10-Q 1 a201310qq1.htm 10-Q 2013 10Q Q1

 
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, 2013
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: (210) 828-7689
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, 2013, there were 62,174,580 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,
2013
 
December 31,
2012
 
(Unaudited)
 
(Audited)
 
(In thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
10,508

 
$
23,733

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
111,316

 
116,352

Unbilled receivables
44,950

 
35,140

Insurance recoveries
9,321

 
6,518

Income taxes
200

 
834

Deferred income taxes
12,387

 
11,058

Inventory
12,337

 
12,111

Prepaid expenses and other current assets
9,400

 
13,040

Total current assets
210,419

 
218,786

Property and equipment, at cost
1,728,995

 
1,698,517

Less accumulated depreciation
717,956

 
684,177

Net property and equipment
1,011,039

 
1,014,340

Intangible assets, net of accumulated amortization of $26.5 million
and $24.4 million at March 31, 2013 and December 31, 2012, respectively
41,667

 
43,843

Goodwill
41,683

 
41,683

Noncurrent deferred income taxes
1,740

 
5,519

Other long-term assets
17,709

 
15,605

Total assets
$
1,324,257

 
$
1,339,776

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
47,847

 
$
83,823

Current portion of long-term debt
222

 
872

Deferred revenues
2,217

 
3,880

Accrued expenses:
 
 
 
Payroll and related employee costs
22,380

 
27,991

Insurance premiums and deductibles
10,979

 
9,708

Insurance claims and settlements
9,321

 
6,348

Interest
1,899

 
12,343

Other
8,505

 
11,585

Total current liabilities
103,370

 
156,550

Long-term debt, less current portion
558,949

 
518,725

Noncurrent deferred income taxes
105,145

 
108,838

Other long-term liabilities
8,936

 
7,983

Total liabilities
776,400

 
792,096

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;
62,173,233 and 62,032,517 shares outstanding at
March 31, 2013 and December 31, 2012, respectively
6,234

 
6,217

Additional paid-in capital
451,281

 
449,554

Treasury stock, at cost; 171,159 and 134,612 shares at
March 31, 2013 and December 31, 2012, respectively
(1,539
)
 
(1,264
)
Accumulated earnings
91,881

 
93,173

Total shareholders’ equity
547,857

 
547,680

Total liabilities and shareholders’ equity
$
1,324,257

 
$
1,339,776

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,
 
2013
 
2012
 
(In thousands, except per share data)
Revenues:
 
 
 
Drilling services
$
133,074

 
$
124,304

Production services
96,596

 
107,674

Total revenues
229,670

 
231,978

Costs and expenses:
 
 
 
Drilling services
88,986

 
81,077

Production services
60,465

 
60,696

Depreciation and amortization
46,285

 
38,373

General and administrative
23,208

 
21,143

Bad debt expense (recovery)
281

 
(91
)
Impairment of equipment

 
1,032

Total costs and expenses
219,225

 
202,230

Income from operations
10,445

 
29,748

Other (expense) income:
 
 
 
Interest expense
(11,462
)
 
(9,555
)
Other
(821
)
 
932

Total other expense
(12,283
)
 
(8,623
)
(Loss) income before income taxes
(1,838
)
 
21,125

Income tax benefit (expense)
546

 
(6,953
)
Net (loss) income
$
(1,292
)
 
$
14,172

 
 
 
 
(Loss) income per common share—Basic
$
(0.02
)
 
$
0.23

 
 
 
 
(Loss) income per common share—Diluted
$
(0.02
)
 
$
0.23

 
 
 
 
Weighted average number of shares outstanding—Basic
61,967

 
61,578

 
 
 
 
Weighted average number of shares outstanding—Diluted
61,967

 
62,647


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,
 
2013
 
2012
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net (loss) income
$
(1,292
)
 
$
14,172

Adjustments to reconcile net (loss) income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
46,285

 
38,373

Allowance for doubtful accounts
281

 
(94
)
Gain on dispositions of property and equipment
(321
)
 
(733
)
Stock-based compensation expense
1,512

 
2,000

Amortization of debt issuance costs, discount and premium
762

 
732

Impairment of equipment

 
1,032

Deferred income taxes
(1,287
)
 
