e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2009
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file no. 001-32693
Basic Energy Services, Inc.
(Exact name of registrant as specified in its charter)
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Delaware
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54-2091194 |
(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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500 W. Illinois, Suite 100
Midland, Texas
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79701 |
(Address of principal executive offices)
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(Zip code) |
(432) 620-5500
(Registrants telephone number, including area code)
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 þ 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 (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o 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. (Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o (Do not check if a smaller reporting company) | 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 o No þ
40,701,498 shares of the registrants Common Stock were outstanding as of July 24, 2009.
BASIC ENERGY SERVICES, INC.
Index to Form 10-Q
2
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
This quarterly report contains certain statements that are, or may be deemed to be,
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act.
We have based these forward-looking statements largely on our current expectations and projections
about future events and financial trends affecting the financial condition of our business. These
forward-looking statements are subject to a number of risks, uncertainties and assumptions,
including, among other things, the risk factors discussed in this quarterly report and other
factors, most of which are beyond our control.
The words believe, may, estimate, continue, anticipate, intend, plan, expect
and similar expressions are intended to identify forward-looking statements. All statements other
than statements of current or historical fact contained in this quarterly report are
forward-looking statements. Although we believe that the forward-looking statements contained in
this quarterly report are based upon reasonable assumptions, the forward-looking events and
circumstances discussed in this quarterly report may not occur and actual results could differ
materially from those anticipated or implied in the forward-looking statements.
Important factors that may affect our expectations, estimates or projections include:
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a decline in, or substantial volatility of, oil and gas prices, and any related changes
in expenditures by our customers; |
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the effects of future acquisitions on our business; |
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changes in customer requirements in markets or industries we serve; |
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competition within our industry; |
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general economic and market conditions; |
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our access to current or future financing arrangements; |
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our ability to replace or add workers at economic rates; and |
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environmental and other governmental regulations. |
Our forward-looking statements speak only as of the date of this quarterly report. Unless
otherwise required by law, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future events or otherwise.
This quarterly report includes market share and industry data and forecasts that we obtained
from internal company surveys (including estimates based on our knowledge and experience in the
industry in which we operate), market research, consultant surveys, publicly available information,
and industry publications and surveys. Industry surveys and publications, consultant surveys and
forecasts generally state that the information contained therein has been obtained from sources
believed to be reliable. Although we believe such information is accurate and reliable, we have not
independently verified any of the data from third party sources cited or used for our managements
industry estimates, nor have we ascertained the underlying economic assumptions relied upon
therein. For example, the number of onshore well servicing rigs in the U.S. could be lower than our
estimate to the extent our two larger competitors have continued to report as stacked rigs
equipment that is not actually complete or subject to refurbishment. Statements as to our position
relative to our competitors or as to market share refer to the most recent available data.
3
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Basic Energy Services, Inc.
Consolidated Balance Sheets
(in thousands, except share data)
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June 30, |
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December 31, |
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2009 |
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2008 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
134,304 |
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$ |
111,135 |
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Trade accounts receivable, net of allowance of $6,396 and $5,838, respectively |
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98,997 |
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172,930 |
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Accounts receivable related parties |
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138 |
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148 |
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Income tax receivable |
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27,052 |
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3,324 |
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Inventories |
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11,279 |
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11,937 |
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Prepaid expenses |
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4,615 |
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6,838 |
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Other current assets |
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5,648 |
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6,508 |
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Deferred tax assets |
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28,076 |
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11,081 |
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Total current assets |
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310,109 |
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323,901 |
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Property and equipment, net |
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714,560 |
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740,879 |
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Deferred debt costs, net of amortization |
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7,058 |
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5,132 |
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Goodwill |
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202,749 |
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Other intangible assets, net of amortization |
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34,381 |
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36,004 |
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Other assets |
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2,285 |
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2,046 |
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Total assets |
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$ |
1,068,393 |
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$ |
1,310,711 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
17,784 |
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$ |
28,291 |
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Accrued expenses |
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37,950 |
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47,139 |
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Current portion of long-term debt |
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28,316 |
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26,063 |
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Other current liabilities |
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401 |
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658 |
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Total current liabilities |
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84,451 |
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102,151 |
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Long-term debt |
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451,958 |
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454,260 |
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Deferred tax liabilities |
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135,079 |
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149,591 |
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Other long-term liabilities |
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9,686 |
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9,705 |
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Commitments and contingencies |
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Stockholders equity: |
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Preferred stock; $.01 par value; 5,000,000 shares authorized; none
designated or issued at June 30, 2009 and December 31, 2008, respectively |
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Common stock; $.01 par value; 80,000,000 shares authorized; 42,394,809 shares
issued; and 40,703,187 shares outstanding at June 30, 2009; 41,734,485 shares
issued; and 40,851,862 shares outstanding at December 31, 2008. |
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424 |
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417 |
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Additional paid-in capital |
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328,101 |
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325,785 |
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Retained earnings |
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72,642 |
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277,173 |
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Treasury stock, at cost, 1,691,622 and 882,623 shares at June 30, 2009 and
December 31, 2008, respectively |
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(13,948 |
) |
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(8,371 |
) |
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Total stockholders equity |
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387,219 |
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595,004 |
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Total liabilities and stockholders equity |
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$ |
1,068,393 |
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$ |
1,310,711 |
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See accompanying notes to consolidated financial statements.
4
Basic Energy Services, Inc.
Consolidated Statements of Operations and Comprehensive Income
(in thousands, except per share amounts)
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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(Unaudited) |
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(Unaudited) |
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Revenues: |
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Well servicing |
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$ |
36,399 |
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$ |
89,018 |
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$ |
85,213 |
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$ |
169,537 |
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Fluid services |
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49,088 |
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72,581 |
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114,065 |
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143,980 |
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Completion and remedial services |
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29,373 |
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79,579 |
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66,632 |
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148,037 |
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Contract drilling |
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3,988 |
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10,344 |
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7,626 |
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19,841 |
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Total revenues |
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118,848 |
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251,522 |
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273,536 |
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481,395 |
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Expenses: |
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Well servicing |
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27,825 |
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55,293 |
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64,742 |
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103,759 |
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Fluid services |
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35,381 |
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48,554 |
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79,968 |
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94,987 |
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Completion and remedial services |
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21,484 |
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42,651 |
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47,378 |
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78,439 |
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Contract drilling |
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|
3,338 |
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7,529 |
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|
6,607 |
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|
14,589 |
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General and administrative, including stock-based compensation
of $1,290 and $1,184 in three months ended June 30, 2009 and
2008, and $2,665 and $2,264 in the six months ended June 30, 2009
and 2008, respectively |
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27,424 |
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26,811 |
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56,503 |
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52,663 |
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Depreciation and amortization |
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|
32,413 |
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28,732 |
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65,150 |
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56,764 |
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(Gain) loss on disposal of assets |
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474 |
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(809 |
) |
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1,339 |
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(584 |
) |
Goodwill impairment |
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(82 |
) |
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204,014 |
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Total expenses |
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148,257 |
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208,761 |
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525,701 |
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400,617 |
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Operating income (loss) |
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(29,409 |
) |
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|
42,761 |
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(252,165 |
) |
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80,778 |
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Other income (expense): |
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Interest expense |
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(5,974 |
) |
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(6,453 |
) |
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(11,710 |
) |
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(13,802 |
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Interest income |
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173 |
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|
471 |
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|
393 |
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|
1,172 |
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Other income (expense) |
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|
118 |
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(6,469 |
) |
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|
252 |
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(6,431 |
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Income (loss) from continuing operations before income taxes |
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(35,092 |
) |
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30,310 |
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(263,230 |
) |
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61,717 |
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Income tax benefit (expense) |
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13,856 |
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(11,597 |
) |
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59,169 |
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(23,348 |
) |
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Net income (loss) |
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$ |
(21,236 |
) |
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$ |
18,713 |
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$ |
(204,061 |
) |
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$ |
38,369 |
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Earnings per share of common stock: |
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Basic |
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$ |
(0.54 |
) |
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$ |
0.46 |
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$ |
(5.13 |
) |
|
$ |
0.94 |
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Diluted |
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$ |
(0.54 |
) |
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$ |
0.45 |
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$ |
(5.13 |
) |
|
$ |
0.92 |
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See accompanying notes to consolidated financial statements.
5
Basic Energy Services, Inc.
Consolidated Statements of Stockholders Equity
(in thousands, except share data)
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Additional |
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Total |
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Common Stock |
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Paid-In |
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Treasury |
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Retained |
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Stockholders |
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Shares |
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Amount |
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Capital |
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Stock |
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Earnings |
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Equity |
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Balance December 31, 2008 |
|
|
41,734,485 |
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|
$ |
417 |
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|
$ |
325,785 |
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|
$ |
(8,371 |
) |
|
$ |
277,173 |
|
|
$ |
595,004 |
|
|
|
|
|
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|
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|
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Issuances of restricted stock |
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660,324 |
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|
7 |
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|
(7 |
) |
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|
431 |
|
|
|
(431 |
) |
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Amortization of share based
compensation |
|
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|
|
|
|
|
|
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|
2,640 |
|
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|
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|
2,640 |
|
Treasury stock issued as compensation
to Chairman of the Board |
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|
43 |
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|
(19 |
) |
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|
24 |
|
Purchase of treasury stock |
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|
|
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|
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|
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|
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(6,104 |
) |
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|
|
|
|
|
(6,104 |
) |
Exercise of stock options / vesting
of restricted stock |
|
|
|
|
|
|
|
|
|
|
(317 |
) |
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|
53 |
|
|
|
(20 |
) |
|
|
(284 |
) |
Net loss |
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|
|
|
|
|
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|
|
|
|
|
|
(204,061 |
) |
|
|
(204,061 |
) |
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|
|
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Balance June 30, 2009 (unaudited) |
|
|
42,394,809 |
|
|
$ |
424 |
|
|
$ |
328,101 |
|
|
$ |
(13,948 |
) |
|
$ |
72,642 |
|
|
$ |
387,219 |
|
|
|
|
|
|
|
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|
|
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|
See accompanying notes to consolidated financial statements.
6
Basic Energy Services, Inc.
Consolidated Statements of Cash Flows
(in thousands)
|
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Six Months Ended June 30, |
|
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|
2009 |
|
|
2008 |
|
|
|
(Unaudited) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(204,061 |
) |
|
$ |
38,369 |
|
Adjustments to reconcile net income to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
65,150 |
|
|
|
56,764 |
|
Goodwill impairment |
|
|
204,014 |
|
|
|
|
|
Accretion on asset retirement obligation |
|
|
73 |
|
|
|
63 |
|
Change in allowance for doubtful accounts |
|
|
558 |
|
|
|
(483 |
) |
Amortization of deferred financing costs |
|
|
630 |
|
|
|
482 |
|
Non-cash compensation |
|
|
2,665 |
|
|
|
2,264 |
|
(Gain) loss on disposal of assets |
|
|
1,339 |
|
|
|
(584 |
) |
Deferred income taxes |
|
|
(31,507 |
) |
|
|
7,666 |
|
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
73,385 |
|
|
|
(23,934 |
) |
Inventories |
|
|
658 |
|
|
|
402 |
|
Prepaid expenses and other current assets |
|
|
3,380 |
|
|
|
5,177 |
|
Other assets |
|
|
(219 |
) |
|
|
(198 |
) |
Accounts payable |
|
|
(10,507 |
) |
|
|
991 |
|
Excess tax expense (benefit) from exercise of employee stock
options / vesting of restricted stock |
|
|
317 |
|
|
|
(1,583 |
) |
Income tax payable |
|
|
(24,213 |
) |
|
|
1,015 |
|
Other liabilities |
|
|
(243 |
) |
|
|
(3,414 |
) |
Accrued expenses |
|
|
(8,370 |
) |
|
|
4,331 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
73,049 |
|
|
|
87,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Purchase of property and equipment |
|
|
(25,187 |
) |
|
|
(45,023 |
) |
Proceeds from sale of assets |
|
|
1,912 |
|
|
|
6,470 |
|
Payments for other long-term assets |
|
|
(995 |
) |
|
|
(2,048 |
) |
Payments for businesses, net of cash acquired |
|
|
(1,190 |
) |
|
|
(51,239 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(25,460 |
) |
|
|
(91,840 |
) |
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Payments of debt |
|
|
(15,475 |
) |
|
|
(10,874 |
) |
Purchase of treasury stock |
|
|
(6,104 |
) |
|
|
(1,149 |
) |
Excess tax (expense) benefit from exercise of employee stock
options / vesting of restricted stock |
|
|
(317 |
) |
|
|
1,583 |
|
Tax withholding from exercise of stock options |
|
|
(5 |
) |
|
|
(842 |
) |
Exercise of employee stock options |
|
|
37 |
|
|
|
1,637 |
|
Deferred loan costs and other financing activities |
|
|
(2,556 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(24,420 |
) |
|
|
(9,645 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and equivalents |
|
|
23,169 |
|
|
|
(14,157 |
) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents beginning of period |
|
|
111,135 |
|
|
|
91,941 |
|
|
|
|
|
|
|
|
Cash and cash equivalents end of period |
|
$ |
134,304 |
|
|
$ |
77,784 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
7
BASIC ENERGY SERVICES, INC.
