10-Q 1 a2014q110q.htm 10-Q 2014 Q1 10Q

 
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 March 31, 2014
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
o
Accelerated filer
x
 
 
 
 
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 April 15, 2014, there were 62,748,941 shares of common stock, par value $0.10 per share, of the registrant outstanding.
 





PART 1. FINANCIAL INFORMATION
Item 1.
Financial Statements
PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
March 31,
2014
 
December 31,
2013
 
(unaudited)
 
(audited)
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
20,810

 
$
27,385

Restricted cash
210,401

 

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
121,790

 
115,908

Unbilled receivables
44,792

 
49,535

Insurance recoveries
9,657

 
8,607

Income taxes and other
6,493

 
2,310

Deferred income taxes
11,569

 
13,092

Inventory
13,750

 
13,232

Prepaid expenses and other current assets
6,610

 
9,311

Total current assets
445,872

 
239,380

Property and equipment, at cost
1,740,920

 
1,724,124

Less accumulated depreciation
813,991

 
786,467

Net property and equipment
926,929

 
937,657

Intangible assets, net of accumulated amortization of $34.3 million and
$32.8 million at March 31, 2014 and December 31, 2013, respectively
30,272

 
32,269

Noncurrent deferred income taxes
4,020

 
1,156

Other long-term assets
19,284

 
19,161

Total assets
$
1,426,377

 
$
1,229,623

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
53,969

 
$
43,718

Current portion of long-term debt
202,166

 
2,847

Deferred revenues
2,159

 
699

Accrued expenses:
 
 
 
Payroll and related employee costs
24,586

 
30,020

Insurance premiums and deductibles
10,896

 
10,940

Insurance claims and settlements
9,657

 
8,607

Interest
2,057

 
12,275

Other
10,898

 
11,727

Total current liabilities
316,388

 
120,833

Long-term debt, less current portion
501,133

 
499,666

Noncurrent deferred income taxes
84,596

 
84,636

Other long-term liabilities
6,706

 
6,055

Total liabilities
908,823

 
711,190

Commitments and contingencies (Note 7)

 

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

 

Common stock $.10 par value; 100,000,000 shares authorized; 62,740,394 and 62,534,636 shares outstanding at March 31, 2014 and December 31, 2013, respectively
6,301

 
6,275

Additional paid-in capital
458,919

 
456,812

Treasury stock, at cost; 270,777 and 219,304 shares at March 31, 2014 and December 31, 2013, respectively
(2,328
)
 
(1,895
)
Accumulated earnings
54,662

 
57,241

Total shareholders’ equity
517,554

 
518,433

Total liabilities and shareholders’ equity
$
1,426,377

 
$
1,229,623

See accompanying notes to condensed consolidated financial statements.

2




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
 
Three months ended March 31,
 
2014
 
2013
 
(in thousands, except per share data)
Revenues:
 
 
 
Drilling services
$
117,957

 
$
133,074

Production services
121,077

 
96,596

Total revenues
239,034

 
229,670

Costs and expenses:
 
 
 
Drilling services
76,338

 
88,986

Production services
77,752

 
60,619

Depreciation and amortization
45,526

 
46,285

General and administrative
24,483

 
23,054

Bad debt expense (recovery)
(124
)
 
281

Total costs and expenses
223,975

 
219,225

Income from operations
15,059

 
10,445

Other (expense) income:
 
 
 
Interest expense
(12,388
)
 
(11,462
)
Loss on extinguishment of debt
(7,887
)
 

Other
2,674

 
(821
)
Total other expense
(17,601
)
 
(12,283
)
Loss before income taxes
(2,542
)
 
(1,838
)
Income tax benefit (expense)
(37
)
 
546

Net loss
$
(2,579
)
 
$
(1,292
)
 
 
 
 
Loss per common share—Basic
$
(0.04
)
 
$
(0.02
)
 
 
 
 
Loss per common share—Diluted
$
(0.04
)
 
$
(0.02
)
 
 
 
 
Weighted average number of shares outstanding—Basic
62,542

 
61,967

 
 
 
 
Weighted average number of shares outstanding—Diluted
62,542

 
61,967















See accompanying notes to condensed consolidated financial statements.

3




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Three months ended March 31,
 
2014
 
2013
 
(in thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(2,579
)
 
$
(1,292
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
45,526

 
46,285

Allowance for doubtful accounts
(164
)
 
281

Gain on dispositions of property and equipment
(1,400
)
 
(321
)
Stock-based compensation expense
1,856

 
1,512

Amortization of debt issuance costs, discount and premium
869

 
762

Loss on extinguishment of debt
7,887

 

Deferred income taxes
(1,364
)
 
(1,287
)
Change in other long-term assets
4,193

 
(2,658
)
Change in other long-term liabilities
651

 
953

Changes in current assets and liabilities:
 
 
 
Receivables
(5,158
)
 
(4,252
)
Inventory
(518
)
 
(226
)
Prepaid expenses and other current assets
2,703

 
3,640

Accounts payable
5,006

 
(6,713
)
Deferred revenues
1,460

 
(1,663
)
Accrued expenses
(17,733
)
 
(17,864
)
Net cash provided by operating activities
41,235

 
17,157

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(31,674
)
 
(71,313
)
Proceeds from sale of property and equipment
5,516

 
1,567

Net cash used in investing activities
(26,158
)
 
(69,746
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
(119,478
)
 
(656
)
Proceeds from issuance of debt
320,000

 
40,000

Debt issuance costs
(6,138
)
 