5,846

Change in other long-term assets
(2,658
)
 
720

Change in other long-term liabilities
953

 
219

Changes in current assets and liabilities:
 
 
 
Receivables
(4,252
)
 
(17,320
)
Inventory
(226
)
 
(1,036
)
Prepaid expenses and other current assets
3,640

 
(644
)
Accounts payable
(6,713
)
 
1,407

Deferred revenues
(1,663
)
 
767

Accrued expenses
(17,864
)
 
(15,789
)
Net cash provided by operating activities
17,157

 
29,652

 
 
 
 
Cash flows from investing activities:
 
 
 
Purchases of property and equipment
(71,313
)
 
(95,109
)
Proceeds from sale of property and equipment
1,567

 
1,357

Net cash used in investing activities
(69,746
)
 
(93,752
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
(656
)
 
(656
)
Proceeds from issuance of debt
40,000

 

Proceeds from exercise of options
295

 
253

Purchase of treasury stock
(275
)
 
(293
)
Net cash provided by (used in) financing activities
39,364

 
(696
)
 
 
 
 
Net decrease in cash and cash equivalents
(13,225
)
 
(64,796
)
Beginning cash and cash equivalents
23,733

 
86,197

Ending cash and cash equivalents
$
10,508

 
$
21,401

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
21,956

 
$
21,343

Income tax paid (refunded)
$
320

 
$
(1,074
)
 
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 and Principles of Consolidation
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 71 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

East Texas
 
3

West Texas
 
23

North Dakota
 
12

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
71

In early 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays. We deployed seven of these new-build drilling rigs during 2012, and deployed the final three in early 2013. All of our new-build drilling rigs are currently operating in shale or unconventional plays under long-term drilling contracts. In April 2013, we sold one mechanical drilling rig that was previously idle in our East Texas division, for which we will recognize an associated gain of approximately $0.2 million.
As of April 15, 2013, 62 of our 71 drilling rigs are earning revenues under drilling contracts, 45 of which are under term contracts. Included in the 45 drilling rigs currently operating under term contracts are four rigs which our client early released due to the recent decrease in demand for vertical conventional drilling in West Texas. These four drilling rigs are under term contracts and therefore we are receiving a standby dayrate for the remainder of the contract term. All of our drilling rigs in Colombia are currently working, six of which are working under term contracts that were extended through the end of 2013. We are actively marketing all of our idle drilling rigs.
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 April 15, 2013, 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 119 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $16.7 million in fishing and rental tools.
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


5



of normal, recurring accruals) necessary for a fair presentation have been included. 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 expense, 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. The condensed consolidated balance sheet as of December 31, 2012 has been derived from our audited financial statements. We suggest that you read these condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2012.
In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after March 31, 2013, 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. Generally, our contracts 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 terms of six months to four years in duration. As of April 15, 2013, we have 45 drilling rigs currently operating 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
 
39

 
28

 
1

 
2

 
2

 
6

Colombia
 
6

 

 
6

 

 

 

 
 
45

 
28

 
7

 
2

 
2

 
6

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 $45.0 million at March 31, 2013, of which $0.1 million related to turnkey drilling contract revenues, $40.7 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at March 31, 2013 and $4.2 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 short-term portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.
Property and Equipment
As of March 31, 2013 and December 31, 2012, we had incurred $29.3 million and $134.9 million, respectively, in construction costs for ongoing projects, primarily for our new-build drilling rigs and additions to our production services fleets. During the three months ended March 31, 2013 and 2012, we capitalized $0.8 million and $2.0 million, respectively, of interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment.
In March 2012, we decided to retire two mechanical drilling rigs, with most of their components to be used as spare parts, as well as two wireline units and other wireline equipment, and recognized an associated impairment charge of $1.0 million. We


