assets related to our Colombian operations, we recorded a valuation allowance of $21.1 million as of June 30, 2015 that fully offsets our foreign deferred tax assets relating to net operating losses and other tax benefits.
4.     Debt
Our debt consists of the following (amounts in thousands):
 
June 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 22, 2014, 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 $350 million, all of which matures on September 22, 2019 (the “Revolving Credit Facility”). In addition, at our request, and with the lenders' consent, the aggregate commitments of the lenders under the Revolving Credit Facility may be increased up to an additional $100 million provided that no default exists, all representations and warranties are true and correct, and compliance with financial covenants as set forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances,

10




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 $350 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 2.0% to 3.0% and 1.0% to 2.0%, 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 July 30, 2015, we had $110.0 million outstanding under our Revolving Credit Facility and $21.3 million in committed letters of credit, which resulted in borrowing availability of $218.7 million under our Revolving Credit Facility. There are no limitations on our ability to access this 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 June 30, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.1 to 1.0, our senior consolidated leverage ratio was 0.6 to 1.0, and our interest coverage ratio was 7.9 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:
A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;
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.
The Revolving Credit Facility does not restrict capital expenditures or repurchases of capital stock as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures or repurchases of capital stock, (b) after giving effect to such capital expenditures or repurchases of capital stock there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less 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 and minimum interest coverage ratio as set forth in the Revolving Credit Facility, both before and after giving effect to such repurchase. If the senior consolidated leverage ratio as of the last day 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 June 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.

11




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 three months ended March 31, 2014, we recognized a loss on debt extinguishment of $7.9 million for the redemption of $99.5 million of 2010 and 2011 Senior Notes in March 2014, which included redemption premiums of $5.5 million, $1.2 million of net unamortized discount and $1.2 million of unamortized debt issuance costs. Additionally, we recognized a loss on debt extinguishment during the three months ended June 30, 2014 of $14.6 million for the redemption of $200.5 million of 2010 and 2011 Senior Notes in May 2014, which included redemption premiums of $9.9 million, $2.4 million of net unamortized discount and $2.3 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 “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.

12




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 June 30, 2015 and December 31, 2014, respectively. We recognized $0.8 million and $1.1 million of associated amortization during the six months ended June 30, 2015 and 2014, respectively.
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 June 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 June 30, 2015 and December 31, 2014 (amounts in thousands):
 
June 30, 2015
 
December 31, 2014
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
410,000

 
$
353,032

 
$
455,080

 
$
415,785


13




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 June 30,
 
Six months ended June 30,
 
2015
 
2014
 
2015
 
2014
Basic
 
 
 
 
 
 
 
Net loss
$
(77,281
)
 
$
(319
)
 
$
(89,300
)
 
$
(2,898
)
 
 
 
 
 
 
 
 
Weighted-average shares
64,342

 
62,877

 
64,168

 
62,710

 
 
 
 
 
 
 
 
Loss per common share—Basic
$
(1.20
)
 
$
(0.01
)
 
$
(1.39
)
 
$
(0.05
)
 
 
 
 
 
 
 
 
Diluted
 
 
 
 
 
 
 
Net loss
$
(77,281
)
 
$
(319
)
 
$
(89,300
)
 
$
(2,898
)
 
 
 
 
 
 
 
 
Weighted-average shares
 
 
 
 
 
 
 
Outstanding
64,342

 
62,877

 
64,168

 
62,710

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

 

 

 

 
64,342

 
62,877

 
64,168

 
62,710

 
 
 
 
 
 
 
 
Loss per common share—Diluted
$
(1.20
)
 
$
(0.01
)
 
$
(1.39
)
 
$
(0.05
)
Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 4,717,647 and 4,893,961 shares of common stock for the three and six months ended June 30, 2015, respectively, and 3,213,088 and 4,170,854 for the three and six months ended June 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 June 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 six months ended June 30, 2015 and 2014 (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2015
 
