XNYS:PES Pioneer Energy Services Corp Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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, 2012
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-8182

PIONEER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
_____________________________________________ 
TEXAS
 
74-2088619
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification Number)
 
 
 
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas
 
78209
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code: (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
x
Accelerated filer
o
 
 
 
 
Non-accelerated filer
o
Smaller reporting company
o
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 20, 2012, there were 61,880,310 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

 




PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
March 31,
2012
 
December 31,
2011
 
(Unaudited)
 
(Audited)
 
(In thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
21,401

 
$
86,197

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
117,274

 
106,084

Unbilled receivables
39,759

 
31,512

Insurance recoveries
6,464

 
5,470

Income taxes
146

 
2,168

Deferred income taxes
16,259

 
15,433

Inventory
12,220

 
11,184

Prepaid expenses and other current assets
12,207

 
11,564

Total current assets
225,730

 
269,612

Property and equipment, at cost
1,443,614

 
1,336,926

Less accumulated depreciation
575,126

 
542,970

Net property and equipment
868,488

 
793,956

Intangible assets, net of amortization
50,503

 
52,680

Goodwill
41,683

 
41,683

Noncurrent deferred income taxes

 
735

Other long-term assets
12,680

 
14,088

Total assets
$
1,199,084

 
$
1,172,754

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
85,117

 
$
66,440

Current portion of long-term debt
873

 
872

Prepaid drilling contracts
4,733

 
3,966

Accrued expenses:
 
 
 
Payroll and related employee costs
23,260

 
29,057

Insurance premiums and deductibles
10,547

 
10,583

Insurance claims and settlements
6,464

 
5,470

Interest
1,789

 
12,283

Other
11,405

 
11,009

Total current liabilities
144,188

 
139,680

Long-term debt, less current portion
418,279

 
418,728

Noncurrent deferred income taxes
100,701

 
94,745

Other long-term liabilities
9,375

 
9,156

Total liabilities
672,543

 
662,309

Commitments and contingencies (Note 8)

 

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

 

Common stock $.10 par value; 100,000,000 shares authorized; 61,880,310 shares and 61,782,180 shares outstanding at March 31, 2012 and December 31, 2011, respectively
6,201

 
6,188

Additional paid-in capital
444,224

 
442,020

Treasury stock, at cost; 126,036 shares and 95,409 shares at March 31, 2012 and December 31, 2011, respectively
(1,197
)
 
(904
)
Accumulated earnings
77,313

 
63,141

Total shareholders’ equity
526,541

 
510,445

Total liabilities and shareholders’ equity
$
1,199,084

 
$
1,172,754

See accompanying notes to condensed consolidated financial statements.


2



PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
Three months ended March 31,
 
2012
 
2011
 
(In thousands, except per share data)
Revenues:
 
 
 
Drilling services
$
124,304

 
$
99,756

Production services
107,674

 
53,593

Total revenues
231,978

 
153,349

Costs and expenses:
 
 
 
Drilling services
81,077

 
67,509

Production services
60,696

 
33,228

Depreciation and amortization
38,373

 
32,256

General and administrative
21,143

 
14,521

Bad debt recovery
(91
)
 
(84
)
Impairment of equipment
1,032

 

Total costs and expenses
202,230

 
147,430

Income from operations
29,748

 
5,919

Other (expense) income:
 
 
 
Interest expense
(9,555
)
 
(7,539
)
Other
932

 
(6,517
)
Total other expense
(8,623
)
 
(14,056
)
Income (loss) before income taxes
21,125

 
(8,137
)
Income tax (expense) benefit
(6,953
)
 
2,102

Net income (loss)
$
14,172

 
$
(6,035
)
 
 
 
 
Income (loss) per common share—Basic
$
0.23

 
$
(0.11
)
 
 
 
 
Income (loss) per common share—Diluted
$
0.23

 
$
(0.11
)
 
 
 
 
Weighted average number of shares outstanding—Basic
$
61,578

 
$
53,968

 
 
 
 
Weighted average number of shares outstanding—Diluted
$
62,647

 
$
53,968


See accompanying notes to condensed consolidated financial statements.



3



PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
Three months ended March 31,
 
2012
 
2011
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income (loss)
$
14,172

 
$
(6,035
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation and amortization
38,373

 
32,256

Allowance for doubtful accounts
(94
)
 
(84
)
Loss (gain) on dispositions of property and equipment
(733
)
 
923

Stock-based compensation expense
2,000

 
1,712

Amortization of debt issuance costs, discount and premium
732

 
742

Impairment of equipment
1,032

 

Deferred income taxes
5,846

 
(2,823
)
Change in other long-term assets
720

 
734

Change in other long-term liabilities
219

 
4,477

Changes in current assets and liabilities:
 
 
 
Receivables
(17,320
)
 
(19,303
)
Inventory
(1,036
)
 