6



recorded gains on disposition of our property and equipment of $0.3 million and $0.7 million for the three months ended March 31, 2013 and 2012, respectively, in our drilling services costs and expenses.
Goodwill
Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We perform a qualitative assessment of goodwill annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment of goodwill.
If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.
When estimating fair values of a reporting unit for our goodwill impairment test, we use an income approach which provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on our weighted average cost of capital and estimated industry average rates for cost of capital. To ensure the reasonableness of the estimated fair value of our reporting units, we consider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units.
We have goodwill of $41.7 million as of March 31, 2013. All of this goodwill was recorded in connection with the acquisition of the production services business from Go-Coil on December 31, 2011. As a result, the goodwill has been allocated to the coiled tubing services reporting unit within our Production Services Segment. As of March 31, 2013, we performed the first step of the two-step process to evaluate our goodwill for potential impairment. As a result of this test, we have concluded that the fair value of our coiled tubing services reporting unit is in excess of its carrying value, including goodwill, and therefore no impairment loss on goodwill exists as of March 31, 2013.
However, the coiled tubing services reporting unit's estimated fair value exceeded its carrying value by a nominal amount, indicating that the reporting unit is at risk of a future impairment in the event of significant unfavorable changes in the forecasted cash flows or the key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in the discounted cash flow analysis. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. Should the coiled tubing services reporting unit not achieve its projected cash flows, its estimated fair value could fall below its carrying value, resulting in a non-cash impairment charge. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.
Other Long-Term Assets
Other long-term assets consist of cash deposits related to the deductibles on our workers’ compensation insurance policies, the long-term portion of deferred mobilization costs, debt issuance costs, net of amortization, and noncurrent prepaid taxes in Colombia which are creditable against future income taxes.
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of deferred mobilization revenues, liabilities associated with our long-term compensation plans, the noncurrent portion of the Colombia net equity tax and other deferred liabilities.


7



2.
Long-Term Debt
Long-term debt consists of the following (amounts in thousands):
 
March 31, 2013
 
December 31, 2012
Senior secured revolving credit facility
$
140,000

 
$
100,000

Senior notes
418,848

 
418,617

Other notes payable
323

 
980

 
559,171

 
519,597

Less current portion
(222
)
 
(872
)
 
$
558,949

 
$
518,725

Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on June 30, 2011, 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 in effect at April 15, 2013 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 (formerly Go-Coil, L.L.C.) was added as a subsidiary 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 April 15, 2013, we had $140.0 million outstanding under our Revolving Credit Facility and $8.9 million in committed letters of credit, which resulted in borrowing availability of $101.1 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, 2013, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.4 to 1.0, our senior consolidated leverage ratio was 0.6 to 1.0, and our interest coverage ratio was 6.3 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.


8



At March 31, 2013, 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.
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.
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 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 (the “Senior Notes”) are reflected on our condensed consolidated balance sheet at March 31, 2013 with a total carrying value of $418.8 million, which represents the $425.0 million total face value net of the $7.6 million unamortized portion of original issue discount and $1.4 million unamortized portion of original issue premium. The original issue discount and premium are being amortized over the term of the Senior Notes based on the effective interest method.
The 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 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 “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption.
Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.


9



The Indenture contains certain restrictions generally on our and certain of our subsidiaries’ ability to:
pay dividends on stock;
repurchase stock or redeem subordinated debt or make other restricted payments;
incur, assume or guarantee additional indebtedness or issue disqualified stock;
create liens on our assets;
enter into sale and leaseback transactions;
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 another person;
enter into transactions with affiliates; and
enter into new lines of business.
We were in compliance with these covenants as of March 31, 2013. 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 (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Indenture. (See Note 8, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)
Other Notes Payable
Our other debt consists of $0.2 million due in April 2013 for a note payable to an employee who was a former shareholder of a production services business which we acquired, and $0.1 million which represents 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.
Capitalized debt costs related to the issuance of our long-term debt were approximately $9.1 million and $9.6 million as of March 31, 2013 and December 31, 2012, respectively. We recognized approximately $0.5 million and $0.5 million of associated amortization during the three months ended March 31, 2013 and 2012, respectively.
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, 2013 and December 31, 2012, our financial instruments consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying value of cash, trade 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, 2013 and December 31, 2012 (amounts in thousands):
 