Change in restricted cash
(210,401
)
 

Tender premium costs
(5,479
)
 

Proceeds from exercise of options
277

 
295

Purchase of treasury stock
(433
)
 
(275
)
Net cash provided by (used in) financing activities
(21,652
)
 
39,364

 
 
 
 
Net decrease in cash and cash equivalents
(6,575
)
 
(13,225
)
Beginning cash and cash equivalents
27,385

 
23,733

Ending cash and cash equivalents
$
20,810

 
$
10,508

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
21,854

 
$
21,956

Income tax paid
$
876

 
$
320

 



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 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 coiled tubing and wireline services offshore in the Gulf of Mexico.
Our Drilling Services Segment provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
Rig Count
South Texas
14

West Texas
18

North Dakota
11

Utah
7

Appalachia
4

Colombia
8

 
62

As of March 31, 2014, 54 of our 62 drilling rigs are earning revenues under drilling contracts, 41 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, six of which are currently earning revenues with the remaining two rigs expected to be operating by early May 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. 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, turnkey or footage 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.
Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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 March 31, 2014, we have a fleet of 109 well servicing rigs consisting of ninety-nine 550 horsepower rigs and ten 600 horsepower rigs, all of which are currently operating or are being actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 120 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $17.4 million in fishing and rental tools.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("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 condensed consolidated financial

5




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, 2013.
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 fair value 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 March 31, 2014, through the filing of this Form 10-Q, for inclusion as necessary.
Drilling Contracts
Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage 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. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with original terms of six months to four years in duration. As of March 31, 2014, we have 43 drilling rigs under term contracts, which if not renewed at 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
 
35

 
21

 
8

 

 
4

 
2

Colombia
 
8

 

 
8

 

 

 

 
 
43

 
21

 
16

 

 
4

 
2

Restricted Cash
Our restricted cash balance represents funds committed for the redemption of 2010 and 2011 Senior Notes in May 2014. (See Note 2, Debt.)
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 and footage drilling contracts are invoiced upon completion of the contract.
Our unbilled receivables totaled $44.8 million at March 31, 2014, of which $0.5 million related to turnkey drilling contract revenues, $38.7 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at March 31, 2014 and $5.6 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.

6




Property and Equipment
As of March 31, 2014 and December 31, 2013, we had incurred $36.3 million and $19.4 million, respectively, in construction costs for ongoing projects. During the three months ended March 31, 2014 and 2013, we capitalized $48,000 and $0.8 million, respectively, of interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment.
We recorded gains on disposition of our property and equipment of $1.4 million and gains of $0.3 million for the three months ended March 31, 2014 and 2013, respectively, in our drilling and production services costs and expenses. In February 2014, we completed the sale of our trucking assets for a sales price of $4.5 million which included a fleet of 40 trucks and related transportation equipment that we used to transport our drilling rigs to and from drilling sites. By owning our own trucks, we have historically been able to reduce the overall cost and downtime between rig moves. However, with the industry trend toward pad drilling, we have upgraded a number of our drilling rigs in recent years to equip them with walking or skidding systems, which enable the drilling rigs to move between wells in pad drilling, and thus operating our own trucking fleet has become less beneficial. The net book value of the trucking assets sold was $3.4 million, for which we recognized a total gain of $1.1 million in our condensed consolidated statement of operations for the first quarter of 2014.
As of March 31, 2014, we have identified certain real estate properties and other production services equipment which are currently held for sale. The total value of these properties, which are recorded at the lower of cost or fair market value and which is included in property and equipment in our condensed consolidated balance sheet, is approximately $0.9 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, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. 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.
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, coiled tubing and fishing and rental services). 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.

7




Other Long-Term Assets
Other long-term assets consist of noncurrent prepaid taxes in Colombia which are creditable against future income taxes, 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, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Our other accrued expenses also consist of the current portion of the Colombian net equity tax.
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of liabilities associated with our long-term compensation plans, deferred mobilization revenues, and other deferred liabilities.
Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.
2.     Debt
Our debt consists of the following (amounts in thousands):
 
March 31, 2014
 
December 31, 2013
Senior secured revolving credit facility
$
80,000

 
$
80,000

Senior notes
621,588

 
419,586

Other
1,711

 
2,927

 
703,299

 
502,513

Less current portion
(202,166
)
 
(2,847
)
 
$
501,133

 
$
499,666

Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on June 30, 2011 and March 3, 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 $250 million, all of which matures on June 30, 2016 (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 $250 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 2.50% to 3.25% and 1.50% to 2.25%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 2.75% and 1.75%, 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. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC was added as a subsidiary

8




guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.
As of March 31, 2014, we had $80.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $156.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At March 31, 2014, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.8 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0, and our interest coverage ratio was 5.3 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 as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures 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. 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 March 31, 2014, 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, redemptions of capital stock, 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.
On March 3, 2014, the Revolving Credit Facility was amended to increase the amount of unsecured debt that we could incur, in order to facilitate the offering of our 2014 Senior Notes and the use of proceeds therefrom to repurchase a portion of our 2010 and 2011 Senior Notes, as described further below.
Senior Notes
On March 11, 2010, we issued $250 million of unregistered senior notes with a coupon interest rate of 9.875% that are due in 2018 (the “2010 Senior Notes”). The 2010 Senior Notes were sold with an original issue discount of $10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity of approximately 10.677%. On March 11, 2010, we received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility.