Notes to Consolidated Financial Statements
June 30, 2009 (unaudited)
1. Basis of Presentation and Nature of Operations
Basis of Presentation
The accompanying unaudited consolidated financial statements of Basic Energy Services, Inc.
and subsidiaries (Basic or the Company) have been prepared in accordance with accounting
principles generally accepted in the United States for interim financial reporting. Accordingly,
they do not include all of the information and footnotes required by accounting principles
generally accepted in the United States for complete financial statements. In the opinion of
management, all adjustments considered necessary for a fair presentation have been made in the
accompanying unaudited financial statements.
Nature of Operations
Basic Energy Services, Inc. provides a range of well site services to oil and gas drilling and
producing companies, including well servicing, fluid services, completion and remedial services,
and contract drilling. These services are primarily provided by Basics fleet of equipment. Basics
operations are concentrated in the major United States onshore oil and gas producing regions in
Texas, New Mexico, Oklahoma, Arkansas, Kansas and Louisiana, and the Rocky Mountain states.
2. Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Basic and its
wholly-owned subsidiaries. Basic has no interest in any other organization, entity, partnership, or
contract that could require any evaluation under FASB Interpretation No. 46R or Accounting Research
Bulletin No. 51. All intercompany transactions and balances have been eliminated.
Estimates and Uncertainties
Preparation of the accompanying consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America requires management to
make estimates and assumptions that affect the reported amount of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Areas where critical accounting estimates are made by
management include:
|
|
|
Depreciation and amortization of property and equipment and intangible assets |
|
|
|
|
Impairment of property and equipment, goodwill and intangible assets |
|
|
|
|
Allowance for doubtful accounts |
|
|
|
|
Litigation and self-insured risk reserves |
|
|
|
|
Fair value of assets acquired and liabilities assumed |
|
|
|
|
Stock-based compensation |
|
|
|
|
Income taxes |
|
|
|
|
Asset retirement obligations |
8
Revenue Recognition
Well Servicing Well servicing consists primarily of maintenance services, workover
services, completion services and plugging and abandonment services. Basic recognizes revenue when
services are performed, collection of the relevant receivables is probable, persuasive evidence of
an arrangement exists and the price is fixed or determinable. Basic prices well servicing by the
hour or by the day of service performed.
Fluid Services Fluid services consists primarily of the sale, transportation, storage and
disposal of fluids used in drilling, production and maintenance of oil and natural gas wells, and
well site construction and maintenance services. Basic recognizes revenue when services are
performed, collection of the relevant receivables is probable, persuasive evidence of an
arrangement exists and the price is fixed or determinable. Basic prices fluid services by the job,
by the hour or by the quantities sold, disposed of or hauled.
Completion and Remedial Services Completion and remedial services consists primarily of
pressure pumping services, focused on cementing, acidizing and fracturing, nitrogen units, coiled
tubing units, and rental and fishing tools. Basic recognizes revenue when services are performed,
collection of the relevant receivables is probable, persuasive evidence of an arrangement exists
and the price is fixed or determinable. Basic prices completion and remedial services by the hour,
day, or project depending on the type of service performed. When Basic provides multiple services
to a customer, revenue is allocated to the services performed based on the fair values of the
services.
Contract Drilling Contract drilling consists primarily of drilling wells to a specified
depth using shallow and medium depth rigs. Basic recognizes revenues based on either a daywork
contract, in which an agreed upon rate per day is charged to the customer, or a footage contract,
in which an agreed upon rate is charged per the number of feet drilled.
Taxes assessed on sales transactions are presented on a net basis and are not included in
revenue.
Inventories
For Rental and Fishing Tools, inventories consisting mainly of grapples and drill
bits are stated at the lower of cost or market, with cost being determined on the average cost
method. Other inventories, consisting mainly of rig components, repair parts, drilling and
completion materials and gravel, are held for use in the operations of Basic and are stated at the
lower of cost or market, with cost being determined on the first-in, first-out (FIFO) method.
Property and Equipment
Property and equipment are stated at cost or at estimated fair value at acquisition date if
acquired in a business combination. Expenditures for repairs and maintenance are charged to expense
as incurred and additions and improvements that significantly extend the lives of the assets are
capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated
depreciation and amortization are removed from the related accounts and any gain or loss is
reflected in operations. All property and equipment are depreciated or amortized (to the extent of
estimated salvage values) on the straight-line method. The components of a well servicing rig
generally require replacement or refurbishment during the well servicing rigs life and are
depreciated over their estimated useful lives, which ranges from 3 to 15 years. The costs of the
original components of a purchased or acquired well servicing rig are not maintained separately
from the base rig.
Impairments
In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144), long-lived assets, such as
property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for
impairment at a minimum annually, or whenever, in managements judgment, events or changes in
circumstances indicate that the carrying amount of such assets may not be recoverable.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of
such assets to estimated undiscounted future cash flows expected to be generated by the assets.
Expected future cash flows and carrying values are aggregated at their lowest identifiable level.
If the carrying amount of such assets exceeds its estimated future cash flows, an impairment charge
is recognized by the amount by which the carrying amount of such assets exceeds the fair value of
the assets. Assets to be disposed of would be separately presented in the consolidated balance
sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no
longer depreciated. The assets and liabilities, if material, of a disposed group classified as held
for sale would be presented separately in the appropriate asset and
9
liability sections of the consolidated balance sheet. These assets are normally sold within a
short period of time through a third party auctioneer.
Basics goodwill is considered to have an indefinite useful economic life and is not
amortized. Basic assesses impairment of its goodwill annually as of December 31 or on an interim
basis if events or circumstances indicate that the fair value of the asset has decreased below its
carrying value. SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142), requires a
two-step process for testing impairment. First, the fair value of each reporting unit is compared
to its carrying value to determine whether an indication of impairment exists. If impairment is
indicated, then the fair value of the reporting units goodwill is determined by allocating the
units fair value to its assets and liabilities (including any unrecognized intangible assets) as
if the reporting unit had been acquired in a business combination. The amount of impairment for
goodwill is measured as the excess of its carrying value over its fair value.
In accordance with SFAS No. 142, the Company performed an assessment of goodwill as of March
31, 2009. A triggering event requiring this assessment was deemed to occur because the oil and
gas services industry continued to decline in the first quarter and the Companys common stock
price declined by 50% from December 31, 2008 to March 31, 2009. For SFAS No. 142 Step One testing
purposes, the Company tested three reporting units for goodwill impairment: well servicing, fluid
services, and completion and remedial services. The Companys contract drilling reporting unit does
not carry any goodwill, and is not subject to the test.
To estimate the fair value of the reporting units, the Company used a weighting of the
discounted cash flow method and the public company guideline method of determining fair value of a
business unit. The Company weighted the discounted cash flow method 85% and public company
guideline method 15%, due to differences between the Companys reporting units and the peer
companies size, profitability and diversity of operations. In order to validate the reasonableness
of the estimated fair values obtained for the reporting units, a reconciliation of fair value to
market capitalization was performed for each unit on a stand-alone basis. A control premium,
derived from market transaction data, was used in this reconciliation to ensure that fair values
were reasonably stated in conjunction with the Companys capitalization. The measurement date for
the Companys common stock price and market capitalization was the closing price on March 31, 2009.
Based on the results of SFAS No. 142 Step One, impairment was indicated in all three of the
assessed reporting units. As such, the Company was required to perform Step Two assessment on all
three of the reporting units. Step Two requires the allocation of the estimated fair value to the
tangible and intangible assets and liabilities of the respective unit. This assessment indicated
that $204.1 million was considered impaired as of March 31, 2009. This non-cash charge eliminated
all of the Companys goodwill.
Additionally, in accordance with SFAS No. 144, the Company performed an assessment of the
Companys long-lived assets for impairment. This assessment is performed as a comparison of the
undiscounted future cash flows of each reporting unit to the carrying value of the assets in each
unit. No impairment was indicated by this test.
Deferred Debt Costs
Basic capitalizes certain costs in connection with obtaining its borrowings, such as lenders
fees and related attorneys fees. These costs are amortized to interest expense using the effective
interest method.
Deferred debt costs were approximately $10.1 million net of accumulated amortization of $3.1
million and $7.6 million net of accumulated amortization of $2.4 million at June 30, 2009 and
December 31, 2008, respectively. Amortization of deferred debt costs totaled approximately $391,000
and $242,000 for the three months ended June 30, 2009 and 2008, respectively. For the six months
ended June 30, 2009 and 2008, amortization of deferred debt costs totaled approximately $630,000
and $482,000, respectively.
Goodwill and Other Intangible Assets
SFAS No. 142 eliminates the amortization of goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means
will continue to be amortized over their useful lives. Goodwill and other intangible assets not
subject to amortization are tested for impairment annually or more frequently if events or changes
in circumstances indicate that the asset might be impaired. Basic completed its assessment of
goodwill impairment as of the date of adoption and completed a subsequent annual impairment
assessment as of December 31 each year thereafter.
As of June 30, 2009, Basic had no goodwill. All of the Companys goodwill was considered
impaired as of March 31, 2009.
10
Intangible
assets subject to amortization under SFAS No. 142 consist of customer relationships
and non-compete agreements. The gross carrying amount of customer relationships subject to
amortization was $35.4 million as of June 30, 2009 and December 31, 2008. The gross carrying amount
of non-compete agreements subject to amortization totaled approximately $4.2 million and $4.4
million at June 30, 2009 and December 31, 2008, respectively. Accumulated amortization related to
these intangible assets totaled approximately $5.3 million and $3.8 million at June 30, 2009 and
December 31, 2008, respectively. Amortization expense for the three months ended June 30, 2009 and
2008 was approximately $803,000 and $636,000, respectively. Amortization expense for the six months
ended June 30, 2009 and 2008 was approximately $1.6 million and $1.3 million, respectively Other
intangibles net of accumulated amortization allocated to reporting units as of June 30, 2009 were
$376,000, $3.1 million, $25.2 million and $5.7 million for well servicing, fluid services,
completion and remedial services, and contract drilling, respectively.
Customer relationships are amortized over a 15-year life. Non-compete agreements are amortized
over a five-year life.
Stock-Based Compensation
Basic accounts for stock-based compensation based on SFAS No. 123 (revised 2004), Share Based
Payment (SFAS No. 123R). Options issued are valued on the grant date using the
Black-Scholes-Merton option-pricing model and all awards are adjusted for an expected forfeiture
rate. Awards are amortized over the vesting period. Compensation expense of the unvested portion of
awards granted as a private company and outstanding as of January 1, 2006 will be based upon the
intrinsic value method calculated under Accounting Principles Board Opinion No. 25, Accounting for
Stock Issued to Employees (APB No. 25).
Income Taxes
Basic accounts for income taxes based upon SFAS No. 109, Accounting for Income Taxes (SFAS
No. 109). Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future
tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities
are measured using statutory tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rate is recognized in the period that includes the
statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is
more likely than not that the benefit of deferred tax assets will not be realized.
Basic
recognized an effective tax benefit rate of 22% in the first six
months of 2009 compared to a tax rate of 38% in the first six months
of 2008. The lower effective tax rate in the first six months of 2009
was primarily due to the $204.0 million goodwill impairment charge.
The tax deductibility of the impairment charge was determined by the
taxable basis of the goodwill considered to be impaired. A portion of
the Companys goodwill was not tax-deductible.
Interest charges are recorded in interest expense and penalties are recorded in income tax
expense.
Concentrations of Credit Risk
Financial instruments, which potentially subject Basic to concentration of credit risk,
consist primarily of temporary cash investments and trade receivables. Basic restricts investment
of temporary cash investments to financial institutions with high credit standing. Basics customer
base consists primarily of multi-national and independent oil and natural gas producers. Basic
performs ongoing credit evaluations of its customers but generally does not require collateral on
its trade receivables. Credit risk is considered by management to be limited due to the large
number of customers comprising its customer base. Basic maintains an allowance for potential credit
losses on its trade receivables, and such losses have been within managements expectations.
Basic did not have any one customer which represented 10% or more of consolidated revenue
during the three months ended June 30, 2009 or 2008.
Asset Retirement Obligations
As of January 1, 2003, Basic adopted SFAS No. 143, Accounting for Asset Retirement
Obligation (SFAS No. 143). SFAS No. 143 requires Basic to record the fair value of an asset
retirement obligation as a liability in the period in which it incurs a legal obligation associated
with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the
asset depreciating it over the life of the asset. Subsequent to the initial measurement of the
asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the
passage of time, changes in the estimated future cash flows underlying the obligation, acquisition
or construction of assets, and settlements of obligations.
11
Environmental
Basic is subject to extensive federal, state and local environmental laws and regulations.
These laws, which are constantly changing, regulate the discharge of materials into the environment
and may require Basic to remove or mitigate the adverse environmental effects of disposal or
release of petroleum, chemical and other substances at various sites. Environmental expenditures
are expensed or capitalized depending on the future economic benefit. Expenditures that relate to
an existing condition caused by past operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental
assessment and/or remediation is probable and the costs can be reasonably estimated.