March 31, 2013
 
December 31, 2012
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
559,171

 
$
604,163

 
$
519,597

 
$
565,257



10



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,
 
2013
 
2012
Basic
 
 
 
Net income (loss)
$
(1,292
)
 
$
14,172

Weighted-average shares
61,967

 
61,578

Income (loss) per share
$
(0.02
)
 
$
0.23

Diluted
 
 
 
Net income (loss)
$
(1,292
)
 
$
14,172

Effect of dilutive securities

 

Net income (loss) available to common shareholders after assumed conversion
$
(1,292
)
 
$
14,172

Weighted average shares:
 
 
 
Outstanding
61,967

 
61,578

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

 
1,069

 
61,967

 
62,647

Income (loss) per share
$
(0.02
)
 
$
0.23

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 5,468,628 and 3,742,383 shares of common stock for the three months ended March 31, 2013 and 2012, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.
5.
Equity Transactions and Stock-Based Compensation Plans
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.
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 stock options granted during the three months ended March 31, 2013 and 2012:
 
 
Three months ended March 31,
 
2013
 
2012
Expected volatility
66
%
 
70
%
Risk-free interest rates
1.0
%
 
0.8
%
Expected life in years
5.53

 
5.31

Options granted
220,656
 
475,156
Grant-date fair value
$4.36
 
$5.21


11



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, 2013 and 2012, 58,367 and 68,100 stock options were exercised at a weighted-average exercise price of $5.05 and $3.72, 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.
The following table summarizes the compensation expense recognized for stock option awards during the three months ended March 31, 2013 and 2012 (amounts in thousands):
 
Three months ended March 31,
 
2013
 
2012
General and administrative expense
$
524

 
$
919

Operating costs
2

 
44

 
$
526

 
$
963

Restricted Stock
We grant 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. 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, 2013 and 2012.
The following table summarizes the compensation expense recognized for restricted stock awards during the three months ended March 31, 2013 and 2012 (amounts in thousands):
 
Three months ended March 31,
 
2013
 
2012
General and administrative expense
$
130

 
$
216

Operating costs
3

 
15

 
$
133

 
$
231

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.
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 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 following table summarizes the number and weighted-average grant-date fair value of the time-based RSUs granted during the three months ended March 31, 2013 and 2012:
 
Three months ended March 31,
 
2013
 
2012
Time-based RSUs granted
153,278

 
205,313

Weighted-average grant-date fair value
$
7.66

 
$
9.07



12



Our performance-based RSUs 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 following table summarizes the number and weighted-average grant-date fair value of performance-based RSUs granted during the three months ended March 31, 2013 and 2012:
 
Three months ended March 31,
 
2013
 
2012
Performance-based RSUs granted
50,858

 
221,495

Weighted-average grant-date fair value
$
8.34

 
$
9.85

Performance-based RSUs granted during 2013, 2012 and 2011 will cliff vest after 39 months from the date of grant. 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 three-year performance period. Approximately one-third of the performance-based RSUs are subject to a market condition, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any. The remaining two-thirds of the performance-based RSUs are subject to performance conditions, 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. As of March 31, 2013, we estimated that our actual achievement level for the performance-based RSUs granted during 2012 and 2011 will be approximately 150% of the predetermined performance conditions.
The following table summarizes the compensation expense recognized for restricted stock unit awards during the three months ended March 31, 2013 and 2012 (amounts in thousands):
 
Three months ended March 31,
 
2013
 
2012
General and administrative expense
$
754

 
$
658

Operating costs
99

 
148

 
$
853

 
$
806

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 71 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

East Texas
 
3

West Texas
 
23

North Dakota
 
12

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
71

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. We currently have a fleet of 109 well servicing rigs


13



consisting of ninety-nine 550 horsepower rigs and ten 600 horsepower rigs. We currently provide wireline services and coiled tubing services with a fleet of 119 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $16.7 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, 2013 and 2012 (amounts in thousands):
 
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

 
60,465

 