9




On November 21, 2011, we issued $175 million of unregistered Senior Notes (the “2011 Senior Notes”). The 2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the acquisition of the coiled tubing business of Go-Coil, L.L.C. ("Go-Coil") in December 2011.
In accordance with a registration rights agreement with the holders of both our 2010 Senior Notes and 2011 Senior Notes, we filed exchange offer registration statements on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010 and July 13, 2012, respectively. These exchange offer registration statements enabled the holders of both our 2010 Senior Notes and 2011 Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “2010 Senior Notes” and “2011 Senior Notes” herein include the senior notes issued in the exchange offers.
The 2010 and 2011 Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the 2010 and 2011 Senior Notes, in whole or in part, at any time (on or after March 15, 2014) in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “2010 and 2011 Indenture”) plus any accrued and unpaid interest and any additional interest thereon to the date of redemption. Prior to March 15, 2014, we could also redeem the 2010 and 2011 Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the 2010 and 2011 Indenture, plus any accrued and unpaid interest to the date of redemption.
In order to reduce our overall interest expense and lengthen the overall maturity of our senior indebtedness, on March 4, 2014, we announced a tender offer for up to an aggregate principal amount of $300 million of our 2010 and 2011 Senior Notes, to be funded by proceeds from the issuance of our 2014 Senior Notes, which is further described below. The tender offer for our 2010 and 2011 Senior Notes expired on March 31, 2014, at which time we had received valid tenders with respect to approximately $99.5 million of the $425 million aggregate principal amount of 2010 and 2011 Senior Notes outstanding. The holders of the $99.5 million of 2010 and 2011 Senior Notes tendered received the total consideration of $1,055.08 for each $1,000 principal amount, the premium portion of which totaled approximately $5.5 million, which was recorded as loss on debt extinguishment during the three months ended March 31, 2014. Additionally, we wrote off $1.2 million related to the net unamortized discount and $1.2 million of unamortized debt costs associated with the $99.5 million of notes tendered, for a total loss on extinguishment of $7.9 million.
The 2010 and 2011 Senior Notes are reflected on our condensed consolidated balance sheet at March 31, 2014 with a total carrying value of $321.6 million, which represents the $325.5 million total face value outstanding net of the $4.9 million unamortized portion of original issue discount and $0.9 million unamortized portion of original issue premium. The original issue discount and premium are being amortized over the term of the 2010 and 2011 Senior Notes based on the effective interest method.
On April 1, 2014, we announced that we will redeem $200.5 million in aggregate principal amount of the 2010 and 2011 Senior Notes (the "Redemption") on May 1, 2014 (the "Redemption Date") at a redemption price equal to 104.938% of the principal amount thereof, plus accrued and unpaid interest on the notes redeemed to, but not including, the Redemption Date. The redemption of these notes will be primarily funded by the remaining net proceeds from the issuance of our 2014 Senior Notes described below, and through cash on hand, for which the total redemption amount of $210.4 million has been classified as restricted cash on our condensed consolidated balance sheet. Upon redemption, we will recognize a loss on debt extinguishment of approximately $14.6 million for the redemption premium, net unamortized discount and unamortized debt issuance costs associated with the Redemption.
On March 18, 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. On March 18, 2014, we received $293.9 million of net proceeds from the issuance of the 2014 Senior Notes after deductions were made for the $6.1 million for underwriters’ fees and other debt offering costs. The net proceeds were partially used to fund the tender of $99.5 million of aggregate principal amount of 2010 and 2011 Senior Notes in March 2014. We intend to use the remaining net proceeds to fund a portion of the Redemption on the Redemption Date.

10




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 commencing on September 15, 2014. 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 “2014 Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the 2014 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.
If we experience a change of control (as defined in the 2010 and 2011 Indenture and the 2014 Indenture (collectively, the "Indentures")), we will be required to make an offer to each holder of the 2010 Senior Notes, 2011 Senior Notes and 2014 Senior Notes (collectively, 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 Indentures, among other things, limit our ability and the ability of certain of our subsidiaries 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.
We were in compliance with these covenants as of March 31, 2014. 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. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC was added as a subsidiary guarantor under the 2010 and 2011 Indenture. (See Note 8, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)
Other Debt
Our other debt consists of a short-term financing of insurance premiums with monthly payments due through August 2014 and a capital lease obligation for equipment with monthly payments due through November 2016.
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 June 2016. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates the use of the interest method) over the term of the Senior Notes which mature in March 2018 and 2022.

11




Capitalized debt costs related to the issuance of our long-term debt were $11.8 million and $7.5 million as of March 31, 2014 and December 31, 2013, respectively. We recognized $0.6 million and $0.5 million of associated amortization during the three months ended March 31, 2014 and 2013, respectively, which excludes the $1.2 million of debt costs recognized as loss on extinguishment of debt in March 2014.
3.
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 March 31, 2014 and December 31, 2013, our financial instruments consist primarily of cash, restricted cash, trade receivables, trade payables, and long-term debt. The carrying value of cash, restricted 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 March 31, 2014 and December 31, 2013 (amounts in thousands):
 
March 31, 2014
 
December 31, 2013
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
703,299

 
$
709,653

 
$
502,513

 
$
538,074

4.
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 March 31,
 
2014
 
2013
Basic
 
 
 
Net loss
$
(2,579
)
 
$
(1,292
)
Weighted-average shares
62,542

 
61,967

Loss per share
$
(0.04
)
 
$
(0.02
)
Diluted
 
 
 
Net loss
$
(2,579
)
 
$
(1,292
)
Weighted average shares:
 
 
 
Outstanding
62,542

 
61,967

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

 

 
62,542

 
61,967

Loss per share
$
(0.04
)
 
$
(0.02
)
Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 4,146,460 and 5,468,628 shares of common stock for the three months ended March 31, 2014 and 2013, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.