(605
)
Prepaid expenses and other current assets
(644
)
 
(808
)
Accounts payable
1,407

 
1,797

Prepaid drilling contracts
767

 
50

Accrued expenses
(15,789
)
 
(3,989
)
Net cash provided by operating activities
29,652

 
9,044

 
 
 
 
Cash flows from investing activities:
 
 
 
Acquisition of production services businesses

 
(2,000
)
Purchases of property and equipment
(95,109
)
 
(31,379
)
Proceeds from sale of property and equipment
1,357

 
786

Proceeds from sale of auction rate securities

 
12,569

Net cash used in investing activities
(93,752
)
 
(20,024
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Debt repayments
(656
)
 
(13,529
)
Proceeds from issuance of debt

 
17,000

Proceeds from exercise of options
253

 
560

Purchase of treasury stock
(293
)
 
(210
)
Excess tax benefit of stock option exercises

 
459

Net cash (used in) provided by financing activities
(696
)
 
4,280

 
 
 
 
Net decrease in cash and cash equivalents
(64,796
)
 
(6,700
)
Beginning cash and cash equivalents
86,197

 
22,011

Ending cash and cash equivalents
$
21,401

 
$
15,311

 
 
 
 
Supplementary disclosure:
 
 
 
Interest paid
$
21,343

 
$
13,004

Income tax (refunded) paid
$
(1,074
)
 
$
226

 
See accompanying notes to condensed consolidated financial statements.


4



PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
1.
Organization and Summary of Significant Accounting Policies
Business and Principles of Consolidation
Pioneer Drilling Company provides drilling services and production services to independent and major 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.
Our Drilling Services Division provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following locations:
Drilling Division Locations
 
Rig Count
South Texas
 
15

East Texas
 
3

West Texas
 
19

North Dakota
 
9

Utah
 
4

Appalachia
 
4

Colombia
 
8

 
 
62

Drilling revenues and rig utilization steadily improved during 2010 and 2011, primarily due to increased demand for drilling services in domestic shale plays and oil or liquid rich regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions. As a result, we closed our Oklahoma and North Texas drilling division locations during 2011 and established our West Texas drilling division location in early 2011.
In March 2012, we evaluated the drilling rigs in our fleet that have remained idle and decided to retire two mechanical drilling rigs that were assigned to our East Texas drilling division location, with most of their components to be used for spare equipment. Therefore, our fleet count has been reduced from 64 to 62 drilling rigs at March 31, 2012. We recognized an impairment charge of $0.6 million in March 2012 in association with our decision to retire these two drilling rigs.
We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, for which we expect seven to begin working by the end of 2012, with the remaining three during the first quarter of 2013. As of April 20, 2012, 55 drilling rigs are operating under drilling contracts, 45 of which are under term contracts. We have seven drilling rigs that are idle and are actively marketing all 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 customers. 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 Division provides a range of services to exploration and production companies, including well services, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. As of April 20, 2012, we have a fleet of 97 well service rigs consisting of eighty-seven 550 horsepower rigs, nine 600 horsepower rigs and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed. We currently provide wireline and coiled tubing services with a fleet of 108 wireline units and ten coiled tubing units, and we provide rental services with approximately $15.4 million of fishing and rental tools. We plan to add another 11 well service rigs, 11 wireline units and three coiled tubing units by the end of 2012. In March 2012, we decided to retire two older wireline units and certain wireline equipment resulting in an impairment charge of approximately $0.4 million.


5



The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Drilling Company 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. 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 estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes, our estimate of compensation related accruals and our determination of depreciation and amortization expense. The condensed consolidated balance sheet as of December 31, 2011 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, 2011.
In preparing the accompanying unaudited condensed consolidated financial statements, we have reviewed events that have occurred after March 31, 2012, through the filing of this Form 10-Q, for inclusion as necessary.
Recently Issued Accounting Standards
Fair Value Measurement. In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This update clarifies existing guidance about how fair value should be applied where it already is required or permitted and provides wording changes that align this standard with International Financial Reporting Standards (IFRS). We are required to apply this guidance prospectively beginning with our first quarterly filing in 2012. The adoption of this new guidance has not had an impact on our financial position or results of operations.
Comprehensive Income. In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update increases the prominence of other comprehensive income in financial statements, eliminating the option of presenting other comprehensive income in the statement of changes in equity, and instead, giving companies the option to present the components of net income and comprehensive income in either one or two consecutive financial statements. We are required to comply with this guidance prospectively beginning with our first quarterly filing in 2012. We have not recognized any other comprehensive income during either of the three month periods ended March 31, 2012 or 2011. The adoption of this new guidance has not had an impact on our financial position or results of operations.
In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update delays the effective date of the requirement to present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements.
Intangibles–Goodwill and Other. In September 2011, the FASB issued ASU No. 2011-08, Intangibles–Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This update allows entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this new guidance has not had an impact on our financial position or results of operations.
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 customer 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 20, 2012, we have 45 drilling rigs operating under term contracts. Of these 45 contracts, if not renewed at the end of their terms, 25