 
149,451

Segment margin
$
44,088

 
$
36,131

 
$

 
$
80,219

Depreciation and amortization
$
30,046

 
$
15,987

 
$
252

 
$
46,285

Capital expenditures
$
27,796

 
$
13,873

 
$
381

 
$
42,050

 
As of and for the three months ended March 31, 2012
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
745,072

 
$
418,934

 
$
35,078

 
$
1,199,084

Revenues
$
124,304

 
$
107,674

 
$

 
$
231,978

Operating costs
81,077

 
60,696

 

 
141,773

Segment margin
$
43,227

 
$
46,978

 
$

 
$
90,205

Depreciation and amortization
$
25,489

 
$
12,718

 
$
166

 
$
38,373

Capital expenditures
$
80,584

 
$
31,554

 
$
239

 
$
112,377

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, 2013 and 2012 (amounts in thousands):
 
Three months ended March 31,
 
2013
 
2012
Segment margin
$
80,219

 
$
90,205

Depreciation and amortization
(46,285
)
 
(38,373
)
General and administrative
(23,208
)
 
(21,143
)
Bad debt recovery (expense)
(281
)
 
91

Impairment of equipment

 
(1,032
)
Income from operations
$
10,445

 
$
29,748

The following table sets forth certain financial information for our international operations in Colombia as of and for the three months ended March 31, 2013 and 2012 (amounts in thousands):
 
As of and for the three months ended March 31,
 
2013
 
2012
Identifiable assets
$
151,498

 
$
152,854

Revenues
$
30,775

 
$
23,816

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.


14



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 $36.0 million relating to our performance under these bonds.
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.
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 Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) 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, 2013, 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.



15




CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands)
 
March 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
9,343

 
$
(3,127
)
 
$
4,292

 
$

 
$
10,508

Receivables, net of allowance
435

 
125,799

 
39,961

 
(408
)
 
165,787

Intercompany receivable (payable)
(123,417
)
 
149,756

 
(26,339
)
 

 

Deferred income taxes
571

 
7,151

 
4,665

 

 
12,387

Inventory

 
6,074

 
6,263

 

 
12,337

Prepaid expenses and other current assets
497

 
7,333

 
1,570

 

 
9,400

Total current assets
(112,571
)
 
292,986

 
30,412

 
(408
)
 
210,419

Net property and equipment
3,604

 
917,102

 
91,083

 
(750
)
 
1,011,039

Investment in subsidiaries
1,153,178

 
116,743

 

 
(1,269,921
)
 

Intangible assets, net of accumulated amortization
70

 
41,597

 

 

 
41,667

Goodwill

 
41,683

 

 

 
41,683

Noncurrent deferred income taxes
58,776

 

 
1,740

 
(58,776
)
 
1,740

Other long-term assets
9,051

 
2,389

 
6,269

 

 
17,709

Total assets
$
1,112,108

 
$
1,412,500

 
$
129,504

 
$
(1,329,855
)
 
$
1,324,257

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
685

 
$
42,408

 
$
4,754

 

 
$
47,847

Current portion of long-term debt

 
222

 

 

 
222

Deferred revenues

 
1,593

 
624

 

 
2,217

Accrued expenses
3,642

 
44,426

 
5,424

 
(408
)
 
53,084

Total current liabilities
4,327

 
88,649

 
10,802

 
(408
)
 
103,370

Long-term debt, less current portion
558,848

 
101

 

 

 
558,949

Noncurrent deferred income taxes

 
163,921

 

 
(58,776
)
 
105,145

Other long-term liabilities
326

 
6,651

 
1,959

 

 
8,936

Total liabilities
563,501

 
259,322

 
12,761

 
(59,184
)
 
776,400

Total shareholders’ equity
548,607

 
1,153,178

 
116,743

 
(1,270,671
)
 
547,857

Total liabilities and shareholders’ equity
$
1,112,108

 
$
1,412,500

 
$
129,504

 
$
(1,329,855
)
 
$
1,324,257

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
18,479

 
$
(5,401
)
 
$
10,655

 
$

 
$
23,733

Receivables, net of allowance
440

 
129,570

 
29,128

 
(294
)
 
158,844

Intercompany receivable (payable)
(124,516
)
 
146,652

 
(22,136
)
 

 