2014
 
2015
 
2014
Stock option awards
$
213

 
$
310

 
$
477

 
$
653

Restricted stock awards
99

 
141

 
223

 
294

Restricted stock unit awards
523

 
1,520

 
540

 
2,880

 
$
835

 
$
1,971

 
$
1,240

 
$
3,827

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 June 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 six months ended June 30, 2015 and 2014:
 
Six months ended June 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 six months ended June 30, 2015, 39,600 and 196,100 stock options, respectively, were exercised at a weighted-average exercise price of $3.84. During the three and six months ended June 30, 2014, 168,500 and 215,400 stock options were exercised at a weighted-average exercise price of $7.74 and $7.34, 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, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our condensed consolidated statement of cash flows.
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 six months ended June 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 June 30, 2014. 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 June 30, 2015 and the six months ended June 30, 2015 and 2014:
 
Three months ended June 30,
 
Six months ended June 30,
 
2015
 
2015
 
2014
Time-based RSUs:
 
 
 
 
 
Time-based RSUs granted

 
151,919

 
347,335

Weighted-average grant-date fair value
$

 
$
4.08

 
$
8.44

 
 
 
 
 
 
Performance-based RSUs:
 
 
 
 
 
Performance-based RSUs granted
145,107

 
439,773

 
321,606

Weighted-average grant-date fair value
$
8.34

 
$
5.76

 
$
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 June 30, 2015, we estimated that our actual achievement level for the performance-based RSUs granted during 2013, 2014 and 2015 will be approximately 60%, 100% 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 six months ended June 30, 2015 and 2014 (amounts in thousands):
 
As of and for the three months ended June 30, 2015
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
574,050

 
$
356,669

 
$
74,178

 
$
1,004,897

Revenues
$
58,559

 
$
76,452

 
$

 
$
135,011

Operating costs
32,815

 
53,106

 

 
85,921

Segment margin
$
25,744

 
$
23,346

 
$

 
$
49,090

Depreciation and amortization
$
20,815

 
$
17,328

 
$
346

 
$
38,489

Capital expenditures
$
42,634

 
$
3,696

 
$
14

 
$
46,344


 
As of and for the three months ended June 30, 2014
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
778,148

 
$
413,308

 
$
59,975

 
$
1,251,431

Revenues
$
127,553

 
$
132,259

 
$

 
$
259,812

Operating costs
84,022

 
82,576

 

 
166,598

Segment margin
$
43,531

 
$
49,683

 
$

 
$
93,214

Depreciation and amortization
$
28,969

 
$
16,466

 
$
356

 
$
45,791

Capital expenditures
$
19,383

 
$
21,486

 
$
127

 
$
40,996


17





 
As of and for the six months ended June 30, 2015
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
574,050

 
$
356,669

 
$
74,178

 
$
1,004,897

Revenues
$
156,974

 
$
171,851

 
$

 
$
328,825

Operating costs
95,111

 
121,874

 

 
216,985

Segment margin
$
61,863

 
$
49,977

 
$

 
$
111,840

Depreciation and amortization
$
44,415

 
$
35,161

 
$
695

 
$
80,271

Capital expenditures
$
75,690

 
$
19,153

 
$
317

 
$
95,160

 
As of and for the six months ended June 30, 2014
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
778,148

 
$
413,308

 
$
59,975

 
$
1,251,431

Revenues
$
245,510

 
$
253,336

 
$

 
$
498,846

Operating costs
161,941

 
160,147

 

 
322,088

Segment margin
$
83,569

 
$
93,189

 
$

 
$
176,758

Depreciation and amortization
$
58,208

 
$
32,485

 
$
624

 
$
91,317

Capital expenditures
$
40,639

 
$
36,829

 
$
445

 
$
77,913

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 six months ended June 30, 2015 and 2014 (amounts in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2015
 