6



will expire by October 20, 2012, 19 will expire by April 20, 2013 and one will expire by April 20, 2014. We also have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, for which we expect seven to begin working by the end of 2012, with the remaining three during the first quarter of 2013.
Restricted Cash
As of March 31, 2012, we had restricted cash in the amount of $0.7 million held in an escrow account to be used for a future payment due March 2013 in connection with the acquisition of Prairie Investors d/b/a Competition Wireline (“Competition”). Restricted cash of $0.7 million is recorded in other current assets and the associated obligation of $0.7 million is recorded in accrued expenses.
Investments
At December 31, 2010, we held $15.9 million (par value) of auction rate preferred securities (“ARPSs”), which were variable-rate preferred securities with a long-term maturity that were classified as held for sale. On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represented 79% of the par value, plus accrued interest. Under the ARPSs sales agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities (collectively, the “ARPSs Call Option”). Upon origination, the fair value of the ARPSs Call Option was estimated to be $0.6 million and was recognized as other income in our consolidated statement of operations for 2011. We are required to assess the value of the ARPSs Call Option at the end of each reporting period, with any changes in fair value recorded within our consolidated statement of operations. As of March 31, 2012, the ARPSs Call Option had an estimated fair value of $0.2 million, and was included in our other long-term assets in our condensed consolidated balance sheet.
Property and Equipment
As of March 31, 2012, we have incurred a total of $158.3 million of construction costs, primarily on our ten new-build drilling rigs that were under construction at March 31, 2012. During three months ended March 31, 2012, we capitalized $2.0 million of interest costs, primarily related to the ten new-build drilling rigs.
2.
Acquisitions
On December 31, 2011, we acquired Go-Coil, LLC, a Louisiana limited liability company ("Go-Coil") which provides coiled tubing services with a fleet of seven onshore units and three offshore units through its facilities in Louisiana, Texas, Oklahoma and Pennsylvania. The aggregate purchase price for the acquisition was approximately $110.4 million, which consisted of assets acquired of $114.9 million and liabilities assumed of $4.5 million. We funded the acquisition with cash on hand that was primarily generated from the proceeds of the Senior Notes issued in November 2011, as described in Note 3, Long-term Debt.
The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):
Cash acquired
$
313

Other current assets
9,068

Property and equipment
30,103

Intangibles and other assets
33,695

Goodwill
41,683

Total assets acquired
$
114,862

Current liabilities
$
4,337

Long-term debt
131

Total liabilities assumed
$
4,468

Net assets acquired
$
110,394

The acquisition of the production services business from Go-Coil was accounted for as an acquisition of a business in accordance with ASC Topic 805, Business Combinations. The purchase price allocation for the Go-Coil acquisition is preliminary at this time and may change once we receive finalized information regarding the fair value estimates of the assets acquired and liabilities assumed in the acquisition. In addition, we have not finalized certain working capital adjustments which will be settled with the former owners of Go-Coil. Goodwill was recognized as part of the Go-Coil acquisition, since the purchase price exceeded


7



the estimated fair value of the assets acquired and liabilities assumed. We believe that the goodwill relates to the acquired workforce, future synergies between our existing service offerings and the ability to expand our service offerings.
3.
Long-term Debt
Long-term debt consists of the following (amounts in thousands):
 
March 31, 2012
 
December 31, 2011
Senior secured revolving credit facility
$

 
$

Senior notes
417,954

 
417,747

Subordinated notes payable and other
1,198

 
1,853

 
419,152

 
419,600

Less current portion
(873
)
 
(872
)
 
$
418,279

 
$
418,728

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 20, 2012 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 Go-Coil, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

As of April 27, 2012, we had $20.0 million outstanding under our Revolving Credit Facility and $9.0 million in committed letters of credit, which resulted in borrowing availability of $221.0 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, 2012, we were in compliance with our financial covenants. Our total consolidated leverage ratio was 1.9 to 1.0, our senior consolidated leverage ratio was 0.04 to 1.0, and our interest coverage ratio was 7.4 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, 2012, 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.
In accordance with a registration rights agreement with the holders of our 2010 Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010. This exchange offer registration statement enabled the holders of our 2010 Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “2010 Senior Notes” herein include the senior notes issued in the exchange offer.
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, as described in Note 2, Acquisitions.
The 2010 and 2011 Senior Notes (the "Senior Notes") are reflected on our condensed consolidated balance sheet at March 31, 2012 with a total carrying value of $418.0 million, which represents the $425.0 million total face value net of the $8.7 million unamortized portion of original issue discount and $1.6 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. In addition, prior to March 15, 2013, we may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 109.875% of the principal amount, plus any accrued and unpaid interest to the redemption date, with the net proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing of the equity offering.
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.
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;