Deferred income taxes
869

 
8,162

 
2,027

 

 
11,058

Inventory

 
5,956

 
6,155

 

 
12,111

Prepaid expenses and other current assets
655

 
9,163

 
3,222

 

 
13,040

Total current assets
(104,073
)
 
294,102

 
29,051

 
(294
)
 
218,786

Net property and equipment
3,474

 
921,393

 
90,223

 
(750
)
 
1,014,340

Investment in subsidiaries
1,122,814

 
114,416

 

 
(1,237,230
)
 

Intangible assets, net of accumulated amortization
68

 
43,775

 

 

 
43,843

Goodwill

 
41,683

 

 

 
41,683

Noncurrent deferred income taxes
51,834

 

 
5,519

 
(51,834
)
 
5,519

Other long-term assets
9,582

 
2,340

 
3,683

 

 
15,605

Total assets
$
1,083,699

 
$
1,417,709

 
$
128,476

 
$
(1,290,108
)
 
$
1,339,776

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,558

 
$
76,828

 
$
5,437

 
$

 
$
83,823

Current portion of long-term debt

 
872

 

 

 
872

Deferred revenues

 
1,954

 
1,926

 

 
3,880

Accrued expenses
14,905

 
48,892

 
4,472

 
(294
)
 
67,975

Total current liabilities
16,463

 
128,546

 
11,835

 
(294
)
 
156,550

Long-term debt, less current portion
518,618

 
107

 

 

 
518,725

Noncurrent deferred income taxes
(4
)
 
160,676

 

 
(51,834
)
 
108,838

Other long-term liabilities
192

 
5,566

 
2,225

 

 
7,983

Total liabilities
535,269

 
294,895

 
14,060

 
(52,128
)
 
792,096

Total shareholders’ equity
548,430

 
1,122,814

 
114,416

 
(1,237,980
)
 
547,680

Total liabilities and shareholders’ equity
$
1,083,699

 
$
1,417,709

 
$
128,476

 
$
(1,290,108
)
 
$
1,339,776



16



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)
 
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

 
129,062

 
20,389

 

 
149,451

Depreciation and amortization
252

 
42,702

 
3,331

 

 
46,285

General and administrative
5,426

 
17,132

 
788

 
(138
)
 
23,208

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
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
190,842

 
$
41,136

 
$

 
$
231,978

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
114,941

 
26,832

 

 
141,773

Depreciation and amortization
165

 
32,689

 
5,519

 

 
38,373

General and administrative
5,508

 
13,032

 
2,741

 
(138
)
 
21,143

Intercompany leasing

 
(1,215
)
 
1,231

 
(16
)
 

Bad debt expense (recovery)

 
(180
)
 
89

 

 
(91
)
Impairment of equipment

 
1,032

 

 

 
1,032

Total costs and expenses
5,673

 
160,299

 
36,412

 
(154
)
 
202,230

Income (loss) from operations
(5,673
)
 
30,543

 
4,724

 
154

 
29,748

Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
23,550

 
4,648

 

 
(28,198
)
 

Interest expense
(9,513
)
 
(40
)
 
(2
)
 

 
(9,555
)
Other
(68
)
 
250

 
904

 
(154
)
 
932

Total other (expense) income
13,969

 
4,858

 
902

 
(28,352
)
 
(8,623
)
Income (loss) before income taxes
8,296

 
35,401

 
5,626

 
(28,198
)
 
21,125

Income tax (expense) benefit
5,876

 
(11,851
)
 
(978
)
 

 
(6,953
)
Net income (loss)
$
14,172

 
$
23,550

 
$
4,648

 
$
(28,198
)
 
$
14,172






17



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
Three months ended March 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(70,272
)
 
$
91,273

 
$
8,651

 
$

 
$
29,652

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Purchases of property and equipment
(478
)
 
(84,565
)
 
(10,066
)
 

 
(95,109
)
Proceeds from sale of property and equipment

 
1,316

 
41

 

 
1,357

 
(478
)
 
(83,249
)
 
(10,025
)
 

 
(93,752
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Debt repayments

 
(650
)
 
(6
)
 