12




5.
Equity Transactions and Stock-Based Compensation Plans
Equity Transactions
In May 2012, 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 March 31, 2014, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity 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.
The following table summarizes the compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the three months ended March 31, 2014 and 2013 (amounts in thousands):
 
Three months ended March 31,
 
2014
 
2013
Stock option awards
$
343

 
$
526

Restricted stock awards
153

 
133

Restricted stock unit awards
1,360

 
853

 
$
1,856

 
$
1,512

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. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the three months ended March 31, 2014 and 2013:
 
Three months ended March 31,
 
2014
 
2013
Expected volatility
66
%
 
66
%
Risk-free interest rates
1.7
%
 
1.0
%
Expected life in years
5.49

 
5.53

Options granted
221,440
 
220,656
Grant-date fair value
$4.87
 
$4.36

13




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 months ended March 31, 2014 and 2013, 46,900 and 58,367 stock options were exercised at a weighted-average exercise price of $5.90 and $5.05, 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. We did not grant any restricted stock awards during the three months ended March 31, 2014 or 2013.
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.
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 March 31, 2014 and 2013:
 
Three months ended March 31,
 
2014
 
2013
Time-based RSUs:
 
 
 
Time-based RSUs granted
347,335

 
153,278

Weighted-average grant-date fair value
$
8.44

 
$
7.66

 
 
 
 
Performance-based RSUs:
 
 
 
Performance-based RSUs granted
321,606

 
50,858

Weighted-average grant-date fair value
$
9.90

 
$
8.34

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 2011, 2012 and 2013, and half of the performance-based RSUs granted during 2014, are subject to a market condition based on total shareholder return, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for

14




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, if any. The remaining performance-based RSUs are subject to performance conditions, based on EBITDA and return on capital employed, 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 2014, we determined that 116.6% of the target number of shares granted during 2011 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, 2011 through December 31, 2013. The performance-based RSUs granted during 2011 will vest and convert to common stock at the end of April 2014.
As of March 31, 2014, we estimated that our actual achievement level for the performance-based RSUs granted during 2012, 2013 and 2014 will be approximately 110%, 100% and 100% of the predetermined performance conditions, respectively.
6.
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.
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
Rig Count
South Texas
14

West Texas
18

North Dakota
11

Utah
7

Appalachia
4

Colombia
8

 
62

Production Services SegmentOur Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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 March 31, 2014, we have a fleet of 109 well servicing rigs consisting of ninety-nine 550 horsepower rigs and ten 600 horsepower rigs. We provide wireline services and coiled tubing services with a fleet of 120 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $17.4 million in fishing and rental tools.
The following tables set forth certain financial information for our two operating segments and corporate as of and for the three months ended March 31, 2014 and 2013 (amounts in thousands):
 
As of and for the three months ended March 31, 2014
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
780,786

 
$
403,923

 
$
241,668

 
$
1,426,377

Revenues
$
117,957

 
$
121,077

 
$

 
$
239,034

Operating costs
76,338

 
77,752

 

 
154,090

Segment margin
$
41,619

 
$
43,325

 
$

 
$
84,944

Depreciation and amortization
$
29,239

 
$
16,019

 
$
268

 
$
45,526

Capital expenditures
$
21,256

 
$
15,343

 
$
318

 
$
36,917


15




 
As of and for the three months ended March 31, 2013
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
870,291

 
$
430,829

 
$
23,137

 
$
1,324,257

Revenues
$
133,074

 
$
96,596

 
$

 
$
229,670

Operating costs
88,986

 
60,619

 

 
149,605

Segment margin
$
44,088

 
$
35,977

 
$

 
$
80,065

Depreciation and amortization
$
30,046

 
$
15,987

 
$
252

 
$
46,285

Capital expenditures
$
27,796

 
$
13,873

 
$
381

 
$
42,050

The following table reconciles the segment profits reported above to income from operations as reported on the consolidated statements of operations for the three months ended March 31, 2014 and 2013 (amounts in thousands):
 
Three months ended March 31,
 
2014
 
2013
Segment margin
$
84,944

 
$
80,065

Depreciation and amortization
(45,526
)
 
(46,285
)
General and administrative
(24,483
)
 
(23,054
)
Bad debt recovery (expense)
124

 
(281
)
Income from operations
$
15,059

 
$
10,445

The following table sets forth certain financial information for our international operations in Colombia as of and for the three months ended March 31, 2014 and 2013 (amounts in thousands):
 
As of and for the three months ended March 31,
 
2014
 
2013
Identifiable assets
$
153,158

 
$
151,498

Revenues
$
22,164

 
$
30,775

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.
7.
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 $40.4 million relating to our performance under these bonds as of March 31, 2014.
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.

16




8.
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, and certain of our future domestic subsidiaries. Effective October 1, 2012, the 2010 and 2011 Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC as a subsidiary guarantor. 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 March 31, 2014, 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.