9



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, 2012. The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries (see Note 9, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements).
Subordinated Notes Payable and Other
We have two subordinated notes payable to certain employees that are former shareholders of production services businesses which we have acquired. These subordinated notes payable have interest rates of 6% and 14%, require annual payments of principal and interest and have final maturity dates in March and April 2013. We have other debt of $0.1 million as of March 31, 2012 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 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 $11.0 million and $11.6 million as of March 31, 2012 and December 31, 2011, respectively. We recognized approximately $0.5 million and $0.5 million of associated amortization during the three months ended March 31, 2012 and 2011, respectively.
4.
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, 2012 and December 31, 2011, our financial instruments consist primarily of cash, trade receivables, trade payables, long-term debt, and our ARPSs Call Option. 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.
At March 31, 2012, our ARPSs Call Option is reported at an amount that reflects our current estimate of fair value. To estimate the value of our ARPSs Call Option as of March 31, 2012, we used inputs defined by ASC Topic 820 as level 3 inputs, which are significant unobservable inputs. The fair value of the ARPSs Call Option was estimated using a modified Black-Scholes model, based on an analysis of recent historical transactions for securities with similar characteristics to the underlying ARPSs, and an analysis of the probability that the options would be exercisable as a result of the underlying ARPSs being redeemed or traded in a secondary market at an amount greater than the option price before the expiration date. As of March 31, 2012, the ARPSs Call Option had an estimated fair value of $0.2 million, and was included in our other long-term assets in our consolidated balance sheet. Future changes in the fair values of the ARPSs Call Option will be reflected in other income (expense) in our condensed consolidated statements of operations.
The fair value of our long-term debt at March 31, 2012 and December 31, 2011 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 based on observable inputs for similar types of debt instruments represents level 2 inputs as defined by ASC Topic 820. The following table presents the supplemental fair value information about long-term debt at March 31, 2012 and December 31, 2011 (amounts in thousands):
 
March 31, 2012
 
December 31, 2011
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
419,152

 
$
462,189

 
$
419,600

 
$
443,309






10



5.
Earnings (Loss) Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic income (loss) per share and diluted income (loss) per share computations (amounts in thousands, except per share data):
 
 
Three months ended March 31,
 
2012
 
2011
Basic
 
 
 
Net income (loss)
$
14,172

 
$
(6,035
)
Weighted-average shares
61,578

 
53,968

Income (loss) per share
$
0.23

 
$
(0.11
)
Diluted
 
 
 
Net income (loss)
$
14,172

 
$
(6,035
)
Effect of dilutive securities

 

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

 
$
(6,035
)
Weighted average shares:
 
 
 
Outstanding
61,578

 
53,968

Diluted effect of stock options, restricted stock, and restricted stock unit awards
1,069

 

 
62,647

 
53,968

Income (loss) per share
$
0.23

 
$
(0.11
)
Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 3,742,383 and 4,875,894 shares of common stock were excluded from the computation of diluted weighted average shares outstanding for the three months ended March 31, 2012 and 2011, respectively, due to their antidilutive effect.
6.
Equity Transactions and Stock Based Compensation Plans
Stock-based Compensation Plans
We grant stock option awards with vesting based on time of service conditions and we 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 provide that all stock option awards must have an exercise price 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.


11



We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-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, 2012 and 2011:
 
 
Three months ended March 31,
 
2012
 
2011
Expected volatility
70
%
 
65
%
Risk-free interest rates
0.8
%
 
1.5
%
Expected life in years
5.31
 
4.33
Options granted
475,156
 
597,298
Grant-date fair value
$5.21
 
$4.67
The assumptions above 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.
The following table summarizes the compensation expense recognized for stock option awards during the three months ended March 31, 2012 and 2011 (amounts in thousands):
 
Three months ended March 31,
 
2012
 
2011
General and administrative expense
$
919

 
$
997

Operating costs
44

 
81

 
$
963

 
$
1,078


During the three months ended March 31, 2012 and 2011, 68,100 and 127,300 stock options were exercised at a weighted-average exercise price of $3.72 and $4.40, 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 consolidated statement of cash flows.
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 RSU 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, 2012 or 2011.
The following table summarizes the compensation expense recognized for restricted stock awards during the three months ended March 31, 2012 and 2011 (amounts in thousands):
 
Three months ended March 31,
 
2012
 
2011
General and administrative expense
$
216

 
$
160

Operating costs
15

 
24

 
$
231

 
$
184

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.


12



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.
 
Three months ended March 31,
 
2012
 
2011
Time-based RSUs granted
205,313

 
102,903

Weighted-average grant-date fair value
$
9.07

 
$
9.01

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.
 