 
(656
)
Proceeds from exercise of options
253

 

 

 

 
253

Purchase of treasury stock
(293
)
 

 

 

 
(293
)
 
(40
)
 
(650
)
 
(6
)
 

 
(696
)
Net increase (decrease) in cash and cash equivalents
(70,790
)
 
7,374

 
(1,380
)
 

 
(64,796
)
Beginning cash and cash equivalents
91,932

 
(13,879
)
 
8,144

 

 
86,197

Ending cash and cash equivalents
$
21,142

 
$
(6,505
)
 
$
6,764

 
$

 
$
21,401





18



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, 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 or in our Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2012 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 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.
On July 30, 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business. 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. 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.


19



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 71 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

East Texas
 
3

West Texas
 
23

North Dakota
 
12

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
71

In early 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays. We deployed seven of these new-build drilling rigs during 2012, and deployed the final three in early 2013. All of our new-build drilling rigs are currently operating in shale or unconventional plays under long-term drilling contracts. In April 2013, we sold one mechanical drilling rig that was previously idle in our East Texas division, for which we will recognize an associated gain of approximately $0.2 million.
As of April 15, 2013, 62 of our 71 drilling rigs are earning revenues under drilling contracts, 45 of which are under term contracts. Included in the 45 drilling rigs currently operating under term contracts are four rigs which our client early released due to the recent decrease in demand for vertical conventional drilling in West Texas. These four drilling rigs are under term contracts and therefore we are receiving a standby dayrate for the remainder of the contract term. All of our drilling rigs in Colombia are currently working, six of which are working under term contracts that were extended through the end of 2013. We are actively marketing all of our idle drilling rigs.
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 April 15, 2013, we operate ninety-nine 550 horsepower rigs and ten 600 horsepower rigs through 12 locations, most of which are in the Gulf Coast and ArkLaTex regions.
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


20



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 April 15, 2013, we operate through 24 locations with a fleet of 119 wireline units.
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. Our coiled tubing business consists of nine onshore and four offshore coiled tubing units which are currently deployed through four locations in Texas, Louisiana and Oklahoma.
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 four locations in Texas and Oklahoma. As of March 31, 2013 our fishing and rental tools have a gross book value of $16.7 million.

Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689 and our website address is www.pioneeres.com. We make available free of charge though our website our Annual Reports on our 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.
From 2004 through 2008, domestic exploration and production spending increased as oil and natural gas prices increased. From late 2008 and into late 2009, there was substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our clients curtailed their drilling programs and reduced their production activities, particularly in natural gas producing regions, which resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment.
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. Though oil prices decreased sharply in mid-2012 for a brief period of time, they recovered with no meaningful upward or downward trend for the year and have remained roughly flat during early 2013. In addition, excess natural gas production in the U.S. shale regions continues to depress natural gas prices. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Colombia has experienced significant growth in oil production since 2008 largely due to the infusion of capital by international exploration and production companies as a result of the country's improved regulation and security. 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.


21



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.
For additional information concerning the effects of the volatility in oil and gas prices, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2012.


22



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 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 April 15, 2013, approximately 95% of our working drilling rigs and 78% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas.
International Presence. In early 2007, we announced our intention to selectively expand internationally and began a relationship with Ecopetrol S.A. 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. Currently, all of our eight drilling rigs in Colombia are working, six of which are under term contracts that were extended through the end of 2013.
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 56 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 and reposition ourselves for continued long-term growth.
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 $10.5 million as of March 31, 2013), 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 April 15, 2013, 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.
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 Go-Coil in December 2011.


23



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 April 15, 2013, we had $140.0 million outstanding under our Revolving Credit Facility and $8.9 million in committed letters of credit, which resulted in borrowing availability of $101.1 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, 2013, we had $42.1 million of additions to our property and equipment. Currently, we expect to spend approximately $140 million to $160 million on capital expenditures during 2013. We expect the total capital expenditures for 2013 will be allocated approximately 70% for our Drilling Services Segment and approximately 30% for our Production Services Segment. Our planned capital expenditures for the year ending December 31, 2013 include the remaining construction costs of our new-build AC drilling rigs, upgrades to certain drilling rigs, additional production services equipment and routine capital expenditures. Actual capital expenditures may vary depending on 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 2013 from operating cash flow in excess of our working capital requirements.
Working Capital
Our working capital was $107.0 million at March 31, 2013, compared to $62.2 million at December 31, 2012. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.0 at March 31, 2013 compared to 1.4 at December 31, 2012.
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.