17




CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands)
 
March 31, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
10,554

 
(4,237
)
 
14,493

 

 
$
20,810

Restricted cash
210,401

 

 

 

 
210,401

Receivables, net of allowance
881

 
143,967

 
40,070

 
(2,186
)
 
182,732

Intercompany receivable (payable)
(24,837
)
 
52,889

 
(28,052
)
 

 

Deferred income taxes
3,323

 
7,008

 
1,238

 

 
11,569

Inventory

 
8,016

 
5,734

 

 
13,750

Prepaid expenses and other current assets
816

 
4,923

 
871

 

 
6,610

Total current assets
201,138

 
212,566

 
34,354

 
(2,186
)
 
445,872

Net property and equipment
4,580

 
832,094

 
91,005

 
(750
)
 
926,929

Investment in subsidiaries
923,552

 
121,187

 

 
(1,044,739
)
 

Intangible assets, net of accumulated amortization
75

 
30,197

 

 

 
30,272

Noncurrent deferred income taxes
85,295

 

 
4,020

 
(85,295
)
 
4,020

Other long-term assets
11,983

 
1,853

 
5,448

 

 
19,284

Total assets
$
1,226,623

 
$
1,197,897

 
$
134,827

 
$
(1,132,970
)
 
$
1,426,377

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,198

 
$
47,517

 
$
5,254

 

 
$
53,969

Current portion of long-term debt
200,528

 
1,638

 

 

 
202,166

Deferred revenues

 
2,159

 

 

 
2,159

Accrued expenses
4,953

 
47,269

 
8,058

 
(2,186
)
 
58,094

Total current liabilities
206,679

 
98,583

 
13,312

 
(2,186
)
 
316,388

Long-term debt, less current portion
501,060

 
73

 

 

 
501,133

Noncurrent deferred income taxes

 
169,891

 

 
(85,295
)
 
84,596

Other long-term liabilities
580

 
5,798

 
328

 

 
6,706

Total liabilities
708,319

 
274,345

 
13,640

 
(87,481
)
 
908,823

Total shareholders’ equity
518,304

 
923,552

 
121,187

 
(1,045,489
)
 
517,554

Total liabilities and shareholders’ equity
$
1,226,623

 
$
1,197,897

 
$
134,827

 
$
(1,132,970
)
 
$
1,426,377

 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
28,368

 
$
(2,059
)
 
$
1,076

 
$

 
$
27,385

Receivables, net of allowance
905

 
125,979

 
49,476

 

 
176,360

Intercompany receivable (payable)
(24,837
)
 
52,671

 
(27,834
)
 

 

Deferred income taxes
1,143

 
8,005

 
3,944

 

 
13,092

Inventory

 
7,415

 
5,817

 

 
13,232

Prepaid expenses and other current assets
1,013

 
7,094

 
1,204

 

 
9,311

Total current assets
6,592

 
199,105

 
33,683

 

 
239,380

Net property and equipment
4,531

 
846,632

 
87,244

 
(750
)
 
937,657

Investment in subsidiaries
939,091

 
120,630

 

 
(1,059,721
)
 

Intangible assets, net of accumulated amortization
75

 
32,194

 

 

 
32,269

Noncurrent deferred income taxes
78,486

 

 
1,156

 
(78,486
)
 
1,156

Other long-term assets
7,513

 
2,009

 
9,639

 

 
19,161

Total assets
$
1,036,288

 
$
1,200,570

 
$
131,722

 
$
(1,138,957
)
 
$
1,229,623

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
757

 
$
37,797

 
$
5,164

 
$

 
$
43,718

Current portion of long-term debt

 
2,847

 

 

 
2,847

Deferred revenues

 
699

 

 

 
699

Accrued expenses
16,368

 
51,739

 
5,462

 

 
73,569

Total current liabilities
17,125

 
93,082

 
10,626

 

 
120,833

Long-term debt, less current portion
499,586

 
80

 

 

 
499,666

Noncurrent deferred income taxes

 
163,122

 

 
(78,486
)
 
84,636

Other long-term liabilities
394

 
5,195

 
466

 

 
6,055

Total liabilities
517,105

 
261,479

 
11,092

 
(78,486
)
 
711,190

Total shareholders’ equity
519,183

 
939,091

 
120,630

 
(1,060,471
)
 
518,433

Total liabilities and shareholders’ equity
$
1,036,288

 
$
1,200,570

 
$
131,722

 
$
(1,138,957
)
 
$
1,229,623


18




CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)

 
Three months ended March 31, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
216,870

 
$
22,164

 
$

 
$
239,034

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
139,487

 
14,603

 

 
154,090

Depreciation and amortization
269

 
41,864

 
3,393

 

 
45,526

General and administrative
6,735

 
17,198

 
688

 
(138
)
 
24,483

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense (recovery)

 
(124
)
 

 

 
(124
)
Total costs and expenses
7,004

 
197,210

 
19,899

 
(138
)
 
223,975

Income (loss) from operations
(7,004
)
 
19,660

 
2,265

 
138

 
15,059

Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
12,885

 
575

 

 
(13,460
)
 

Interest expense
(12,399
)
 
7

 
4

 

 
(12,388
)
Loss on extinguishment of debt
(7,887
)
 

 

 

 
(7,887
)
Other
2,879

 
671

 
(738
)
 
(138
)
 
2,674

Total other (expense) income
(4,522
)
 
1,253

 
(734
)
 
(13,598
)
 
(17,601
)
Income (loss) before income taxes
(11,526
)
 
20,913

 
1,531

 
(13,460
)
 
(2,542
)
Income tax (expense) benefit
8,947

 
(8,028
)
 
(956
)
 

 
(37
)
Net income (loss)
$
(2,579
)
 