2014
 
2015
 
2014
Segment margin
$
49,090

 
$
93,214

 
$
111,840

 
$
176,758

Depreciation and amortization
(38,489
)
 
(45,791
)
 
(80,271
)
 
(91,317
)
General and administrative
(18,363
)
 
(25,276
)
 
(40,223
)
 
(49,759
)
Bad debt expense
(394
)
 
(561
)
 
(713
)
 
(437
)
Impairment charges
(71,329
)
 

 
(77,319
)
 

Gain on dispositions of property and equipment
4,377

 
331

 
3,244

 
1,731

Gain on litigation

 

 

 
2,876

Income (loss) from operations
$
(75,108
)
 
$
21,917

 
$
(83,442
)
 
$
39,852

The following table sets forth certain financial information for our international operations in Colombia as of and for the three and six months ended June 30, 2015 and 2014 (amounts in thousands):
 
As of and for the three months ended June 30,
 
As of and for the six months ended June 30,
 
2015
 
2014
 
2015
 
2014
Identifiable assets
$
65,902

 
$
157,025

 
$
65,902

 
$
157,025

Revenues
$
14,078

 
$
25,527

 
$
34,039

 
$
47,691

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.

18




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 $45.4 million relating to our performance under these bonds as of June 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 June 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)
 
June 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
57,686

 
(2,033
)
 
6,815

 

 
$
62,468

Receivables, net of allowance
2,335

 
74,384

 
26,519

 

 
103,238

Intercompany receivable (payable)
(24,836
)
 
41,788

 
(16,952
)
 

 

Deferred income taxes
700

 
5,093

 
203

 

 
5,996

Inventory

 
6,378

 
3,150

 

 
9,528

Assets held for sale

 
4,056

 

 

 
4,056

Prepaid expenses and other current assets
1,192

 
4,972

 
1,515

 

 
7,679

Total current assets
37,077

 
134,638

 
21,250

 

 
192,965

Net property and equipment
3,652

 
741,734

 
35,705

 

 
781,091

Investment in subsidiaries
654,656

 
49,587

 

 
(704,243
)
 

Intangible assets, net of accumulated amortization

 
20,253

 

 

 
20,253

Noncurrent deferred income taxes
119,992

 

 

 
(119,992
)
 

Other long-term assets
9,466

 
1,122

 

 

 
10,588

Total assets
$
824,843

 
$
947,334

 
$
56,955

 
$
(824,235
)
 
$
1,004,897

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
986

 
$
45,883

 
$
2,433

 

 
$
49,302

Current portion of long-term debt

 

 

 

 

Deferred revenues

 
26,113

 

 

 
26,113

Accrued expenses
7,393

 
43,682

 
4,708

 

 
55,783

Total current liabilities
8,379

 
115,678

 
7,141

 

 
131,198

Long-term debt, less current portion
410,000

 

 

 

 
410,000

Noncurrent deferred income taxes

 
174,548

 

 
(119,992
)
 
54,556

Other long-term liabilities
418

 
2,452

 
227

 

 
3,097

Total liabilities
418,797

 
292,678

 
7,368

 
(119,992
)
 
598,851

Total shareholders’ equity
406,046

 
654,656

 
49,587

 
(704,243
)
 
406,046

Total liabilities and shareholders’ equity
$
824,843

 
$
947,334

 
$
56,955

 
$
(824,235
)
 
$
1,004,897

 
 
 
 
 
 
 
 
 
 
 
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
830,185

 
116,799

 

 
(946,984
)
 

Intangible assets, net of accumulated amortization

 
24,223

 

 

 
24,223

Noncurrent deferred income taxes
111,286

 

 
2,753

 
(111,286
)
 
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

 
180,726

 

 
(111,286
)
 
69,578

Other long-term liabilities
513

 
3,658

 
531

 

 
4,702

Total liabilities
467,495

 
309,752

 
10,567

 
(111,289
)
 