Litigation and Self-Insured Risk Reserves
Basic estimates its reserves related to litigation and self-insured risks based on the facts
and circumstances specific to the litigation and self-insured claims and its past experience with
similar claims in accordance with SFAS No. 5 Accounting for Contingencies. Basic maintains
accruals in the consolidated balance sheets to cover self-insurance retentions (See note 6).
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157,
Fair Value Measurements (SFAS No. 157), which became effective for financial assets and
liabilities of the Company on January 1, 2008 and became effective for non-financial assets and
liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a
framework for measuring fair value and expands disclosures about fair value measurements. SFAS No.
157 does not require any new fair value measurements but would apply to assets and liabilities that
are required to be recorded at fair value under other accounting standards. This standard was
adopted for financial assets and liabilities as of January 1, 2008 and was adopted for
non-financial assets and liabilities, including fair value measurements for asset impairments,
goodwill and intangible asset impairments, purchase price allocations and asset retirement
obligations on January 1, 2009. The adoption of this standard did not have any impact on the fair
value of any of the Companys financial assets or liabilities. For further information, see note
13.
In December 2007, the FASB issued SFAS No. 141R, Business Combinations (SFAS No. 141R),
which became effective for the Company on January 1, 2009. This Statement requires an acquirer to
recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree at the acquisition date at their fair values as of that date. An acquirer is required to
recognize assets or liabilities arising from all other contingencies (contractual contingencies) as
of the acquisition date, measured at their acquisition-date fair values, only if it is more likely
than not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6,
Elements of Financial Statements. Any acquisition related costs are to be expensed instead of
capitalized. The impact to the Company from the adoption of SFAS No. 141R in 2009 will vary
acquisition by acquisition.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements (SFAS No. 160), which became effective for the Company on January 1, 2009.
This standard establishes accounting and reporting standards for ownership interests in
subsidiaries held by parties other than the parent, the amount of consolidated net income
attributable to the parent and to the noncontrolling interest, changes in a parents ownership
interest and the valuation of retained non-controlling equity investments when a subsidiary is
deconsolidated. The Statement also establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the interests of the parent and the
interests of the non-controlling owners. This pronouncement has not had a significant impact on the
Companys results of operation or consolidated financial position since the Company does not have
any noncontrolling interests.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which became effective for the Company on January 1, 2009.
This standard improves financial reporting for derivative instruments and hedging activities by
requiring enhanced disclosures to expand on these instruments effects on a companys financial
position, financial performance and cash flows. This pronouncement did not have any impact on the
Companys results of operation or consolidated financial position since the Company does not have
any derivative instruments.
In April 2008, the FASB issued FASB Staff Position SFAS No. 142-3, Determination of Useful
Life of Intangible Assets (FSP No. 142-3). FSP No. 142-3 amends the factors that should be
considered in developing the renewal or extension assumptions used to determine the useful life of
a recognized intangible asset under SFAS No. 142. FSP No. 142-3 is effective for fiscal years
beginning after December 15, 2008. This pronouncement has not had a significant impact on the
results of operation or consolidated financial position of the Company.
12
In June 2008, the FASB issued FASB Staff Position EITF 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF
03-6-1). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions
are participating securities prior to vesting and, therefore, need to be included in the earnings
allocation in computing earnings per share (EPS) under the two-class method described in
paragraphs 60 and 61 of SFAS No. 128, Earnings Per Share. FSP EITF 03-6-1 is effective for
financial statements issued for fiscal years and interim periods beginning after December 15, 2008
and requires retrospective adjustment for all comparable prior periods presented. FSP EITF 03-6-1
has not had a significant impact on the Companys results of operation or consolidated financial
position since the Company does not have any participating securities.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS No. 165), which became
effective for the Company on April 1, 2009. This standard establishes principles and requirements
for disclosure of subsequent events. It establishes the period after the balance sheet date during
which events or transactions are to be evaluated for potential disclosure. It also establishes the
circumstances under which an entity shall recognize events or transactions occurring after the
balance sheet date. The adoption of this standard requires the
Company to disclose the date through which subsequent events have
been reviewed.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and
the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement no. 162
(SFAS No. 168), which becomes effective for the Company on July 1, 2009. SFAS No. 168 establishes
the FASB Accounting Standards Codification as the source of authoritative accounting principles
recognized by the FASB to be applied by nongovernmental entities in the preparation of financial
statements in conformity with GAAP. SFAS No. 168 is not expected to change GAAP and will not have
a material impact on the Companys consolidated financial statements.
3. Acquisitions
In the first six months of 2009 Basic did not acquire any businesses. In 2008, Basic acquired
either substantially all of the assets or all of the outstanding capital stock of each of the
following businesses, each of which was accounted for using the purchase method of accounting (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Total Cash Paid (net of |
|
|
Closing Date |
|
cash acquired) |
|
|
|
|
|
|
|
Xterra Fishing and Rental Tools Co.
|
|
January 28, 2008
|
|
$ |
21,473 |
|
Lackey Construction, LLC
|
|
January 30, 2008
|
|
|
4,328 |
|
B&S Disposal, LLC and B&S Equipment, Ltd
|
|
April 30, 2008
|
|
|
7,071 |
|
Triple N Services, Inc.
|
|
May 27, 2008
|
|
|
17,315 |
|
Azurite Services Company, Inc., Azurite Leasing Company, LLC
and Freestone Disposal, L.P. (collectively, Azurite)
|
|
September 26, 2008
|
|
|
60,977 |
|
|
|
|
|
|
|
|
Total 2008
|
|
|
|
$ |
111,164 |
|
|
|
|
|
|
|
|
The operations of each of the acquisitions listed above are included in Basics statement of
operations as of each respective closing date. The acquisition of Azurite in 2008 has been deemed
material and is discussed below in further detail.
Contingent Earn-out Arrangements and Purchase Price Allocations
Contingent earn-out arrangements are generally arrangements entered into on certain
acquisitions to encourage the owner/manager to continue operating and building the business after
the purchase transaction. The contingent earn-out arrangements of the related acquisitions are
generally linked to certain financial measures and performance of the assets acquired in the
various acquisitions. All amounts paid or reasonably accrued for related to the contingent earn-out
payments are reflected as increases to the goodwill associated with the acquisition or compensation
expense depending on the terms and conditions of the earn-out arrangement.
13
Azurite
On September 26, 2008, Basic acquired substantially all of the assets of Azurite Services
Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, L.P. (collectively, Azurite)
for $61.0 million in cash. This acquisition operates in our fluid services line of business and
expands our operations in the East Texas markets. The following table summarizes the preliminary
estimated fair value of the assets acquired and liabilities assumed at the date of acquisition for
Azurite (in thousands):
|
|
|
|
|
Property and Equipment |
|
$ |
53,127 |
|
Intangible Assets (1) |
|
|
1,862 |
|
Goodwill (2) |
|
|
5,988 |
|
|
|
|
|
|
|
|
|
|
Total Assets Acquired |
|
$ |
60,977 |
|
|
|
|
|
|
|
|
(1) |
|
Consists of customer relationships of $1,832, amortizable over 15 years, and non-compete
agreements of $30, amortizable over five years. |
|
(2) |
|
All of which is expected to be deductible for tax purposes. |
The following unaudited pro forma results of operations have been prepared as though the
Azurite acquisition had been completed on January 1, 2008. Pro forma amounts are based on the
purchase price allocations of the significant acquisitions and are not necessarily indicative of
the results that may be reported in the future (in thousands, except per share data).
|
|
|
|
|
|
|
Six Months Ended |
|
|
June 30, 2008 |
Revenues |
|
$ |
504,149 |
|
|
|
|
|
|
Net income |
|
$ |
40,020 |
|
|
|
|
|
|
Earnings per common share basic |
|
$ |
0.98 |
|
Earnings per common share diluted |
|
$ |
0.96 |
|
Basic does not believe the pro forma effect of the remainder of the acquisitions completed in
2008 are material, either individually or when aggregated, to the reported results of operations.
14
4. Property and Equipment
Property and equipment consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Land |
|
$ |
5,275 |
|
|
$ |
4,689 |
|
Buildings and improvements |
|
|
31,913 |
|
|
|
29,913 |
|
Well service units and equipment |
|
|
385,750 |
|
|
|
379,167 |
|
Fluid services equipment |
|
|
138,671 |
|
|
|
136,814 |
|
Brine and fresh water stations |
|
|
10,443 |
|
|
|
10,203 |
|
Frac/test tanks |
|
|
117,514 |
|
|
|
128,845 |
|
Pressure pumping equipment |
|
|
169,636 |
|
|
|
156,406 |
|
Construction equipment |
|
|
25,475 |
|
|
|
22,483 |
|
Contract drilling equipment |
|
|
60,467 |
|
|
|
60,340 |
|
Disposal facilities |
|
|
55,566 |
|
|
|
49,878 |
|
Vehicles |
|
|
39,998 |
|
|
|
41,129 |
|
Rental equipment |
|
|
37,317 |
|
|
|
36,898 |
|
Aircraft |
|
|
4,119 |
|
|
|
4,119 |
|
Other |
|
|
29,350 |
|
|
|
21,758 |
|
|
|
|
|
|
|
|
|
|
|
1,111,494 |
|
|
|
1,082,642 |
|
Less accumulated depreciation and amortization |
|
|
396,934 |
|
|
|
341,763 |
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
714,560 |
|
|
$ |
740,879 |
|
|
|
|
|
|
|
|
Basic is obligated under various capital leases for certain vehicles and equipment that expire
at various dates during the next five years. The gross amount of property and equipment and related
accumulated amortization recorded under capital leases and included above consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Light vehicles |
|
$ |
26,572 |
|
|
$ |
30,141 |
|
Well service units and equipment |
|
|
1,713 |
|
|
|
1,194 |
|
Fluid services equipment |
|
|
56,516 |
|
|
|
56,010 |
|
Pressure pumping equipment |
|
|
27,276 |
|
|
|
20,492 |
|
Construction equipment |
|
|
1,034 |
|
|
|
3,679 |
|
Software |
|
|
13,659 |
|
|
|
9,464 |
|
Other |
|
|
|
|
|
|
705 |
|
|
|
|
|
|
|
|
|
|
|
126,770 |
|
|
|
121,685 |
|
Less accumulated amortization |
|
|
38,018 |
|
|
|
37,370 |
|
|
|
|
|
|
|
|
|
|
$ |
88,752 |
|
|
$ |
84,315 |
|
|
|
|
|
|
|
|
Amortization of assets held under capital leases of approximately $5.1 million and $3.2
million for the three months ended June 30, 2009 and 2008 and $10.1 million and $6.6 million for
the six months ended June 30, 2009 and 2008, respectively, is included in depreciation and
amortization expense in the consolidated statements of operations.
15
5. Long-Term Debt
Long-term debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Credit Facilities: |
|
|
|
|
|
|
|
|
Revolver |
|
$ |
180,000 |
|
|
$ |
180,000 |
|
7.125% Senior Notes |
|
|
225,000 |
|
|
|
225,000 |
|
Capital leases and other notes |
|
|
75,274 |
|
|
|
75,323 |
|
|
|
|
|
|
|
|
|
|
|
480,274 |
|
|
|
480,323 |
|
Less current portion |
|
|
28,316 |
|
|
|
26,063 |
|
|
|
|
|
|
|
|
|
|
$ |
451,958 |
|
|
$ |
454,260 |
|
|
|
|
|
|
|
|
Senior Notes
On April 12, 2006, Basic issued $225.0 million of 7.125% Senior Notes due April 2016 in a
private placement. Proceeds from the sale of the Senior Notes were used to retire the outstanding
balance on the $90.0 million Term B Loan and to pay down approximately $96.0 million under the
revolving credit facility, which amounts may be reborrowed to fund future acquisitions or for
general corporate purposes. Interest payments on the Senior Notes are due semi-annually, on April
15 and October 15. The Senior Notes are unsecured. Under the terms of the sale of the Senior Notes,
Basic was required to take appropriate steps to offer to exchange other Senior Notes with the same
terms that have been registered with the Securities and Exchange Commission for the private
placement Senior Notes. Basic completed the exchange offer for all of the Senior Notes on October
16, 2006.
The Senior Notes are redeemable at the option of Basic on or after April 15, 2011 at the
specified redemption price as described in the Indenture. Prior to April 15, 2011, Basic may redeem
the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount
of the Senior Notes redeemed plus the Applicable Premium as defined in the Indenture.
Following a change of control, as defined in the Indenture, Basic will be required to make an
offer to repurchase all or any portion of the Senior Notes at a purchase price of 101% of the
principal amount, plus accrued and unpaid interest to the date of repurchase.