Three months ended March 31,
 
2012
 
2011
Performance-based RSUs granted
221,495

 
146,479

Weighted-average grant-date fair value
$
9.85

 
$
10.23

Performance-based RSUs granted during the three months ended March 31, 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 respective 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.
The following table summarizes the compensation expense recognized for restricted stock unit awards during the three months ended March 31, 2012 and 2011 (amounts in thousands):
 
Three months ended March 31,
 
2012
 
2011
General and administrative expense
$
658

 
$
389

Operating costs
148

 
61

 
$
806

 
$
450

7.
Segment Information
We have two operating segments referred to as the Drilling Services Division and the Production Services Division which is the basis management uses for making operating decisions and assessing performance.
Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following locations:
Drilling Division Locations
 
Rig Count
South Texas
 
15

East Texas
 
3

West Texas
 
19

North Dakota
 
9

Utah
 
4

Appalachia
 
4

Colombia
 
8

 
 
62

Production Services DivisionOur Production Services Division provides a range of services to exploration and production companies, including well services, wireline services, coiled tubing services, and fishing and rental services. Our production


13



services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states.We currently have a fleet of 97 well service rigs consisting of eighty-seven 550 horsepower rigs, nine 600 horsepower rigs and one 400 horsepower rig. We currently provide wireline and coiled tubing services with a fleet of 108 wireline units and ten coiled tubing units, and we provide rental services with approximately $15.4 million of 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, 2012 and 2011 (amounts in thousands):
 
As of and for the three months ended March 31, 2012
 
Drilling
Services
Division
 
Production
Services
Division
 
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

 
As of and for the three months ended March 31, 2011
 
Drilling
Services
Division
 
Production
Services
Division
 
Corporate
 
Total
Identifiable assets
$
581,725

 
$
241,836

 
$
24,426

 
$
847,987

Revenues
$
99,756

 
$
53,593

 
$

 
$
153,349

Operating costs
67,509

 
33,228

 

 
100,737

Segment margin
$
32,247

 
$
20,365

 
$

 
$
52,612

Depreciation and amortization
$
24,486

 
$
7,495

 
$
275

 
$
32,256

Capital expenditures
$
19,113

 
$
15,444

 
$
137

 
$
34,694

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, 2012 and 2011 (amounts in thousands):
 
Three months ended March 31,
 
2012
 
2011
Segment margin
$
90,205

 
$
52,612

Depreciation and amortization
(38,373
)
 
(32,256
)
General and administrative
(21,143
)
 
(14,521
)
Bad debt recovery
91

 
84

Impairment of equipment
(1,032
)
 

Income from operations
$
29,748

 
$
5,919

The following table sets forth certain financial information for our international operations in Colombia as of and for the three months ended March 31, 2012 and 2011 which is included in our Drilling Services Division (amounts in thousands):
 
As of and for the three months ended March 31,
 
2012
 
2011
Identifiable assets
$
152,854

 
$
157,285

Revenues
$
23,816

 
$
24,234

Identifiable assets as of March 31, 2012 and 2011 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




8.
Commitments and Contingencies
In connection with our expansion into international markets, 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 $47.8 million relating to our performance under these bonds.
The Colombian government enacted a tax reform act which, among other things, adopted a one-time, net-worth tax for all Colombian entities, which was assessed on January 1, 2011 and is payable in eight semi-annual installments from 2011 through 2014. Based on our Colombian operations’ net equity, measured on a Colombian tax basis as of January 1, 2011, our total net-worth tax obligation is approximately $7.3 million, which is not deductible for tax purposes. We recognized this tax obligation in full during the first quarter of 2011 in other expense in our condensed consolidated statement of operations. As of March 31, 2012, we have a remaining obligation of $5.7 million, which is recorded in other accrued expenses and other long-term liabilities on our condensed consolidated balance sheet.
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.
9.
Guarantor/Non-Guarantor Condensed Consolidated Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, Go-Coil, LLC, and certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. 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, 2012, 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, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
21,142

 
$
(6,505
)
 
$
6,764

 
$

 
$
21,401

Receivables, net of allowance for doubtful accounts
2

 
123,415

 
43,844

 
(3,618
)
 
163,643

Intercompany receivable (payable)
(126,574
)
 
142,819

 
(16,245
)
 

 

Deferred income taxes
553

 
6,656

 
9,050

 

 
16,259

Inventory

 
4,971

 
7,249

 

 
12,220

Prepaid expenses and other current assets
246

 
7,890

 
4,071

 

 
12,207

Total current assets
(104,631
)
 
279,246

 
54,733

 
(3,618
)
 
225,730

Net property and equipment
1,751

 
743,910

 
123,577

 
(750
)
 
868,488

Investment in subsidiaries
1,004,501

 
225,515

 

 
(1,230,016
)
 

Intangible assets, net of amortization
176

 
17,768

 
32,559

 

 
50,503

Goodwill

 

 
41,683

 

 
41,683

Noncurrent deferred income taxes
36,436

 

 

 
(36,436
)
 

Other long-term assets
11,208

 
1,457

 
15

 