$
12,885

 
$
575

 
$
(13,460
)
 
$
(2,579
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
198,895

 
$
30,775

 
$

 
$
229,670

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
129,216

 
20,389

 

 
149,605

Depreciation and amortization
252

 
42,702

 
3,331

 

 
46,285

General and administrative
5,426

 
16,978

 
788

 
(138
)
 
23,054

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt expense (recovery)

 
281

 

 

 
281

Total costs and expenses
5,678

 
187,962

 
25,723

 
(138
)
 
219,225

Income (loss) from operations
(5,678
)
 
10,933

 
5,052

 
138

 
10,445

Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
9,189

 
2,342

 

 
(11,531
)
 

Interest expense
(11,449
)
 
(20
)
 
7

 

 
(11,462
)
Other
1

 
283

 
(967
)
 
(138
)
 
(821
)
Total other (expense) income
(2,259
)
 
2,605

 
(960
)
 
(11,669
)
 
(12,283
)
Income (loss) before income taxes
(7,937
)
 
13,538

 
4,092

 
(11,531
)
 
(1,838
)
Income tax (expense) benefit
6,645

 
(4,349
)
 
(1,750
)
 

 
546

Net income (loss)
$
(1,292
)
 
$
9,189

 
$
2,342

 
$
(11,531
)
 
$
(1,292
)
 
 
 
 
 
 
 
 
 
 

19




CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 
Three months ended March 31, 2014
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
Cash flows from operating activities
$
4,044

 
$
16,734

 
$
20,457

 
$
41,235

Cash flows from investing activities:
 
 
 
 
 
 
 
Purchases of property and equipment
(212
)
 
(24,300
)
 
(7,162
)
 
(31,674
)
Proceeds from sale of property and equipment

 
5,394

 
122

 
5,516

 
(212
)
 
(18,906
)
 
(7,040
)
 
(26,158
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Debt repayments
(119,472
)
 
(6
)
 

 
(119,478
)
Proceeds from issuance of debt
320,000

 

 

 
320,000

Debt issuance costs
(6,138
)
 

 

 
(6,138
)
Change in restricted cash
(210,401
)
 

 

 
(210,401
)
Tender premium costs
(5,479
)
 

 

 
(5,479
)
Proceeds from exercise of options
277

 

 

 
277

Purchase of treasury stock
(433
)
 

 

 
(433
)
 
(21,646
)
 
(6
)
 

 
(21,652
)
Net increase (decrease) in cash and cash equivalents
(17,814
)
 
(2,178
)
 
13,417

 
(6,575
)
Beginning cash and cash equivalents
28,368

 
(2,059
)
 
1,076

 
27,385

Ending cash and cash equivalents
$
10,554

 
$
(4,237
)
 
$
14,493

 
$
20,810

 
 
 
 
 
 
 
 
 
Three months ended March 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
Cash flows from operating activities
$
(48,340
)
 
$
68,190

 
$
(2,693
)
 
$
17,157

Cash flows from investing activities:
 
 
 
 
 
 
 
Purchases of property and equipment
(816
)
 
(66,164
)
 
(4,333
)
 
(71,313
)
Proceeds from sale of property and equipment

 
904

 
663

 
1,567

 
(816
)
 
(65,260
)
 
(3,670
)
 
(69,746
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Debt repayments

 
(656
)
 

 
(656
)
Proceeds from issuance of debt
40,000

 

 

 
40,000

Proceeds from exercise of options
295

 

 

 
295

Purchase of treasury stock
(275
)
 

 

 
(275
)
 
40,020

 
(656
)
 

 
39,364

Net increase (decrease) in cash and cash equivalents
(9,136
)
 
2,274

 
(6,363
)
 
(13,225
)
Beginning cash and cash equivalents
18,479

 
(5,401
)
 
10,655

 
23,733

Ending cash and cash equivalents
$
9,343

 
$
(3,127
)
 
$
4,292

 
$
10,508

 
 

20




Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, levels and volatility of oil and gas prices, decisions about exploration and development projects to be made by oil and gas exploration and production companies, economic cycles and their impact on capital markets and liquidity, the continued demand for drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, changes in technology and improvements in our competitors' equipment, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2013, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our Annual Report on Form 10-K for the year ended December 31, 2013 could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.
Company Overview
Pioneer Energy Services (formerly called "Pioneer Drilling Company") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil, L.L.C. ("Go-Coil") to expand our existing production services offerings.
Pioneer Energy Services 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 coiled tubing and wireline services offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our clients.

21




Business Segments
We currently conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 6, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

West Texas
 
18

North Dakota
 
11

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
62

As of March 31, 2014, 54 of our 62 drilling rigs are earning revenues under drilling contracts, 43 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, six of which are currently earning revenues with the remaining two rigs expected to be operating by early May 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. 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, turnkey or footage 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.
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental 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. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of March 31, 2014, we operate ninety-nine 550 horsepower rigs and ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and ArkLaTex regions, though we also have 14 rigs in North Dakota.
Wireline Services. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. To complete a well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. As of March 31, 2014, we operate a fleet of 120 wireline units through 24 locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.

22




Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of March 31, 2014, our coiled tubing business consists of nine onshore and four offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.
Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of three locations in Texas and Oklahoma. As of March 31, 2014 our fishing and rental tools have a gross book value of $17.4 million.

Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge though our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report or otherwise made part of this report.
Market Conditions in Our Industry
Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected oil and natural gas prices.
With generally increasing oil prices in 2010 and 2011, exploration and production companies increased their exploration and production spending and industry equipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. During 2012, modest increases in exploration and production spending resulted in modest increases in industry equipment utilization and revenue rates during 2012, as compared to 2011. Despite generally increasing oil prices during 2013 and 2014, industry equipment utilization levels have been slightly lower than industry levels during 2012 and 2011, partially due to the advancements in technology and efficiency of drilling rigs. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Historically, Colombian oil prices have generally trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon the national oil company's long-term exploration and production programs.

23




The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last five years are illustrated in the graphs below.


As shown in the charts above, the trends in industry rig counts are influenced by fluctuations in oil and natural gas prices, which affect the levels of capital and operating expenditures made by our clients.
Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure.
Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.
In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated according to a simple short-term payout criterion that is far less dependent on commodity price forecasts.
Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.

24




For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2013.
Strategy
In past years, our strategy was to become a premier land drilling and production services company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production services business which we operate in the most attractive drilling markets throughout the United States and in Colombia. Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services company, continue to expand our relationships with existing clients, expand our client base in the areas where we currently operate and further enhance our geographic diversification through selective expansion. The key elements of this long-term strategy are focused on our:
Competitive Position in the Most Attractive Domestic Markets. Shale plays and non-shale oil or liquid rich environments are increasingly important to domestic hydrocarbon production and not all drilling rigs are capable of successfully drilling in these unconventional opportunities. We are currently operating in unconventional areas in the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins. All of the ten drilling rigs we recently constructed are currently operating in domestic shale and unconventional plays. Additionally, in recent years, we have added significant capacity to our production services fleets, which we believe are well positioned to capitalize on increased shale development.
Exposure to Oil and Liquids Rich Natural Gas Drilling Activity. We believe that our flexible drilling and production services fleets allow us to pursue varied opportunities, enabling us to focus on a favorable mix of natural gas, oil and liquids rich natural gas activity. In recent years, we have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and we continue to actively seek contracts with oil-focused producers. As of March 31, 2014, approximately 98% of our working drilling rigs and 79% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas.
International Presence. In 2007, we began operating in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, six of which are currently earning revenues with the remaining two rigs expected to be operating by early May 2014.
Growth Through Select Capital Deployment. We have historically invested in the growth of our business by strategically upgrading our existing assets, selectively engaging in new-build opportunities, and through selective acquisitions. We have continued to make significant investments in the growth of our business over the past several years. For example, on December 31, 2011, we acquired a coiled tubing services business to expand our existing production services offerings. We have also added significant capacity to our other production services fleets through the addition of 57 wireline units and 35 well servicing rigs since the beginning of 2010. In 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays.
With these capital projects recently completed, we have shifted our near-term focus toward reducing capital expenditures and using excess cash flows from operations to reduce outstanding debt balances. Management efforts are currently focused on stringent cost control measures, the evaluation of nonstrategic or under-performing assets for potential liquidation and continued emphasis on the execution and performance of our core businesses. We are also currently planning for some organic growth through select fleet additions, but this growth will be balanced with our plans for continued debt reduction. We believe this near-term strategy will position us to take advantage of future business opportunities and continue our long-term growth strategy.

25




Liquidity and Capital Resources
Sources of Capital Resources
Our principal liquidity requirements have been for working capital needs, debt service, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $20.8 million as of March 31, 2014), cash generated from operations and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).
In May 2012, 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 March 31, 2014, 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.
On March 11, 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that are due in 2018 (the "2010 Senior Notes"). We received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes that were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. On November 21, 2011, we issued an additional $175 million of senior notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition of our coiled tubing business in December 2011.
On March 18, 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. On March 18, 2014, we received $293.9 million of net proceeds from the issuance of the 2014 Senior Notes after deductions were made for the $6.1 million for underwriters’ fees and other debt offering costs. The net proceeds were partially used to fund the tender of $99.5 million of aggregate principal amount of 2010 and 2011 Senior Notes in March 2014. We intend to use the remaining net proceeds to fund a portion of the redemption of $200.5 million of 2010 and 2011 Senior Notes on May 1, 2014. The $210.4 million of funds which are committed for the redemption, including the redemption premium, are classified as restricted cash on our condensed consolidated balance sheet at March 31, 2014.
Our Revolving Credit Facility 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 $250 million, all of which matures on June 30, 2016. As of March 31, 2014, we had $80.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $156.0 million under our Revolving Credit Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.
We currently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.
Uses of Capital Resources
During the three months ended March 31, 2014, we spent $31.7 million on purchases of property and equipment and placed into service property and equipment of $36.9 million. Currently, we expect to spend approximately $135 million to $145 million on capital expenditures during 2014. We expect the total capital expenditures for 2014 will be allocated approximately 50% for our Drilling Services Segment and approximately 50% for our Production Services Segment. Our planned capital expenditures for the year ending December 31, 2014 include nine well servicing rigs, three coiled tubing units, three wireline units, upgrades to certain drilling rigs and routine capital expenditures. Actual capital expenditures may vary depending on the timing of commitments and payments, as well as the level of new-build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the remaining capital expenditures in 2014 from operating cash flow in excess of our working capital requirements.