Pursuant to the Indenture, Basic is subject to covenants that limit the ability of Basic and
its restricted subsidiaries to, among other things: incur additional indebtedness, pay dividends or
repurchase or redeem capital stock, make certain investments, incur liens, enter into certain types
of transactions with affiliates, limit dividends or other payments by restricted subsidiaries, and
sell assets or consolidate or merge with or into other companies. These limitations are subject to
a number of important qualifications and exceptions set forth in the Indenture. Basic was in
compliance with the restrictive covenants at June 30, 2009. In the event of a default on the Credit
Facility the trustee or the holders of at least 25% in aggregate principal amount of the Senior
Notes then outstanding may declare all of the amounts outstanding under the Senior Notes to be due
and payable immediately.
As part of the issuance of the above-mentioned Senior Notes, Basic incurred debt issuance
costs of approximately $4.6 million, which are being amortized to interest expense using the
effective interest method over the term of the Senior Notes.
The Senior Notes are jointly and severally guaranteed by Basic and all of its restricted
subsidiaries. Basic Energy Services, Inc., the ultimate parent company, does not have any
independent operating assets or operations. Subsidiaries other than the restricted subsidiaries
that are guarantors are minor.
Credit Facility
On May 4, 2009, Basic entered into Amendment and Consent No. 1 (the Amendment) to its Fourth
Amended and Restated Credit Agreement, dated February 6, 2007 (the Existing Credit Agreement, and
as amended by the Amendment, the Credit Facility).
Under the Credit Facility, Basic Energy Services, Inc. is the sole borrower and each of our
subsidiaries is a subsidiary guarantor. The Credit Facility provides for an aggregate $225 million
revolving line of credit (the Revolver). The Credit Facility includes provisions allowing Basic
to request an increase in commitments of up to $100.0 million aggregate principal amount subject to
16
meeting certain tangible value requirements and subject to lender participation at the time of the
request. The commitment under the Revolver provides for (1) the borrowing of funds, (2) the
issuance of up to $30 million of letters of credit and (3) $2.5 million of swing-line loans.
Under the Credit Facility, certain revolving loans are reclassified as (i) Tranche A Revolving
Loans, which have the same maturity date as that of revolving loans under the Existing Credit
Agreement (December 15, 2010), and (ii) Tranche B Revolving Loans, which have an extended maturity
date of January 31, 2012. Revolving lenders are reclassified into two groups: those who agreed to
extend the maturity date for their revolving commitments are deemed Tranche B Revolving Lenders,
and the other revolving lenders are deemed Tranche A Revolving Lenders. The amount of commitments
under the Tranche A Revolving Loans is $80 million and the amount under the Tranche B Revolving
Loans is $145 million.
For Tranche A Revolving Loans and Tranche B Revolving Loans, Alternative Base Rate loans (ABR
Loans) bear interest at the highest of (i) the banks prime rate, (ii) the federal funds rate plus
0.50% per year, and (iii) the adjusted LIBOR rate for an interest period of one month beginning on
the day of the ABR Loan plus 100 basis points, plus an applicable margin. The applicable margin for
ABR Loans ranges from 0.25% to 0.50% for Tranche A Revolving Loans and ranges from 2.50% to 3.50%
for Tranche B Revolving Loans. The applicable margin for Eurodollar revolving loans with respect to
any Tranche B Revolving Loan ranges from 3.50% to 4.50%. Furthermore, the applicable commitment fee
for the unused portion of any Tranche B revolving commitments, based on average daily unused
amounts, is 1.0% per annum, as compared to 0.375% per annum for Tranche A revolving commitments.
At June 30, 2009, Basic had $180.0 million of borrowings, and $16.2 million of letters of
credit and no swing-line loans outstanding under the Revolver and remaining availabilty of $28.8
million.
Pursuant to the Credit Facility, Basic must apply proceeds from certain specified events to
reduce principal outstanding borrowings under the Revolver, including (a) assets sales greater than
$2.0 million individually or $7.5 million in the aggregate on an annual basis, (b) 100% of the net
cash proceeds from any debt issuance, including certain permitted unsecured senior or senior
subordinated debt, but excluding certain other permitted debt issuances and (c) 50% of the net cash
proceeds from any equity issuance (including equity issued upon the exercise of any warrant or
option).
The Credit Facility contains various restrictive covenants and compliance requirements, which
include (a) limitations on the incurrence of additional indebtedness, (b) restrictions on mergers,
sales or transfer of assets without the lenders consent (c) limitations on dividends and
distributions and (d) various financial covenants, including (1) a maximum leverage ratio of 3.75
to 1.00 on the effective date of the Amendment and thereafter, and (2) a minimum interest coverage
ratio of 3.00 to 1.00. At June 30, 2009, Basic was in compliance with its covenants.
Other Debt
Basic has a variety of other capital leases and notes payable outstanding that are generally
customary in its business. None of these debt instruments are individually material.
See note 14 for discussion of secured senior notes offering.
Basics interest expense consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Cash payments for interest |
|
$ |
12,263 |
|
|
$ |
12,935 |
|
Commitment and other fees paid |
|
|
157 |
|
|
|
51 |
|
Amortization of debt issuance costs |
|
|
630 |
|
|
|
482 |
|
Change in accrued interest |
|
|
(1,345 |
) |
|
|
51 |
|
Other |
|
|
5 |
|
|
|
283 |
|
|
|
|
|
|
|
|
|
|
$ |
11,710 |
|
|
$ |
13,802 |
|
|
|
|
|
|
|
|
17
6. Commitments and Contingencies
Environmental
Basic is subject to various federal, state and local environmental laws and regulations that
establish standards and requirements for protection of the environment. Basic cannot predict the
future impact of such standards and requirements which are subject to change and can have
retroactive effectiveness. Basic continues to monitor the status of these laws and regulations.
Management believes that the likelihood of any of these items resulting in a material adverse
impact to Basics financial position, liquidity, capital resources or future results of operations
is remote.
Currently, Basic has not been fined, cited or notified of any environmental violations that
would have a material adverse effect upon its financial position, liquidity or capital resources.
However, management does recognize that by the very nature of its business, material costs could be
incurred in the near term to bring Basic into total compliance. The amount of such future
expenditures is not determinable due to several factors including the unknown magnitude of possible
contamination, the unknown timing and extent of the corrective actions which may be required, the
determination of Basics liability in proportion to other responsible parties and the extent to
which such expenditures are recoverable from insurance or indemnification.
Litigation
From time to time, Basic is a party to litigation or other legal proceedings that Basic
considers to be a part of the ordinary course of business. Basic is not currently involved in any
legal proceedings that it considers probable or reasonably possible, individually or in the
aggregate, to result in a material adverse effect on its financial condition, results of operations
or liquidity.
Self-Insured Risk Accruals
Basic is self-insured up to retention limits as it relates to workers compensation and
medical and dental coverage of its employees. Basic generally maintains no physical property damage
coverage on its workover rig fleet, with the exception of certain of its 24-hour workover rigs and
newly manufactured rigs. Basic has deductibles per occurrence for workers compensation and medical
and dental coverage of $375,000 and $250,000, respectively. Basic has lower deductibles per
occurrence for automobile liability and general liability. Basic maintains accruals in the
accompanying consolidated balance sheets related to self-insurance retentions by using third-party
data and claims history.
At June 30, 2009 and December 31, 2008, self-insured risk accruals for medical and dental
coverage totaled approximately $14.6 million net of a $49,000 receivable and $15.4 million net of a
$992,000 receivable, respectively.
7. Stockholders Equity
Common Stock
At June 30, 2009 and December 31, 2008, Basic had 80,000,000 shares of common stock, par value
$.01 per share, authorized.
During the year ended December 31, 2008, Basic issued 447,255 shares of newly-issued common
stock and 138,675 shares of treasury stock for the exercise of stock options.
In March 2008, Basic granted various employees 361,700 unvested shares of common stock which
vest over a five year period. Also, in March 2008, Basic granted the Chairman of the Board 4,000
shares of common stock which vested immediately in lieu of annual cash director fees. In October
2008, Basic granted a vice president 5,000 shares of restricted common stock which vest over a
three year period.
In March 2008, the Compensation Committee of Basics Board of Directors approved grants of
performance-based stock awards to certain members of management. In March 2009, it was determined
that 93,500 shares, or 100% of the target number of shares, were earned based on the Companys
achievement of certain earnings per share growth and return on capital employed performance over
the performance period from January 1, 2006 through December 31, 2008, as compared to other members
of a defined peer group. These shares remain subject to vesting over a three-year period, with the
first shares vesting on March 15, 2010.
18
In March 2009, Basic granted various employees 571,824 unvested shares of common stock which
vest over a five-year period. Also, in March 2009, Basic granted the Chairman of the Board 4,000
shares of common stock which vested immediately in lieu of annual cash director fees.
In May 2009, consistent with its director compensation practices, Basic granted a new board
member 37,500 shares of restricted common stock which vest over a three-year period.
During the six months ended June 30, 2009, Basic issued 5,000 shares of common stock from
treasury stock for the exercise of stock options.
Treasury Stock
On October 13, 2008, Basic announced that its Board of Directors authorized the repurchase of
up to $50.0 million of Basics shares of common stock from time to time in open market or private
transactions, at Basics discretion. The number of shares purchased and the timing of purchases are
based on several factors, including the price of the common stock, general market conditions,
available cash and alternative investment opportunities. During the year ended December 31, 2008,
Basic repurchased 897,558 shares at a total price of $8.8 million (an average of $9.82 per share),
inclusive of commissions and fees. During the first six months of 2009, Basic repurchased 809,093
shares at a total price of $6.0 million (an average of $7.41 per share), inclusive of commissions
and fees.
Basic also acquired treasury shares through net share settlements for payment of payroll taxes
upon the vesting of restricted stock. Basic acquired a total of 52,877 shares through net share
settlements during 2008 and 13,719 shares through net share settlements during the first six months
of 2009.
Preferred Stock
At June 30, 2009 and December 31, 2008, Basic had 5,000,000 shares of preferred stock, par
value $.01 per share, authorized, of which none was designated, issued or outstanding.
8. Incentive Plan
In May 2003, Basics board of directors and stockholders approved the Basic 2003 Incentive
Plan (as amended effective May 26, 2009) (the Plan), which provides for granting of incentive
awards in the form of stock options, restricted stock, performance awards, bonus shares, phantom
shares, cash awards and other stock-based awards to officers, employees, directors and consultants
of Basic. The Plan assumed awards of the plans of Basics successors that were awarded and remained
outstanding prior to adoption of the Plan. The Plan provides for the issuance of 7,100,000 shares.
The Plan is administered by the Plan committee, and in the absence of a Plan committee, by the
Board of Directors, which determines the awards and the associated terms of the awards and
interprets its provisions and adopts policies for implementing the Plan. The number of shares
authorized under the Plan and the number of shares subject to an award under the Plan will be
adjusted for stock splits, stock dividends, recapitalizations, mergers and other changes affecting
the capital stock of Basic.
The fair value of each option award is estimated on the date of grant using the
Black-Scholes-Merton option-pricing model. Basic is required to estimate the expected forfeiture
rate and only recognize expense for those options expected to vest. During the three months ended
June 30, 2009 and 2008, compensation expense related to share-based arrangements was approximately
$1.3 million and $1.2 million, respectively. For compensation expense recognized during the three
months ended June 30, 2009 and 2008, Basic recognized a tax
benefit of approximately $509,000 and
$453,000 respectively. During the six months ended June 30, 2009 and 2008, compensation expense
related to share-based arrangements was approximately $2.7 million and $2.3 million, respectively.
For compensation expense recognized during the six months ended June 30, 2009 and 2008, Basic
recognized a tax benefit of approximately $992,000 and $857,000 respectively.
Options granted under the Plan expire 10 years from the date they are granted, and generally
vest over a three to five-year service period.
19
The following table reflects the summary of stock options outstanding at June 30, 2009 and the
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
Weighted |
|
Average |
|
Aggregate |
|
|
Number of |
|
Average |
|
Remaining |
|
Instrinsic |
|
|
Options |
|
Exercise |
|
Contractual |
|
Value |
|
|
Granted |
|
Price |
|
Term (Years) |
|
(000s) |
Non-statutory stock
options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding,
beginning of period |
|
|
1,608,675 |
|
|
$ |
11.11 |
|
|
|
|
|
|
|
|
|
Options granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options forfeited |
|
|
(15,500 |
) |
|
$ |
14.03 |
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
(5,000 |
) |
|
$ |
6.98 |
|
|
|
|
|
|
|
|
|
Options expired |
|
|
(91,250 |
) |
|
$ |
6.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of
period |
|
|
1,496,925 |
|
|
$ |
11.40 |
|
|
|
5.34 |
|
|
$ |
1,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of
period |
|
|
1,124,050 |
|
|
$ |
9.18 |
|
|
|
4.96 |
|
|
$ |
1,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested or expected
to vest, end of
period |
|
|
1,483,175 |
|
|
$ |
11.27 |
|
|
|
5.32 |
|
|
$ |
1,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total intrinsic value of share options exercised during the six months ended June 30, 2009
and 2008 was approximately $15,000 and $2.6 million, respectively.