 
12,680

Total assets
$
949,441

 
$
1,267,896

 
$
252,567

 
$
(1,270,820
)
 
$
1,199,084

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
452

 
$
76,081

 
$
8,584

 

 
$
85,117

Current portion of long-term debt

 
850

 
23

 

 
873

Prepaid drilling contracts

 
2,722

 
2,011

 

 
4,733

Accrued expenses
3,541

 
43,997

 
9,545

 
(3,618
)
 
53,465

Total current liabilities
3,993

 
123,650

 
20,163

 
(3,618
)
 
144,188

Long-term debt, less current portion
417,954

 
200

 
125

 

 
418,279

Noncurrent deferred income taxes

 
134,255

 
2,882

 
(36,436
)
 
100,701

Other long-term liabilities
203

 
5,290

 
3,882

 

 
9,375

Total liabilities
422,150

 
263,395

 
27,052

 
(40,054
)
 
672,543

Total shareholders’ equity
527,291

 
1,004,501

 
225,515

 
(1,230,766
)
 
526,541

Total liabilities and shareholders’ equity
$
949,441

 
$
1,267,896

 
$
252,567

 
$
(1,270,820
)
 
$
1,199,084

 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
91,932

 
$
(13,879
)
 
$
8,144

 
$

 
$
86,197

Receivables, net of allowance for doubtful accounts
(2
)
 
112,531

 
32,724

 
(19
)
 
145,234

Intercompany receivable (payable)
(122,552
)
 
131,585

 
(9,033
)
 

 

Deferred income taxes
1,408

 
8,644

 
5,381

 

 
15,433

Inventory

 
4,533

 
6,651

 

 
11,184

Prepaid expenses and other current assets
285

 
6,304

 
4,975

 

 
11,564

Total current assets
(28,929
)
 
249,718

 
48,842

 
(19
)
 
269,612

Net property and equipment
1,605

 
675,679

 
117,422

 
(750
)
 
793,956

Investment in subsidiaries
932,237

 
221,201

 

 
(1,153,438
)
 

Intangible assets, net of amortization
171

 
18,829

 
33,680

 

 
52,680

Goodwill

 

 
41,683

 

 
41,683

Noncurrent deferred income taxes
30,835

 

 
735

 
(30,835
)
 
735

Other long-term assets
11,949

 
2,124

 
15

 

 
14,088

Total assets
$
947,868

 
$
1,167,551

 
$
242,377

 
$
(1,185,042
)
 
$
1,172,754

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,090

 
$
57,150

 
$
8,200

 
$

 
$
66,440

Current portion of long-term debt

 
850

 
22

 

 
872

Prepaid drilling contracts

 
1,297

 
2,669

 

 
3,966

Accrued expenses
16,779

 
45,012

 
6,631

 
(20
)
 
68,402

Total current liabilities
17,869

 
104,309

 
17,522

 
(20
)
 
139,680

Long-term debt, less current portion
417,747

 
850

 
131

 

 
418,728

Noncurrent deferred income taxes
921

 
124,659

 

 
(30,835
)
 
94,745

Other long-term liabilities
137

 
5,496

 
3,523

 

 
9,156

Total liabilities
436,674

 
235,314

 
21,176

 
(30,855
)
 
662,309

Total shareholders’ equity
511,194

 
932,237

 
221,201

 
(1,154,187
)
 
510,445

Total liabilities and shareholders’ equity
$
947,868

 
$
1,167,551

 
$
242,377

 
$
(1,185,042
)
 
$
1,172,754



16



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)
 
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

 
(180
)
 
89

 

 
(91
)
Impairment of equipment

 
1,032

 

 

 
1,032

Total costs and expenses
5,673

 
160,299

 
36,412

 
(154
)
 
202,230

Income 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
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

 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2011
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$

 
$
129,115

 
$
24,234

 
$

 
$
153,349

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs

 
81,878

 
18,859

 

 
100,737

Depreciation and amortization
275

 
29,118

 
2,863

 

 
32,256

General and administrative
4,131

 
9,890

 
608

 
(108
)
 
14,521

Intercompany leasing

 
(1,215
)
 
1,215

 

 

Bad debt recovery

 
(84
)
 

 

 
(84
)
Total costs and expenses
4,406

 
119,587

 
23,545

 
(108
)
 
147,430

Income from operations
(4,406
)
 
9,528

 
689

 
108

 
5,919

Other income (expense):
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
807

 
(5,027
)
 

 
4,220

 

Interest expense
(7,472
)
 
(73
)
 
6

 

 
(7,539
)
Other
532

 
236

 
(7,177
)
 
(108
)
 
(6,517
)
Total other income (expense)
(6,133
)
 
(4,864
)
 
(7,171
)
 
4,112

 
(14,056
)
Income (loss) before income taxes
(10,539
)
 
4,664

 
(6,482
)
 