26




Working Capital
Our working capital was $129.5 million at March 31, 2014, compared to $118.5 million at December 31, 2013. Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.4 at March 31, 2014 compared to 2.0 at December 31, 2013, due to the increase in restricted cash and current debt obligations associated with the redemption of Senior Notes which will be redeemed on May 1, 2014.
Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements could increase during periods when higher percentages of our drilling contracts are turnkey and footage contracts and when new-build rig construction projects are in progress.
With the completion of our new-build drilling rig program in the first quarter of 2013, we shifted our near-term focus toward reducing capital expenditures and using excess cash flows from operations to reduce outstanding debt balances.
The changes in the components of our working capital were as follows (amounts in thousands):
 
March 31,
2014
 
December 31,
2013
 
Change
Cash and cash equivalents
$
20,810

 
$
27,385

 
$
(6,575
)
Restricted cash
210,401

 

 
210,401

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
121,790

 
115,908

 
5,882

Unbilled receivables
44,792

 
49,535

 
(4,743
)
Insurance recoveries
9,657

 
8,607

 
1,050

Income taxes and other
6,493

 
2,310

 
4,183

Deferred income taxes
11,569

 
13,092

 
(1,523
)
Inventory
13,750

 
13,232

 
518

Prepaid expenses and other current assets
6,610

 
9,311

 
(2,701
)
Current assets
445,872

 
239,380

 
206,492

Accounts payable
53,969

 
43,718

 
10,251

Current portion of long-term debt
202,166

 
2,847

 
199,319

Deferred revenues
2,159

 
699

 
1,460

Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
24,586

 
30,020

 
(5,434
)
Insurance premiums and deductibles
10,896

 
10,940

 
(44
)
Insurance claims and settlements
9,657

 
8,607

 
1,050

Interest
2,057

 
12,275

 
(10,218
)
Other
10,898

 
11,727

 
(829
)
Current liabilities
316,388

 
120,833

 
195,555

Working capital
$
129,484

 
$
118,547

 
$
10,937

The decrease in cash and cash equivalents during the three months ended March 31, 2014 is primarily due to $31.7 million used for purchases of property and equipment and $21.7 million of cash used in our financing activities, which were mostly offset by $41.2 million of cash provided by operating activities and $5.5 million of proceeds from the sale of assets.
On April 1, 2014, we announced that we will redeem $200.5 million in aggregate principal amount of the 2010 and 2011 Senior Notes on May 1, 2014 at a redemption price equal to 104.938% of the principal amount thereof, plus accrued and unpaid interest. The redemption of these notes will be primarily funded by the remaining net proceeds from the issuance of our 2014 Senior Notes described below, and through cash on hand, for which the total redemption amount has been classified as restricted cash on our condensed consolidated balance sheet.

27




The net increase in our total trade and unbilled receivables as of March 31, 2014 as compared to December 31, 2013 is primarily due to the timing of billing and collection cycles and partially due to the increase in our Production Services Segment revenues for the quarter ended March 31, 2014 as compared to the quarter ended December 31, 2013.
The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of March 31, 2014 as compared to December 31, 2013 is primarily due to an increase in our insurance company's reserve for workers compensation claims in excess of our deductibles.
The increase in income taxes and other receivables as of March 31, 2014 as compared to December 31, 2013 is primarily due to the movement of prepaid taxes associated with our Colombian operations from noncurrent to current receivables, as we expect to utilize them in the near term.
The decrease in current deferred income taxes as of March 31, 2014 as compared to December 31, 2013 is primarily due to a movement of net operating losses for our Colombian operations to noncurrent deferred tax assets as we currently expect to utilize prepaid taxes rather than net operating losses to offset income taxes payable within the next year, as well as a decrease in current deferred income tax assets for 2013 annual bonuses accruals which were paid in the first quarter of 2014. The overall decrease in current deferred income taxes was partially offset by a movement of domestic net operating losses from noncurrent to current deferred tax assets, as we expect to realize them in the near term.
The decrease in prepaid expenses and other assets as of March 31, 2014 as compared to December 31, 2013 is primarily due to a decrease in prepaid insurance costs because most of the insurance premiums are paid in late October of each year, and therefore we had amortization of five months of these October premiums at March 31, 2014, as compared to two months at December 31, 2013.
The increase in accounts payable as of March 31, 2014 as compared to December 31, 2013 is primarily due to a $5.2 million increase in our accruals for capital expenditures as of March 31, 2014 as compared to December 31, 2013.
The current portion of our long-term debt primarily represents the aggregate principal amount of our 2010 and 2011 Senior Notes which will be redeemed on May 1, 2014.
The increase in deferred revenues as of March 31, 2014 as compared to December 31, 2013 is primarily related to revenues collected but not yet earned for two turnkey jobs which were in progress at March 31, 2014.
The decrease in accrued payroll and employee related costs as of March 31, 2014 as compared to December 31, 2013 is primarily due to the payment of our 2013 annual bonuses in February 2014, which were fully accrued for as of December 31, 2013.
The decrease in accrued interest expense as of March 31, 2014 as compared to December 31, 2013 is primarily due to the payment of interest on our Senior Notes which is due semi-annually on March 15 and September 15.
The decrease in other accrued expenses as of March 31, 2014 as compared to December 31, 2013 is primarily due to the timing of payments for property taxes, which was partially offset by an increase in our sales tax accrual.

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Long-term Debt and Other Contractual Obligations
The following table includes information about the amount and timing of our contractual obligations at March 31, 2014 (amounts in thousands):
 
Payments Due by Period
Contractual Obligations
Total
 
Within 1 Year
 
2 to 3 Years
 
4 to 5 Years
 
Beyond 5 Years
Debt
$
707,239

 
$
202,166

 
$
80,073

 
$
125,000

 
$
300,000