On March 13, 2009, the Compensation Committee of Basics Board of Directors approved grants of
performance-based stock awards to certain members of management. The performance-based awards are
tied to the Companys achievement of certain earnings per share growth and return on capital
employed performance over the performance period from January 1, 2007 through December 31, 2009, as
compared to other members of a defined peer group. The number of shares to be issued will range
from 0% to 150% of the target number of shares of 265,000 depending on the performance noted above.
Any shares earned at the end of the performance period will then remain subject to vesting over a
three-year period, with the first shares vesting March 15, 2011. As of June 30, 2009 it was
estimated that none of the performance based awards will be earned.
20
A summary of the status of the Companys non-vested share grants at June 30, 2009 and changes
during the six months ended June 30, 2009 is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
Number of |
|
|
Grant Date Fair |
|
Nonvested Shares |
|
Shares |
|
|
Value Per Share |
|
Nonvested at beginning
of period |
|
|
599,325 |
|
|
$ |
21.41 |
|
Granted during period |
|
|
616,324 |
|
|
|
6.50 |
|
Vested during period |
|
|
(72,375 |
) |
|
|
20.04 |
|
Forfeited during period |
|
|
(39,600 |
) |
|
|
16.86 |
|
Performance based earned (1) |
|
|
14,025 |
|
|
|
21.17 |
|
|
|
|
|
|
|
|
|
Nonvested at end of period |
|
|
1,117,699 |
|
|
$ |
13.44 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In March 2008 certain members of management were awarded grants of performance based stock
awards. The number of shares to be earned ranged from 0% to 150% of target depending on the
Companys achievement of certain EPS and return on capital employed performance compared to a
peer group. The performance period for purposes of these grants was January 1, 2006 through
December 31, 2008. As of December 31, 2008 it was estimated that 85% of the target shares
would be earned and in March 2009 it was determined that 100% of the target shares had been
earned. These shares remain subject to vesting over a three-year period, with the first shares
vesting in March 2010. |
As of June 30, 2009, there was approximately $12.6 million of total unrecognized compensation
related to non-vested share-based compensation arrangements granted under the Plan. That cost is
expected to be recognized over a weighted-average period of 3.29 years. The total fair value of
share-based awards vested during the six months ended June 30, 2009 and 2008 was approximately $3.9
million and $10.0 million, respectively. The actual tax benefit realized for the tax deduction from
vested share-based awards was $149,000 and $861,000 for the six months ended June 30, 2009 and
2008, respectively.
Cash received from share option exercises under the Plan was approximately $35,000 and
$795,000 for the six months ended June 30, 2009 and 2008, respectively. The actual tax benefit
realized for the tax deductions from options exercised was $6,000 and $1.0 million for the six
months ended June 30, 2009 and 2008, respectively.
The Company has a history of issuing treasury and newly-issued shares to satisfy share option
exercises.
9. Related Party Transactions
Basic had receivables from employees of approximately $138,000 and $148,000 as of June 30,
2009 and December 31, 2008, respectively. During 2006, Basic entered into a lease agreement with
Darle Vuelta Cattle Co., LLC, an affiliate of the Chief Executive Officer, for approximately
$69,000. The term of the lease is five years and will continue on a year-to-year basis unless
terminated by either party.
10. Earnings Per Share
Basic presents earnings per share information in accordance with the provisions of SFAS No.
128, Earnings per Share (SFAS No. 128). Under SFAS No. 128, basic earnings per common share are
determined by dividing net earnings applicable to common stock by the weighted average number of
common shares actually outstanding during the period. Diluted earnings per common share is based on
the increased number of shares that would be outstanding assuming conversion of dilutive
outstanding securities using the as if converted method. The following table sets forth the
computation of basic and diluted earnings per share (in thousands, except share data):
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(Unaudited) |
|
|
(Unaudited) |
|
Numerator (both basic and diluted): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(21,236 |
) |
|
$ |
18,713 |
|
|
$ |
(204,061 |
) |
|
$ |
38,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for basic earnings per share |
|
|
39,574,561 |
|
|
|
40,721,317 |
|
|
|
39,773,857 |
|
|
|
40,649,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
|
|
|
|
827,164 |
|
|
|
|
|
|
|
810,916 |
|
Unvested restricted stock |
|
|
|
|
|
|
110,114 |
|
|
|
|
|
|
|
197,915 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share |
|
|
39,574,561 |
|
|
|
41,658,595 |
|
|
|
39,773,857 |
|
|
|
41,658,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per common share: |
|
$ |
(0.54 |
) |
|
$ |
0.46 |
|
|
$ |
(5.13 |
) |
|
$ |
0.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per common share: |
|
$ |
(0.54 |
) |
|
$ |
0.45 |
|
|
$ |
(5.13 |
) |
|
$ |
0.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and unvested restricted stock shares of approximately 409,000 and 443,000 were
excluded in the computation of diluted earnings per share for the three months and six months ended
June 30, 2009, respectively as the effect would have been anti-dilutive due to the net loss in each
of these periods.
11. Business Segment Information
Basics reportable business segments are Well Servicing, Fluid Services, Completion and
Remedial Services, and Contract Drilling. The following is a description of the segments:
Well Servicing: This business segment encompasses a full range of services performed with a
mobile well servicing rig, including the installation and removal of downhole equipment and
elimination of obstructions in the well bore to facilitate the flow of oil and gas. These services
are performed to establish, maintain and improve production throughout the productive life of an
oil and gas well and to plug and abandon a well at the end of its productive life. Well servicing
equipment and capabilities such as Basics are essential to facilitate most other services
performed on a well.
Fluid Services: This segment utilizes a fleet of trucks and related assets, including
specialized tank trucks, storage tanks, water wells, disposal facilities, construction and other
related equipment. Basic employs these assets to provide, transport, store and dispose of a variety
of fluids, as well as provide well site construction and maintenance services. These services are
required in most workover, completion and remedial projects and are routinely used in daily
producing well operations.
Completion and Remedial Services: This segment utilizes a fleet of pressure pumping units,
coiled tubing units, air compressor packages specially configured for underbalanced drilling
operations, cased-hole wireline units and an array of specialized rental equipment and fishing
tools. The largest portion of this business consists of pressure pumping services focused on
cementing, acidizing and fracturing services in niche markets.
Contract Drilling: This segment utilizes shallow and medium depth rigs and associated
equipment for drilling wells to a specified depth for customers on a contract basis.
Basics management evaluates the performance of its operating segments based on operating
revenues and segment profits. Corporate expenses include general corporate expenses associated with
managing all reportable operating segments. Corporate assets consist principally of working capital
and debt financing costs.
22
The following table sets forth certain financial information with respect to Basics reportable
segments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Completion |
|
|
|
|
|
|
|
|
|
|
|
|
Well |
|
|
Fluid |
|
|
and Remedial |
|
|
Contract |
|
|
Corporate |
|
|
|
|
|
|
Servicing |
|
|
Services |
|
|
Services |
|
|
Drilling |
|
|
and Other |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009 (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
36,399 |
|
|
$ |
49,088 |
|
|
$ |
29,373 |
|
|
$ |
3,988 |
|
|
$ |
|
|
|
$ |
118,848 |
|
Direct operating costs |
|
|
(27,825 |
) |
|
|
(35,381 |
) |
|
|
(21,484 |
) |
|
|
(3,338 |
) |
|
|
|
|
|
$ |
(88,028 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits |
|
$ |
8,574 |
|
|
$ |
13,707 |
|
|
$ |
7,889 |
|
|
$ |
650 |
|
|
$ |
|
|
|
$ |
30,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
$ |
12,127 |
|
|
$ |
9,131 |
|
|
$ |
7,653 |
|
|
$ |
1,803 |
|
|
$ |
1,699 |
|
|
$ |
32,413 |
|
Capital expenditures, (excluding acquisitions) |
|
$ |
4,266 |
|
|
$ |
3,212 |
|
|
$ |
2,693 |
|
|
$ |
634 |
|
|
$ |
598 |
|
|
$ |
11,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008 (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
89,018 |
|
|
$ |
72,581 |
|
|
$ |
79,579 |
|
|
$ |
10,344 |
|
|
$ |
|
|
|
$ |
251,522 |
|
Direct operating costs |
|
|
(55,293 |
) |
|
|
(48,554 |
) |
|
|
(42,651 |
) |
|
|
(7,529 |
) |
|
|
|
|
|
|
(154,027 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits |
|
$ |
33,725 |
|
|
$ |
24,027 |
|
|
$ |
36,928 |
|
|
$ |
2,815 |
|
|
$ |
|
|
|
$ |
97,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
$ |
11,492 |
|
|
$ |
7,046 |
|
|
$ |
7,041 |
|
|
$ |
1,853 |
|
|
$ |
1,300 |
|
|
$ |
28,732 |
|
Capital expenditures, (excluding acquisitions) |
|
$ |
10,638 |
|
|
$ |
6,522 |
|
|
$ |
6,518 |
|
|
$ |
1,715 |
|
|
$ |
1,203 |
|
|
$ |
26,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009 (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
85,213 |
|
|
$ |
114,065 |
|
|
$ |
66,632 |
|
|
$ |
7,626 |
|
|
$ |
|
|
|
$ |
273,536 |
|
Direct operating costs |
|
|
(64,742 |
) |
|
|
(79,968 |
) |
|
|
(47,378 |
) |
|
|
(6,607 |
) |
|
|
|
|
|
$ |
(198,695 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits |
|
$ |
20,471 |
|
|
$ |
34,097 |
|
|
$ |
19,254 |
|
|
$ |
1,019 |
|
|
$ |
|
|
|
$ |
74,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
$ |
24,375 |
|
|
$ |
18,353 |
|
|
$ |
15,383 |
|
|
$ |
3,624 |
|
|
$ |
3,415 |
|
|
$ |
65,150 |
|
Capital expenditures, (excluding acquisitions) |
|
$ |
9,423 |
|
|
$ |
7,095 |
|
|
$ |
5,947 |
|
|
$ |
1,401 |
|
|
$ |
1,321 |
|
|
$ |
25,187 |
|
Identifiable assets |
|
$ |
268,207 |
|
|
$ |
205,577 |
|
|
$ |
202,563 |
|
|
$ |
44,544 |
|
|
$ |
347,502 |
|
|
$ |
1,068,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008 (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
169,537 |
|
|
$ |
143,980 |
|
|
$ |
148,037 |
|
|
$ |
19,841 |
|
|
$ |
|
|
|
$ |
481,395 |
|
Direct operating costs |
|
|
(103,759 |
) |
|
|
(94,987 |
) |
|
|
(78,439 |
) |
|
|
(14,589 |
) |
|
|
|
|
|
|
(291,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profits |
|
$ |
65,778 |
|
|
$ |
48,993 |
|
|
$ |
69,598 |
|
|
$ |
5,252 |
|
|
$ |
|
|
|
$ |
189,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
$ |
22,704 |
|
|
$ |
13,921 |
|
|
$ |
13,911 |
|
|
$ |
3,661 |
|
|
$ |
2,567 |
|
|
$ |
56,764 |
|
Capital expenditures, (excluding acquisitions) |
|
$ |
18,008 |
|
|
$ |
11,041 |
|
|
$ |
11,033 |
|
|
$ |
2,904 |
|
|
$ |
2,037 |
|
|
$ |
45,023 |
|
Identifiable assets |
|
$ |
301,669 |
|
|
$ |
209,397 |
|
|
$ |
322,623 |
|
|
$ |
70,984 |
|
|
$ |
305,103 |
|
|
$ |
1,209,776 |
|
The following table reconciles the segment profits reported above to the operating income as
reported in the consolidated statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Segment profits |
|
$ |
30,820 |
|
|
$ |
97,495 |
|
|
$ |
74,841 |
|
|
$ |
189,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses |
|
|
(27,424 |
) |
|
|
(26,811 |
) |
|
|
(56,503 |
) |
|
|
(52,663 |
) |
Depreciation and amortization |
|
|
(32,413 |
) |
|
|
(28,732 |
) |
|
|
(65,150 |
) |
|
|
(56,764 |
) |
Loss on disposal of assets |
|
|
(474 |
) |
|
|
809 |
|
|
|
(1,339 |
) |
|
|
584 |
|
Goodwill impairment |
|
|
82 |
|
|
|
|
|
|
|
(204,014 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(29,409 |
) |
|
$ |
42,761 |
|
|
$ |
(252,165 |
) |
|
$ |
80,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
12. Supplemental Schedule of Cash Flow Information
The following table reflects non-cash financing and investing activity during the following
periods:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
2009 |
|
2008 |
|
|
(In thousands) |
Capital leases issued for equipment |
|
$ |
15,426 |
|
|
$ |
20,522 |
|
Contingent earnout accrual |
|
$ |
909 |
|
|
$ |
1,158 |
|
Asset retirement obligation additions |
|
$ |
12 |
|
|
$ |
34 |
|
Basic paid no income taxes during the six months ended June 30, 2009. Basic paid income taxes
of approximately $13.2 million during the six months ended June 30, 2008. Basic paid interest of
approximately $12.3 million and $12.9 million during the six months ended June 30, 2009 and 2008,
respectively.