4,220

 
(8,137
)
Income tax (expense) benefit
4,504

 
(3,857
)
 
1,455

 

 
2,102

Net earnings (loss)
$
(6,035
)
 
$
807

 
$
(5,027
)
 
$
4,220

 
$
(6,035
)
 
 
 
 
 
 
 
 
 
 


17



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
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

 
 
 
 
 
 
 
 
 
 
 
Three months ended March 31, 2011
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash flows from operating activities
$
(17,846
)
 
$
30,450

 
$
(3,560
)
 
$

 
$
9,044

Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
Acquisition of production services businesses

 
(2,000
)
 

 

 
(2,000
)
Purchases of property and equipment
(90
)
 
(29,492
)
 
(1,797
)
 

 
(31,379
)
Proceeds from sale of property and equipment

 
782

 
4

 

 
786

Proceeds from sale of auction rate securities
12,569

 

 

 

 
12,569

 
12,479

 
(30,710
)
 
(1,793
)
 

 
(20,024
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
Debt repayments
(12,800
)
 
(729
)
 

 

 
(13,529
)
Proceeds from issuance of debt
17,000

 

 

 

 
17,000

Proceeds from exercise of options
560

 

 

 

 
560

Purchase of treasury stock
(210
)
 

 

 

 
(210
)
Excess tax benefit of stock option exercises
459

 

 

 

 
459

 
5,009

 
(729
)
 

 

 
4,280

Net decrease in cash and cash equivalents
(358
)
 
(989
)
 
(5,353
)
 

 
(6,700
)
Beginning cash and cash equivalents
15,737

 
(1,840
)
 
8,114

 

 
22,011

Ending cash and cash equivalents
$
15,379

 
$
(2,829
)
 
$
2,761

 
$

 
$
15,311

 
 
 
 
 
 
 
 
 
 


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 onshore exploration and development projects to be made by oil and gas exploration and production companies, risks associated with economic cycles and their impact on capital markets and liquidity, the continued demand for the 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 service rigs, coiled tubing and wireline units within the industry, the continued availability of drilling rig, well service 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, 2011, 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, 2011 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 provides drilling services and production services to independent and major 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. 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 significantly expanded our service offerings with the acquisition of two production services businesses, which provide well services, 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 Go-Coil, LLC ("Go-Coil"), a coiled tubing service company based in Maurice, Louisiana, to complement our existing production services offerings. 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 customers.


19



Business Segments
We currently conduct our operations through two operating segments: our Drilling Services Division and our Production Services Division. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 7, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item 1, Financial Statements and Supplementary Data, of this Quarterly Report on Form 10-Q.
Drilling Services Division—Our Drilling Services Division provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following locations:
Drilling Division Locations
 
Rig Count
South Texas
 
15

East Texas
 
3

West Texas
 
19

North Dakota
 
9

Utah
 
4

Appalachia
 
4

Colombia
 
8

 
 
62

Drilling revenues and rig utilization steadily improved during 2010 and 2011, primarily due to increased demand for drilling services in domestic shale plays and oil or liquid rich regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions. As a result, we closed our Oklahoma and North Texas drilling division locations during 2011 and established our West Texas drilling division location in early 2011.
At March 31, 2012, we have 62 drilling rigs in our fleet. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, for which we expect seven to begin working by the end of 2012, with the remaining three during the first quarter of 2013. As of April 20, 2012, 55 drilling rigs are operating under drilling contracts, 45 of which are under term contracts. We have seven drilling rigs that are idle and are actively marketing all 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 customers. 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 Division—Our Production Services Division provides a range of services to exploration and production companies, including well services, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are managed through locations concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, Rocky Mountain and Appalachian states. 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 Services. Existing and newly-drilled wells require a range of services to establish and maintain production over their useful lives. We use our well service rig fleet to provide these required services, including maintenance of existing wells, workover of existing wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. We have acquired 8 well service rigs during 2012, resulting in a total of 97 well service rigs in 12 locations as of April 20, 2012. Our well service rig fleet consists of eighty-seven 550 horsepower rigs, nine 600 horsepower rigs, and one 400 horsepower rig. All our well service rigs are currently operating or are being actively marketed. We plan to add another 11 well service rigs to our fleet during 2012.
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. When a producing well is completed, they also must perforate the production casing 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.


20



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 April 20, 2012, we operate in 25 locations with 108 wireline units and plan to add another 11 wireline units to our fleet during 2012.
Coiled Tubing Services. Coiled tubing is an important element of the well service industry today 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 ten coiled tubing units which are currently deployed in Texas, Louisiana, Oklahoma and Pennsylvania. We plan to add another three coiled tubing units to our fleet during 2012.
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, 2012 our fishing and rental tools have a gross book value of $15.4 million.