676,525

Total shareholders’ equity
495,814

 
830,185

 
116,799

 
(947,734
)
 
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 June 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
120,933

 
$
14,078

 
$

 
$
135,011

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
74,907

 
11,014

 

 
85,921

Depreciation and amortization
346

 
34,367

 
3,776

 

 
38,489

General and administrative
5,685

 
12,118

 
698

 
(138
)
 
18,363

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense

 
394

 

 

 
394

Impairment charges

 
15,447

 
56,632

 
(750
)
 
71,329

Gain on dispositions of property and equipment

 
(4,359
)
 
(18
)
 

 
(4,377
)
Total costs and expenses
6,031

 
131,659

 
73,317

 
(888
)
 
210,119

Income (loss) from operations
(6,031
)
 
(10,726
)
 
(59,239
)
 
888

 
(75,108
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(70,508
)
 
(62,574
)
 

 
133,082

 

Interest expense
(5,135
)
 
(118
)
 
8

 

 
(5,245
)
Other
(2
)
 
419

 
207

 
(138
)
 
486

Total other income (expense)
(75,645
)
 
(62,273
)
 
215

 
132,944

 
(4,759
)
Income (loss) before income taxes
(81,676
)
 
(72,999
)
 
(59,024
)
 
133,832

 
(79,867
)
Income tax (expense) benefit
3,645

 
2,491

 
(3,550
)
 

 
2,586

Net income (loss)
$
(78,031
)
 
$
(70,508
)
 
$
(62,574
)
 
$
133,832

 
$
(77,281
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended June 30, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
234,285

 
$
25,527

 
$

 
$
259,812

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
149,539

 
17,059

 

 
166,598

Depreciation and amortization
356

 
41,979

 
3,456

 

 
45,791

General and administrative
6,800

 
17,438

 
1,176

 
(138
)
 
25,276

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense

 
561

 

 

 
561

Gain on dispositions of property and equipment

 
(186
)
 
(145
)
 

 
(331
)
Total costs and expenses
7,156

 
208,116

 
22,761

 
(138
)
 
237,895

Income (loss) from operations
(7,156
)
 
26,169

 
2,766

 
138

 
21,917

Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
19,707

 
3,512

 

 
(23,219
)
 

Interest expense
(10,707
)
 
(24
)
 
3

 

 
(10,728
)
Loss on extinguishment of debt
(14,595
)
 

 

 

 
(14,595
)
Other
7

 
617

 
1,531

 
(138
)
 
2,017

Total other income (expense)
(5,588
)
 
4,105

 
1,534

 
(23,357
)
 
(23,306
)
Income (loss) before income taxes
(12,744
)
 
30,274

 
4,300

 
(23,219
)
 
(1,389
)
Income tax (expense) benefit
12,425

 
(10,567
)
 
(788
)
 

 
1,070

Net income (loss)
$
(319
)
 
$
19,707

 
$
3,512

 
$
(23,219
)
 
$
(319
)
 
 
 
 
 
 
 
 
 
 





21




CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)

 
Six months ended June 30, 2015
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
294,786

 
$
34,039

 
$

 
$
328,825

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
190,443

 
26,542

 

 
216,985

Depreciation and amortization
695

 
72,044

 
7,532

 

 
80,271

General and administrative
10,760

 
28,373

 
1,366

 
(276
)
 
40,223

Intercompany leasing

 
(2,430
)
 
2,430

 

 

Bad debt expense

 
713

 

 

 
713

Impairment charges

 
21,437

 
56,632

 
(750
)
 
77,319

Gain on dispositions of property and equipment

 
(3,223
)
 
(21
)
 

 
(3,244
)
Total costs and expenses
11,455

 
307,357

 
94,481

 
(1,026
)
 
412,267

Income (loss) from operations
(11,455
)
 
(12,571
)
 
(60,442
)
 
1,026

 
(83,442
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
(75,971
)
 
(67,163
)
 

 
143,134