13. Fair Value Measurements
SFAS No. 157 was issued by the FASB in September 2006 and became effective for financial
assets and liabilities of the Company on January 1, 2008 and became effective for non-financial
assets and liabilities of the Company on January 1, 2009. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value under GAAP and expands disclosures about fair
value measurements. Fair value is the price that would be received to sell an asset or the amount
paid to transfer a liability in an orderly transaction between market participants (an exit price)
at the measurement date. Fair value is a market based measurement considered from the perspective
of a market participant. The Company uses market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk and the risks inherent in
the inputs to the valuation. These inputs can be readily observable, market corroborated, or
unobservable. If observable prices or inputs are not available, unobservable prices or inputs are
used to estimate the current fair value, often using an internal valuation model. These valuation
techniques involve some level of management estimation and judgment, the degree of which is
dependent on the item being valued. The Company primarily applies a market approach for recurring
fair value measurements using the best available information while utilizing valuation techniques
that maximize the use of observable inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to quoted prices in active markets for
identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable
inputs (Level 3 measurement). The Company classifies fair value balances based on the observability
of those inputs. The three levels of the fair value hierarchy are as follows:
Level 1Quoted prices in active markets for identical assets or liabilities that the Company
has the ability to access. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing information on an
ongoing basis.
Level 2Inputs are other than quoted prices in active markets included in Level 1, which are
either directly or indirectly observable. These inputs are either directly observable in the
marketplace or indirectly observable through corroboration with market data for substantially
the full contractual term of the asset or liability being measured.
Level 3Inputs reflect managements best estimate of what market participants would use in
pricing the asset or liability at the measurement date. Consideration is given to the risk
inherent in the valuation technique and the risk inherent in the inputs to the model.
In valuing certain assets and liabilities, the inputs used to measure fair value may fall into
different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are
classified in their entirety in the fair value hierarchy level based on the lowest level of input
that is significant to the overall fair value measurement. The Companys assessment of the
significance of a particular input to the fair value measurement requires judgment and may affect
the placement within the fair value hierarchy levels.
The Companys asset retirement obligation related to its salt water disposal sites, brine
water wells, gravel pits and land farm sites, each of which is subject to rules and regulations
regarding usage and eventual closure, is measured using primarily Level 3 inputs. The
24
significant unobservable inputs to this fair value measurement include estimates of plugging,
abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on
historical data as well as current estimated costs. The fair value is calculated by taking the
present value of the expected cash flow at the time of the closure of the site. The following table
reflects the changes in the fair value of the liability during the six months ended June 30, 2009
(in thousands):
|
|
|
|
|
|
|
Asset |
|
|
|
Retirement |
|
|
|
Obligation |
|
Balance, December 31, 2008 |
|
$ |
1,796 |
|
|
|
|
|
|
Additional asset retirement obligation |
|
|
12 |
|
Accretion expense |
|
|
73 |
|
|
|
|
|
Balance, June 30, 2009 |
|
$ |
1,881 |
|
|
|
|
|
14. Subsequent Events
Management performed an evaluation of the Companys activity through July 31, 2009, the date
these financial statements were issued, noting the following subsequent event.
On July 23, 2009, we announced that we had priced a private offering of $225 million of Senior
Secured Notes due 2014, which will bear interest at a rate of 11.625% per annum. The notes are
being sold at 94.621% of their face amount. We closed the sale of the notes July 31, 2009, and used
the net proceeds from the offering to repay all outstanding indebtedness under our revolving credit
facility.
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Managements Overview
We provide a wide range of well site services to oil and gas drilling and producing companies,
including well servicing, fluid services, completion and remedial services and contract drilling.
Our results of operations reflect the impact of our acquisition strategy as a leading consolidator
in the domestic land-based well services industry. Our acquisitions have increased our breadth of
service offerings at the well site and expanded our market presence. In implementing this strategy,
we purchased businesses and assets in 40 separate acquisitions from January 1, 2004 to June 30,
2009. Our weighted average number of well servicing rigs increased from 279 in 2004 to 414 in the
second quarter of 2009 and our weighted average number of fluid service trucks increased from 386
to 808 in the same period. These acquisitions make our revenues, expenses and income not directly
comparable between periods.
Our operating revenues from each of our segments, and their relative percentages of our total
revenues, consisted of the following (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2009 |
|
2008 |
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well servicing |
|
$ |
85.2 |
|
|
|
31 |
% |
|
$ |
169.5 |
|
|
|
35 |
% |
Fluid services |
|
|
114.1 |
|
|
|
42 |
% |
|
|
144.0 |
|
|
|
30 |
% |
Completion and remedial services |
|
|
66.6 |
|
|
|
24 |
% |
|
|
148.0 |
|
|
|
31 |
% |
Contract drilling |
|
|
7.6 |
|
|
|
3 |
% |
|
|
19.8 |
|
|
|
4 |
% |
|
|
|
|
|
Total revenues |
|
$ |
273.5 |
|
|
|
100 |
% |
|
$ |
481.3 |
|
|
|
100 |
% |
|
|
|
|
|
Our core businesses depend on our customers willingness to make expenditures to produce,
develop and explore for oil and gas in the United States. Industry conditions are influenced by
numerous factors, such as the supply of and demand for oil and gas, domestic and worldwide economic
conditions, political instability in oil producing countries and merger and divestiture activity
among oil and gas producers. The volatility of the oil and gas industry, and the consequent impact
on exploration and production activity, could adversely impact the level of drilling and workover
activity by some of our customers. This volatility affects the demand for our services and the
price of our services.
25
In 2007, natural gas prices declined as an excess supply of natural gas began to develop,
mainly due to moderate U.S. weather patterns. Utilization for our services declined from 2006
levels as drilling activity flattened or declined in several of our markets and new equipment
entered the marketplace balancing supply and demand for our services. However, pricing for our
services improved in 2007 from 2006, mainly reflecting continued increases in labor costs, and
offset a portion the effect of the lower utilization of our services on our total revenues. By the
middle of 2008, oil and natural gas prices reached historic highs. However, in the second half of
2008, oil and natural gas prices decreased substantially, which caused significantly lower
utilization of our services in the fourth quarter of 2008. In the first half of 2009, utilization
and pricing for our services continued to decline from the fourth quarter of 2008. For the second
half of 2009, we expect oil and gas prices to remain below the levels required to support
aggressive capital spending programs by our customers and that their maintenance related spending
will be deferred for as long as possible. The reduced spending by our customers in the first half
of 2009 is expected to continue in the second half of 2009, which will result in decreased demand
for our services and increased competition among the service providers in each of our segments. We
anticipate that utilization, revenue and margins in 2009 will be substantially below 2008 levels.
We derive a majority of our revenues from services supporting production from existing oil and
gas operations. Demand for these production-related services, including well servicing and fluid
services, tends to remain relatively stable, even in moderate oil and gas price environments, as
ongoing maintenance spending is required to sustain production. As oil and gas prices fluctuate,
demand for all of our services changes correspondingly as our customers must balance maintenance
and capital expenditures against their available cash flows. Because our services are required to
support drilling and workover activities, we are also subject to changes in capital spending by our
customers as oil and gas prices increase or decrease. Adverse changes in capital markets have
caused a number of oil and gas producers to reduce their capital budgets for the remainder of 2009.
Limitations on the availability of capital, or higher costs of capital, for financing expenditures
may cause these and other oil and gas producers to make additional reductions to capital budgets in
the future even if commodity prices return to historically high levels.
We believe that the most important performance measures for our lines of business are as
follows:
|
|
|
Well Servicing rig hours, rig utilization rate, revenue per rig hour and segment
profits as a percent of revenues; |
|
|
|
|
Fluid Services revenue per truck and segment profits as a percent of revenues; |
|
|
|
|
Completion and Remedial Services segment profits as a percent of revenues; and |
|
|
|
|
Contract Drilling rig operating days, revenue per drilling day and segment profits as
a percent of revenues. |
Segment profits are computed as segment operating revenues less direct operating costs. These
measurements provide important information to us about the activity and profitability of our lines
of business. For a detailed analysis of these indicators for our company, see below in Segment
Overview.
We will continue to evaluate opportunities to grow our business through selective acquisitions
and internal growth initiatives. Our capital investment decisions are determined by an analysis of
the projected return on capital employed for each of those alternatives, which is substantially
driven by the cost to acquire existing assets from a third party, the capital required to build new
equipment and the point in the oil and gas commodity price cycle. Based on these factors, we make
capital investment decisions that we believe will support our long-term growth strategy. While we
believe our costs of integration for prior acquisitions have been reflected in our historical
results of operations, integration of acquisitions may result in unforeseen operational
difficulties or require a disproportionate amount of our managements attention. As discussed below
in Liquidity and Capital Resources, we also must meet certain financial covenants in order to
borrow money under our existing credit agreement to fund future acquisitions.
Selected 2008 Acquisitions
During the year 2008, we made several acquisitions that complemented our existing lines of
business. These included among others:
Xterra Fishing and Rental Tools Co
On January 28, 2008, we acquired all of the outstanding capital stock of Xterra Fishing and
Rental Tools Co. (Xterra) for total consideration of $21.5 million cash. This acquisition
operates in our completion and remedial services line of business.
26
Azurite Services Company, Inc.
On September 26, 2008, we acquired substantially all of the operating assets of Azurite for
$61.0 million in cash. This acquisition operates in our fluid services line of business.
Segment Overview
Well Servicing
During the first six months of 2009, our well servicing segment represented 31% of our
revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion,
and plugging and abandonment services. We provide maintenance-related services as part of the
normal, periodic upkeep of producing oil and gas wells. Maintenance-related services represent a
relatively consistent component of our business. Workover and completion services generate more
revenue per hour than maintenance work, due to the use of auxiliary equipment, but demand for
workover and completion services fluctuates more with the overall activity level in the industry.
We typically charge our customers for services on an hourly basis at rates that are determined
by the type of service and equipment required, market conditions in the region in which the rig
operates, the ancillary equipment provided on the rig and the necessary personnel. Depending on the
type of job, we may also charge by the project or by the day. We measure our activity levels by the
total number of hours worked by all of the rigs in our fleet. We monitor our fleet utilization
levels, with full utilization deemed to be 55 hours per week per rig. Our fleet increased from a
weighted average number of 392 rigs in the first quarter of 2008 to 414 in the second quarter of
2009 through a combination of newbuild purchases and acquisitions and other individual equipment
purchases.
The following is an analysis of our well servicing operations for each of the quarters in
2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
Rig |
|
|
|
|
|
Profits |
|
|
|
|
Number of |
|
Rig |
|
Utilization |
|
Revenue Per |
|
Per Rig |
|
Segment |
|
|
Rigs |
|
Hours |
|
Rate |
|
Rig Hour |
|
Hour |
|
Profits% |
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
392 |
|
|
|
202,500 |
|
|
|
72.2 |
% |
|
$ |
398 |
|
|
$ |
158 |
|
|
|
39.8 |
% |
Second Quarter |
|
|
403 |
|
|
|
222,300 |
|
|
|
77.1 |
% |
|
$ |
400 |
|
|
$ |
152 |
|
|
|
37.9 |
% |
Third Quarter |
|
|
412 |
|
|
|
233,000 |
|
|
|
79.1 |
% |
|
$ |
418 |
|
|
$ |
156 |
|
|
|
37.3 |
% |
Fourth Quarter |
|
|
414 |
|
|
|
182,400 |
|
|
|
61.6 |
% |
|
$ |
418 |
|
|
$ |
141 |
|
|
|
33.8 |
% |
Full Year |
|
|
405 |
|
|
|
840,200 |
|
|
|
72.5 |
% |
|
$ |
408 |
|
|
$ |
152 |
|
|
|
37.3 |
% |
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
414 |
|
|
|
132,300 |
|
|
|
44.7 |
% |
|
$ |
369 |
|
|
$ |
90 |
|
|
|
24.4 |
% |
Second Quarter |
|
|
414 |
|
|
|
110,500 |
|
|
|
37.3 |
% |
|
$ |
329 |
|
|
$ |
78 |
|
|
|
23.6 |
% |
We gauge activity levels in our well servicing segment based on rig utilization rate, revenue
per rig hour and segment profits per rig hour.
Rig utilization declined to 37.3% in the second quarter of 2009 compared to 44.7% in the first
quarter of 2009. The decline was caused by the continued slowdown in the economy and instability of
oil prices experienced in the second quarter of 2009, which caused a decrease in demand for our
services. This decrease was exacerbated by the continued weakness in natural gas prices. The
decrease in demand for our services also caused price pressure, and our revenue per rig hour
decreased to $329 in the second quarter of 2009 compared to $369 in the first quarter of 2009.
Through our continued cost cutting measures, we were able to minimize the decrease in segment
profit percentage to 23.6% in the second quarter of 2009 from 24.4% in the first quarter of 2009.