Pioneer Drilling Company’s corporate office is located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689 and our website address is www.pioneerdrlg.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 (the “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 customers’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of 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 customers 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 increasing oil and natural gas prices during 2010, exploration and production companies modestly increased their exploration and production spending for 2010 and industry rig utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. Increased natural gas production in the U.S. shale regions continues to depress natural gas prices, but oil prices continued to increase during 2011, resulting in continued increases in exploration and production spending during 2011 as compared to 2010. As a result, we experienced continued increases in industry rig utilization and revenue rates during 2011 as compared to 2010. We expect continued modest increases in exploration and production spending for 2012, which we expect will result in modest increases in industry equipment utilization and revenue rates in 2012, as compared to 2011. However, if for the remainder of 2012, oil prices remain steady but natural gas prices continue to decline below historically low levels, then industry equipment utilization and revenue rates could decrease.
For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A – “Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2011.


21



On April 20, 2012, the spot price for West Texas Intermediate crude oil was $103.05, the spot price for Henry Hub natural gas was $1.85 and the Baker Hughes U.S. land rig count was 1,904, a 9% increase from 1,754 on April 22, 2011. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic well service rig count for each of the last five years were:
 
Three months ended March 31, 2012
 
Years ended March 31,
 
 
2012
 
2011
 
2010
 
2009
 
2008
Oil (West Texas Intermediate)
$
102.99

 
$
99.03

 
$
83.05

 
$
70.42

 
$
86.35

 
$
82.50

Natural Gas (Henry Hub)
$
2.40

 
$
3.59

 
$
4.10

 
$
4.01

 
$
7.78

 
$
7.27

U.S. Land Rig Count
1,929

 
1,925

 
1,589

 
1,034

 
1,690

 
1,685

U.S. Well Service Rig Count
2,144

 
2,108

 
1,925

 
1,668

 
2,392

 
2,412

Since late 2009, increases primarily in oil prices have caused increases in exploration and production spending and the corresponding increases in drilling and well services activities are reflected by increases in the U.S. land rig counts and the U.S. well service rig counts in 2010, 2011 and 2012.
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. 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, but these projects are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which 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.
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 that operate in active drilling markets in the United States and 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 customers, expand our customer base in the areas in which we currently operate and further enhance our geographic diversification through selective international expansion. The key elements of this long-term strategy include:
Further Strengthen 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, and we intend to add ten new-build drilling rigs that will be operating in the shale plays in 2012. We also intend to continue adding capacity to our wireline, coiled tubing, and well servicing product offerings, which are well positioned to capitalize on increased shale development.


22



Increase our Exposure to Oil-Driven Drilling Activity. We have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and actively seeking contracts with oil-focused producers. As of April 20, 2012, approximately 89% of our working drilling rigs and 80% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas. We believe that our flexible rig fleet and production services assets allow us to target opportunities focused on both natural gas and oil.
Selectively Expand our International Operations. 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. We are continuously evaluating additional international expansion opportunities and intend to target international markets that share the favorable characteristics of our Colombian operations and which would allow us to deploy sufficient assets in order to realize economies of scale.
Continue Growth with Select Capital Deployment. We intend to invest in the growth of our business by continuing to strategically upgrade our existing assets, selectively engaging in new-build opportunities, and potentially making selective acquisitions. Our capital investment decisions are determined by an analysis of the projected return on capital employed, which is based on the terms of secured contracts whenever possible, and the investment must be consistent with our strategic objectives. We currently have term contracts for ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, for which we expect seven to begin working by the end of 2012, with the remaining three during the first quarter of 2013. On December 31, 2011, we acquired the coiled tubing service company, Go-Coil, to complement our existing production services offerings. We currently plan to expand our production services fleets by adding a total of 16 wireline units, 19 well service rigs and three coiled tubing units during 2012.
Liquidity and Capital Resources
Sources of Capital Resources
Our principal liquidity requirements have been for working capital needs, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $21.4 million as of March 31, 2012), cash generated from operations, and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).
In July 2009, 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. In November 2009, we obtained $24.0 million in net proceeds when we sold 3,820,000 shares of our common stock at $6.75 per share, less underwriters’ discounts and commissions, pursuant to a public offering under the $300 million shelf registration statement. In July 2011, we obtained $94.3 million in net proceeds when we sold 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under the $300 million shelf registration statement. On July 22, 2011, we used $57.0 million of these proceeds to pay down the debt balance outstanding under our Revolving Credit Facility. The current availability under the $300 million shelf registration statement for equity or debt is $174.2 million as of April 20, 2012. 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.
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 27, 2012, we had $20.0 million outstanding under our Revolving Credit Facility and $9.0 million in committed letters of credit, which resulted in borrowing availability of $221.0 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.


23



Uses of Capital Resources
During the three months ended March 31, 2012, we had $112.4 million of additions to our property and equipment. Currently, we expect to spend approximately $300 million to $330 million on capital expenditures during 2012. We expect the total capital expenditures for 2012 will be allocated approximately 70%