24



The changes in the components of our working capital were as follows (amounts in thousands):
 
March 31,
2013
 
December 31,
2012
 
Change
Cash and cash equivalents
$
10,508

 
$
23,733

 
$
(13,225
)
Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
111,316

 
116,352

 
(5,036
)
Unbilled receivables
44,950

 
35,140

 
9,810

Insurance recoveries
9,321

 
6,518

 
2,803

Income taxes
200

 
834

 
(634
)
Deferred income taxes
12,387

 
11,058

 
1,329

Inventory
12,337

 
12,111

 
226

Prepaid expenses and other current assets
9,400

 
13,040

 
(3,640
)
Current assets
210,419

 
218,786

 
(8,367
)
Accounts payable
47,847

 
83,823

 
(35,976
)
Current portion of long-term debt
222

 
872

 
(650
)
Deferred revenues
2,217

 
3,880

 
(1,663
)
Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
22,380

 
27,991

 
(5,611
)
Insurance premiums and deductibles
10,979

 
9,708

 
1,271

Insurance claims and settlements
9,321

 
6,348

 
2,973

Interest
1,899

 
12,343

 
(10,444
)
Other
8,505

 
11,585

 
(3,080
)
Current liabilities
103,370

 
156,550

 
(53,180
)
Working capital
$
107,049

 
$
62,236

 
$
44,813

The decrease in cash and cash equivalents during the three months ended March 31, 2013 is primarily due to $71.3 million used for purchases of property and equipment, partially offset by $17.2 million of cash provided by operating activities and $39.3 million in net proceeds from debt borrowings.
The net increase in our total trade and unbilled receivables as of March 31, 2013 as compared to December 31, 2012 is primarily due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia, as well as the increase in revenues of $1.8 million, or 1%, for the quarter ended March 31, 2013 as compared to the quarter ended December 31, 2012.
The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of March 31, 2013 as compared to December 31, 2012 is primarily due to an increase in our insurance company's reserve for workers compensation claims in excess of our deductibles.
The increase in current deferred income taxes as of March 31, 2013 as compared to December 31, 2012 is due to a movement of our deferred tax assets related to net operating losses from long-term to current, as we expect to realize them in the short term. The increase was mostly offset by a reduction in the current deferred tax assets for our annual bonus accruals which were paid in the first quarter of 2013.
The decrease in prepaid expenses and other assets as of March 31, 2013 as compared to December 31, 2012 is primarily due to the amortization of deferred mobilization costs for our new-build drilling rigs and other drilling rigs that moved between drilling divisions domestically and between well locations in Colombia.
The decrease in accounts payable is primarily due to a $29.3 million decrease in our accruals for capital expenditures as of March 31, 2013 as compared to December 31, 2012, as we completed construction of three of our new-build drilling rigs during the first quarter of 2013.
The decrease in deferred revenues is primarily related to the amortization of deferred mobilization costs for drilling rigs in Colombia which moved between well locations in 2012.


25



The decrease in accrued payroll and employee related costs as of March 31, 2013 as compared to December 31, 2012 is primarily due to the payment of our 2012 annual bonuses during the first quarter of 2013, and partially due to lower payroll accruals resulting from fewer payroll days reflected in the accrued payroll at March 31, 2013 as compared to December 31, 2012, due to the timing of pay periods.
The increase in our accrued insurance premiums and deductibles is primarily due to an increase in our health insurance costs.
The decrease in accrued interest expense 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, 2013 as compared to December 31, 2012 is primarily due to a decrease in our sales tax accrual which primarily related to the construction of our new-build drilling rigs which were completed in the first quarter of 2013, and a decrease in property tax accruals due to timing of payments.
Long-term Debt and Other Contractual Obligations