Fluid Services
During the first six months of 2009, our fluid services segment represented 42% of our
revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage
and disposal of fluids used in the drilling, production and maintenance of oil and gas wells, and
well site construction and maintenance services. The fluid services segment has a base level of
business consisting of transporting and disposing of salt water produced as a by-product of the
production of oil and gas. These services are necessary for our customers and generally have a
stable demand but typically produce lower relative segment profits than other parts of our fluid
services segment. Fluid services for completion and workover projects typically require fresh or
brine water for making drilling mud,
27
circulating fluids or frac fluids used during a job, and all of these fluids require storage
tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking,
storage and disposal required on most drilling and workover projects, the add-on services
associated with drilling and workover activity enable us to generate higher segment profits
contributions. Revenues from our well site construction services are derived primarily from
preparing and maintaining access roads and well locations, installing small diameter gathering
lines and pipelines, constructing foundations to support drilling rigs and providing maintenance
services for oil and gas facilities. The higher segment profits are due to the relatively small
incremental labor costs associated with providing these services in addition to our base fluid
services segment. We typically price fluid services by the job, by the hour or by the quantities
sold, disposed of or hauled.
The following is an analysis of our fluid services operations for each of the quarters in
2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Segment Profits |
|
|
|
|
Average Number of |
|
Revenue Per |
|
Per Fluid |
|
|
|
|
Fluid Service |
|
Fluid Service |
|
Service |
|
Segment |
|
|
Trucks |
|
Truck |
|
Truck |
|
Profits% |
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
644 |
|
|
$ |
111 |
|
|
$ |
39 |
|
|
|
35.0 |
% |
Second Quarter |
|
|
663 |
|
|
$ |
109 |
|
|
$ |
36 |
|
|
|
33.1 |
% |
Third Quarter |
|
|
683 |
|
|
$ |
121 |
|
|
$ |
43 |
|
|
|
35.8 |
% |
Fourth Quarter |
|
|
804 |
|
|
$ |
111 |
|
|
$ |
42 |
|
|
|
38.1 |
% |
Full Year |
|
|
699 |
|
|
$ |
452 |
|
|
$ |
161 |
|
|
|
35.6 |
% |
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
814 |
|
|
$ |
80 |
|
|
$ |
25 |
|
|
|
31.4 |
% |
Second Quarter |
|
|
808 |
|
|
$ |
61 |
|
|
$ |
17 |
|
|
|
27.9 |
% |
We gauge activity levels in our fluid services segment based on revenue and segment profits
per fluid service truck.
The decrease in revenue per fluid service truck to $61 in the second quarter of 2009 from $80
in the first quarter of 2009 and the decrease in segment profit percentage to 27.9% in the second
quarter of 2009 from 31.4% in the first quarter of 2009 were caused by lower customer demand and
rate decreases in all of our market areas.
Completion and Remedial Services
During the first six months of 2009, our completion and remedial services segment represented
24% of our revenues. Revenues from our completion and remedial services segment are generally
derived from a variety of services designed to stimulate oil and gas production or place cement
slurry within the wellbores. Our completion and remedial services segment includes pressure
pumping, cased-hole wireline services, underbalanced drilling and rental and fishing tool
operations.
Our pressure pumping operations concentrate on providing lower-horsepower cementing, acidizing
and fracturing services in selected markets. Our total hydraulic horsepower capacity for our
pressure pumping operations was 139,000 and 128,000 at June 30, 2009 and June 30, 2008,
respectively.
In this segment, we generally derive our revenues on a project-by-project basis in a
competitive bidding process. Our bids are generally based on the amount and type of equipment and
personnel required, with the materials consumed billed separately. During periods of decreased
spending by oil and gas companies, we may be required to discount our rates to remain competitive,
which would cause lower segment profits.
28
The following is an analysis of our completion and remedial services segment for each of the
quarters in 2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and
June 30, 2009 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
|
Revenues |
|
Profits% |
2008: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
68,458 |
|
|
|
47.7 |
% |
Second Quarter |
|
$ |
79,579 |
|
|
|
46.4 |
% |
Third Quarter |
|
$ |
85,541 |
|
|
|
45.3 |
% |
Fourth Quarter |
|
$ |
70,748 |
|
|
|
43.0 |
% |
Full Year |
|
$ |
304,326 |
|
|
|
45.6 |
% |
2009: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
37,259 |
|
|
|
30.5 |
% |
Second Quarter |
|
$ |
29,373 |
|
|
|
26.9 |
% |
We gauge the performance of our completion and remedial services segment based on the
segments operating revenues and segment profits.
The decrease in completion and remedial revenue to $29.4 million in the second quarter of 2009
from $37.3 million in the first quarter of 2009 was caused by the continued slowdown in the economy
during the second quarter of 2009 along with natural gas prices remaining low, which resulted in
lower demand for our services. Demand, particularly in our pressure pumping segment, and rates for
our services decreased faster than our costs, resulting in the decrease in segment profit
percentage to 26.9% in the second quarter of 2009 from 30.5% in the first quarter of 2009.
Contract Drilling
During the first six months of 2009, our contract drilling segment represented 3% of our
revenues. Revenues from our contract drilling segment are derived primarily from the drilling of
new wells.
Within this segment, we typically charge our drilling rig customers at a daywork daily rate,
or footage at an established rate per number of feet drilled. We measure the activity level of our
drilling rigs on a weekly basis by calculating a rig utilization rate which is based on a seven day
work week per rig. Our contract drilling rig fleet had a weighted average of nine rigs during the
four quarters of 2008 and the first and second quarter of 2009.
The following is an analysis of our contract drilling segment for each of the quarters in
2008, the full year ended December 31, 2008 and the quarters ended March 31, 2009 and June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Average |
|
Rig |
|
|
|
|
|
|
|
|
Number of |
|
Operating |
|
Revenue |
|
Profits |
|
Segment |
|
|
Rigs |
|
Days |
|
Per Day |
|
Per Day |
|
Profits% |
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
9 |
|
|
|
645 |
|
|
$ |
14,700 |
|
|
$ |
3,800 |
|
|
|
25.7 |
% |
Second Quarter |
|
|
9 |
|
|
|
699 |
|
|
$ |
14,800 |
|
|
$ |
4,000 |
|
|
|
27.2 |
% |
Third Quarter |
|
|
9 |
|
|
|
767 |
|
|
$ |
15,600 |
|
|
$ |
5,600 |
|
|
|
35.6 |
% |
Fourth Quarter |
|
|
9 |
|
|
|
666 |
|
|
$ |
14,900 |
|
|
$ |
5,400 |
|
|
|
36.2 |
% |
Full Year |
|
|
9 |
|
|
|
2,777 |
|
|
$ |
15,000 |
|
|
$ |
4,700 |
|
|
|
31.4 |
% |
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
9 |
|
|
|
248 |
|
|
$ |
14,700 |
|
|
$ |
1,500 |
|
|
|
10.1 |
% |
Second Quarter |
|
|
9 |
|
|
|
314 |
|
|
$ |
12,700 |
|
|
$ |
2,100 |
|
|
|
16.3 |
% |
We gauge activity levels in our drilling operations based on rig operating days, revenue per
day and profits per drilling day.
The increase in segment profits to 16.3% in the second quarter of 2009 from 10.1% in the first
quarter of 2009 was due primarily to the increase in rig operating days during the second quarter.
29
Operating Cost Overview
Our operating costs are comprised primarily of labor, including workers compensation and
health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid
on an hourly basis. We also incur costs to employ personnel to sell and supervise our services and
perform maintenance on our fleet. These costs are not directly tied to our level of business
activity. Compensation for our administrative personnel in local operating yards and in our
corporate office is accounted for as general and administrative expenses. Repair and maintenance is
performed by our crews, company maintenance personnel and outside service providers. Insurance is
generally a fixed cost regardless of utilization and relates to the number of rigs, trucks and
other equipment in our fleet, employee payroll and safety record.
Critical Accounting Policies and Estimates
Our consolidated financial statements are impacted by the accounting policies used and the
estimates and assumptions made by management during their preparation. A complete summary of our
critical accounting policies is included in note 2 of the notes to our historical consolidated
financial statements. The following is a discussion of our critical accounting policies and
estimates.
Critical Accounting Policies
We have identified below accounting policies that are of particular importance in the
presentation of our financial position, results of operations and cash flows and which require the
application of significant judgment by management.
Property and Equipment. Property and equipment are stated at cost or at estimated fair value
at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance
are charged to expenses as incurred. We also review the capitalization of refurbishment of workover
rigs as described in note 2 of the notes to our consolidated financial statements.
Impairments. We review our assets for impairment at a minimum annually, or whenever, in
managements judgment, events or changes in circumstances indicate that the carrying amount of a
long-lived asset may not be recovered over its remaining service life. Provisions for asset
impairment are charged to income when the sum of the estimated future cash flows, on an
undiscounted basis, is less than the assets carrying amount. When impairment is indicated, an
impairment charge is recorded based on an estimate of future cash flows on a discounted basis.
Self-Insured Risk Accruals. We are self-insured up to retention limits with regard to workers
compensation and medical and dental coverage of our employees. We generally maintain no physical
property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour
workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers
compensation and medical and dental coverage of $375,000 and $250,000 respectively. We have lower
deductibles per occurrence for automobile liability and general liability. We maintain accruals in
our consolidated balance sheets related to self-insurance retentions by using third-party actuarial
data and historical claims history.
Revenue Recognition. We recognize revenues when the services are performed, collection of the
relevant receivables is probable, persuasive evidence of the arrangement exists and the price is
fixed and determinable.
Income Taxes. We account for income taxes based upon Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes (SFAS No. 109). Under SFAS No. 109,
deferred tax assets and liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax
rates expected to apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change
in tax rate is recognized in the period that includes the statutory enactment date. A valuation
allowance for deferred tax assets is recognized when it is more likely than not that the benefit of
deferred tax assets will not be realized.
Critical Accounting Estimates
The preparation of our consolidated financial statements in conformity with accounting
principles generally accepted in the United States of America (GAAP) requires management to make
certain estimates and assumptions. These estimates and assumptions affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet
date and the amounts of revenues and expenses recognized during the reporting period. We analyze
our estimates based on historical experience
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and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The
following is a discussion of our critical accounting estimates.
Depreciation and Amortization. In order to depreciate and amortize our property and equipment
and our intangible assets with finite lives, we estimate the useful lives and salvage values of
these items. Our estimates may be affected by such factors as changing market conditions,
technological advances in industry or changes in regulations governing the industry.
Impairment of Property and Equipment. Our impairment of property and equipment requires us to
estimate undiscounted future cash flows. Actual impairment charges are recorded using an estimate
of discounted future cash flows. The determination of future cash flows requires us to estimate
rates and utilization in future periods and such estimates can change based on market conditions,
technological advances in industry or changes in regulations governing the industry.
Impairment of Goodwill. Our goodwill is considered to have an indefinite useful economic life
and is not amortized. We assess impairment of our goodwill annually as of December 31 or on an
interim basis if events or circumstances indicate that the fair value of the asset has decreased
below its carrying value. SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142),
requires a two-step process for testing impairment. First, the fair value of each reporting unit is
compared to its carrying value to determine whether an indication of impairment exists. If
impairment is indicated, then the fair value of the reporting units goodwill is determined by
allocating the units fair value to its assets and liabilities (including any unrecognized
intangible assets) as if the reporting unit had been acquired in a business combination. The amount
of impairment for goodwill is measured as the excess of its carrying value over its fair value. As
of June 30, 2009, we had no goodwill recorded on our balance sheet.
Allowance for Doubtful Accounts. We estimate our allowance for doubtful accounts based on an
analysis of historical collection activity and specific identification of overdue accounts. Factors
that may affect this estimate include (1) changes in the financial positions of significant
customers and (2) a decline in commodity prices that could affect the entire customer base.
Litigation and Self-Insured Risk Reserves. We estimate our reserves related to litigation and
self-insured risk based on the facts and circumstances specific to the litigation and self-insured
risk claims and our past experience with similar claims. The actual outcome of litigated and
insured claims could differ significantly from estimated amounts. As discussed in Self-Insured
Risk Accruals above with respect to our critical accounting policies, we maintain accruals on our
balance sheet to cover self-insured retentions. These accruals are based on certain assumptions
developed using third-party data and historical data to project future losses. Loss estimates in
the calculation of these accruals are adjusted based upon actual claim settlements and reported
claims.
Fair Value of Assets Acquired and Liabilities Assumed. We estimate the fair value of assets
acquired and liabilities assumed in business combinations, which involves the use of various
assumptions. These estimates may be affected by such factors as changing market conditions,
technological advances in industry or changes in regulations governing the industry. The most
significant assumptions, and the ones requiring the most judgment, involve the estimated fair value
of property and equipment, intangible assets and the resulting amount of goodwill, if any. Our
adoption of SFAS No. 142 on January 1, 2002 requires us to test annually for impairment the
goodwill and intangible assets with indefinite useful lives recorded in business combinations. This
requires us to estimate the fair values of our own assets and liabilities at the reporting unit
level. Therefore, considerable judgment, similar to that described above in connection with our
estimation of the fair value of an acquired company, is required to assess goodwill and certain
intangible assets for impairment.
Cash Flow Estimates. Our estimates of future cash flows are based on the most recent available
market and operating data for the applicable asset or reporting unit at the time the estimate is
made. Our cash flow estimates are used for asset impairment analyses.
Stock-Based Compensation. We account for stock-based compensation based on Statement of
Financial Accounting Standards No. 123 (revised 2004), Share Based Payment (SFAS No. 123R).
Options issued are valued on the grant date using the Black-Scholes-Merton option-pricing model and
all awards are adjusted for an expected forfeiture rate. Awards are amortized over the vesting
period. Compensation expense of the unvested portion of awards granted as a private company and
outstanding as of January 1, 2006 will be based upon the intrinsic value method calculated under
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No.
25).
The fair value of common stock for options granted from July 1, 2004 through September 30,
2005 was estimated by management using an internal valuation methodology. We did not obtain
contemporaneous valuations by an unrelated valuation specialist because we were focused on internal
growth and acquisitions and because we had consistently used our internal valuation methodology for
previous stock awards.
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Income Taxes. The amount and availability of our loss carryforwards (and certain other tax
attributes) are subject to a variety of interpretations and restrictive tests. The utilization of
such carryforwards could be limited or lost upon certain changes in ownership and the passage of
time. Accordingly, although we believe substantial loss carryforwards are available to us, no
assurance can be given concerning the realization of such loss carryforwards, or whether or not
such loss carryforwards will be available in the future.
Asset Retirement Obligations.
SFAS No. 143, Accounting for Asset Retirement Obligation
(SFAS No. 143) requires us to record the fair value of an asset retirement obligation as a
liability in the period in which we incur a legal obligation associated with the retirement of
tangible long-lived assets and to capitalize an equal amount as a cost of the asset, depreciating
it over the life of the asset. Subsequent to the initial measurement of the asset retirement
obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time,
changes in the estimated future cash flows underlying the obligation, acquisition or construction
of assets, and settlement of obligations.
Results of Operations
The results of operations between periods may not be comparable, primarily due to the significant
number of acquisitions made and their relative timing in the year acquired. See note 3 of the notes
to our historical consolidated financial statements for more detail.
Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008
Revenues. Revenues decreased
by 53% to $118.8 million during the second quarter of 2009 from
$251.5 million during the same period in 2008. This decrease was primarily due to lower
expenditures by our customers for our services and increased price competition from our competitors
due to the continued decline in oil and natural gas prices.
Well servicing revenues decreased
by 59% to $36.4 million during the second quarter of 2009
compared to $89.0 million during the same period in 2008. This decrease was due to the decrease in
rig utilization to 37.3% during the second quarter of 2009 from 77.1% during the second quarter of
2008, along with a decrease in revenue per rig hour to $329 during the second quarter of 2009 from
$400 during the second quarter of 2008. These decreases were due to
decreased spending by our
customers for our services along with increased price competition from our competitors. Our average
number of well servicing rigs increased to 414 during the second quarter of 2009 compared to 403 in
the same period in 2008, due to internal expansion from our newbuild rig program and the Triple N
Services, Inc. acquisition.
Fluid services revenues decreased by 32% to $49.1 million during the second quarter of 2009
compared to $72.6 million in the same period in 2008. This decrease was primarily due to decreased
rates that we charged to our customers for our services caused by increased price competition from
our competitors. These decreases were partially offset by the Azurite acquisition in September 2008
which added 98 fluid service trucks and 632 frac tanks. This acquisition added approximately $6.9
million of revenues during the second quarter of 2009. Our weighted average number of fluid service
trucks increased to 808 during the second quarter of 2009 from 663 in the same period in 2008,
although our revenue per fluid service truck decreased to $61,000 in the second quarter of 2009
compared to $109,000 in the same period in 2008.
Completion and remedial services revenues decreased by 63% to $29.4 million during the second
quarter of 2009 compared to $79.6 million in the same period in 2008. The decrease in revenue
between these periods was due to decreased utilization of equipment due to the decline in oil and
gas prices. Increased market competition also caused significant rate declines. Total hydraulic
horsepower increased to 139,000 at June 30, 2009 from 128,000 at June 30, 2008.
Contract drilling revenues decreased by 61% to $4.0 million during the second quarter in 2009
compared to $10.3 million in the same period in 2008. The number of rig operating days decreased to
314 in second quarter of 2009 compared to 699 in the second quarter of 2008. This decrease was due
to lower new well starts in all of our geographic markets.
Direct Operating Expenses. Direct operating expenses, which primarily consist of labor,
including workers compensation and health insurance, fuel and maintenance and repair costs,
decreased by 43% to $88.0 million during the second quarter of 2009 from $154.0 million in the same
period in 2008. This decrease was due to the lower activity levels in all of our segments.
Direct operating expenses for the well servicing segment decreased by 50% to $27.8 million
during the second quarter of 2009 as compared to $55.3 million for the same period in 2008, due
primarily to the decrease in rig hours to 110,500 in the second quarter of
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2009 from 222,300 for the same period in 2008. Segment profits decreased to 24% of revenues during the second quarter of
2009 compared to 38% for the same period in 2008, which reflects the faster decline in activity
levels and rates than in costs.
Direct operating expenses for the fluid services segment decreased by 27% to $35.4 million
during the second quarter of 2009 as compared to $48.6 million for the same period in 2008, which
is due to lower activity levels being partially offset by the Azurite acquisition in September 2008
which added approximately $5.5 million in direct operating expenses in the second quarter 2009.
Segment profits were 28% of revenues during the second quarter of 2009 compared to 33% for the same
period in 2008.
Direct operating expenses for the completion and remedial services segment decreased by 50% to
$21.5 million during the second quarter of 2009 as compared to $42.7 million for the same period in
2008 due primarily to decreased activity levels. Segment profits decreased to 27% of revenues
during the second quarter of 2009 compared to 46% for the same period in 2008, due to activity
levels and rates declining faster than costs.
Direct operating expenses for the contract drilling segment decreased by 56% to $3.3 million
during the second quarter of 2009 as compared to $7.5 million for the same period in 2008 due
primarily to lower activity levels. Segment profits for this segment were 16% of revenues during
the second quarter of 2009 compared to 27% for the same period in 2008.
General and Administrative Expenses. General and administrative expenses increased by 2% to
$27.4 million during the second quarter of 2009 from $26.8 million for the same period in 2008,
which included $1.3 million and $1.2 million in stock-based compensation expense during the second
quarter of 2009 and 2008, respectively. The increase primarily reflects higher salary and office
expenses related to businesses acquired during 2008.
Depreciation and Amortization Expenses. Depreciation and amortization expenses were $32.4
million during the second quarter of 2009 as compared to $28.7 million for the same period in 2008,
reflecting the increase in the size of and investment in our asset base, due to acquisitions as
well as the internal expansion of our business segments.
Interest Expense. Interest expense decreased by 7% to $6.0 million during the second quarter
of 2009 compared to $6.5 million for the same period in 2008. The decrease was due primarily to
lower interest rates on our revolving line of credit.
Income Tax Expense. There was an income tax benefit of $13.9 million during the second quarter
of 2009 as compared to an income tax expense of $11.6 million for the same period in 2008. Our
effective tax rate during the second quarter of 2009 and 2008 was approximately 39% and 38%,
respectively.
Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
Revenues. Revenues decreased by 43% to $273.5 million during the first six months of 2009 from
$481.4 million during the same period in 2008. This decrease was primarily due to lower
expenditures by our customers for our services and increased price competition from our competitors
due to the decline in oil and gas prices.
Well servicing revenues decreased by 50% to $85.2 million during the first six months of 2009
compared to $169.5 million during the same period in 2008. This decrease was due to the decrease in
rig utilization to 41% during the first six months of 2009 from 75% during the first six months of
2008, along with a decrease in revenue per rig hour to $351 during the first six months of 2009
from $399 during the first six months of 2008. These decreases were due to decreased expenditures
by our customers for our services along with increased price competition from our competitors. Our
average number of well servicing rigs increased to 414 during the first six months of 2009 compared
to 398 in the same period in 2008, due to internal expansion from our newbuild rig program and the
Lackey Construction, LLC and the Triple N Services, Inc. acquisitions.
Fluid services revenues decreased by 21% to $114.1 million during the first six months of 2009
compared to $144.0 million in the same period in 2008. This decrease was primarily due to decreased
rates that we charged to our customers for our services caused by increased price competition from
our competitors. These decreases were partially offset by the Azurite acquisition in September 2008
which added 98 fluid service trucks and 632 frac tanks. This acquisition added approximately $16.6
million of revenues during the first six months of 2009. Our weighted average number of fluid
service trucks increased to 811 during the first six months of 2009 from 654 in the same period in
2008, although our revenue per fluid service truck decreased to $141,000 in the first six months of
2009 compared to $220,000 in the same period in 2008.
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Completion and remedial services revenues decreased by 55% to $66.6 million during the first
six months of 2009 compared to $148.0 million in the same period in 2008. The decrease in revenue
between these periods was due to decreased utilization of equipment due to the decline in oil and gas prices. Increased market competition also caused
significant rate declines. Total hydraulic horsepower increased to 139,000 at June 30, 2009 from
128,000 at June 30, 2008.
Contract drilling revenues decreased by 62% to $7.6 million during the first six months in
2009 compared to $19.8 million in the same period in 2008. The number of rig operating days
decreased to 562 in first six months of 2009 compared to 1,344 in the first six months of 2008.
This decrease was due to lower new well starts in all of our geographic markets.
Direct Operating Expenses. Direct operating expenses, which primarily consist of labor,
including workers compensation and health insurance, fuel and maintenance and repair costs,
decreased by 32% to $198.7 million during the first six months of 2009 from $291.8 million in the
same period in 2008. This decrease was due to the lower activity levels in all of our segments.
Direct operating expenses for the well servicing segment decreased by 38% to $64.7 million
during the first six months of 2009 as compared to $103.8 million for the same period in 2008, due
primarily to the decrease in rig hours to 242,800 in the first six months of 2009 from 424,800 for
the same period in 2008. Segment profits decreased to 24% of revenues during the first six months
of 2009 compared to 39% for the same period in 2008, which reflects the faster decline in activity
levels and rates than in costs.
Direct operating expenses for the fluid services segment decreased by 16% to $80.0 million
during the first six months of 2009 as compared to $95.0 million for the same period in 2008, which
is due to lower activity levels being partially offset by the Azurite acquisition in September 2008
which added approximately $12.6 million in direct operating expenses in the first six months 2009.
Segment profits were 30% of revenues during the first six months of 2009 compared to 34% for the
same period in 2008.
Direct operating expenses for the completion and remedial services segment decreased by 40% to
$47.4 million during the first six months of 2009 as compared to $78.4 million for the same period
in 2008 due primarily to decreased activity levels. Segment profits decreased to 29% of revenues
during the first six months of 2009 compared to 47% for the same period in 2008, due to activity
levels and rates declining faster than costs.
Direct operating expenses for the contract drilling segment decreased by 55% to $6.6 million
during the first six months of 2009 as compared to $14.6 million for the same period in 2008 due
primarily to lower activity levels. Segment profits for this segment were 13% of revenues during
the first six months of 2009 compared to 26% for the same period in 2008.
General and Administrative Expenses. General and administrative expenses increased by 7% to
$56.5 million during the first six months of 2009 from $52.7 million for the same period in 2008,
which included $2.7 million and $2.3 million in stock-based compensation expense during the first
six months of 2009 and 2008, respectively. The increase primarily reflects higher salary and office
expenses related to businesses acquired during 2008.
Depreciation and Amortization Expenses. Depreciation and amortization expenses were $65.2
million during the first six months of 2009 as compared to $56.8 million for the same period in
2008, reflecting the increase in the size of and investment in our asset base, due to acquisitions
as well as the internal expansion of our business segments.
Goodwill Impairment. In the first six months of 2009, we recorded a non-cash charge totaling
$204.0 million for impairment of all of the goodwill associated with our well servicing, fluid
services, and completion and remedial services segments.
Interest Expense. Interest expense decreased by 15% to $11.7 million during the first six
months of 2009 compared to $13.8 million for the same period in 2008. The decrease was due
primarily to lower interest rates on our revolving line of credit.
Income Tax Expense. There was an income tax benefit of $59.2 million during the first six
months of 2009 as compared to an income tax expense of $23.3 million for the same period in 2008.
Our effective tax rate during the first six months of 2009 and 2008 was approximately 22% and 38%,
respectively.
Liquidity and Capital Resources
As of June 30,2009, our primary capital resources were net cash flows from our operations,
utilization of capital leases as allowed under our Fourth Amended and Restated Credit Agreement, as
amended by Amendment and Consent No. 1 thereto (the Credit Facility), and availability under our
Credit Facility, under which approximately $28.8 million of borrowing capacity was available at
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June 30, 2009. As of June 30, 2009, we had cash and cash equivalents of $134.3 million compared to
$111.1 million as of December 31, 2008. When appropriate, we will consider public or private debt and equity offerings and
non-recourse transactions to meet our liquidity needs.
On July 31, 2009, we completed the sale of $225 million principal amount of our 11.625% Senior
Secured Notes due 2014 (the Senior Secured Notes). The
net proceeds of $208.4 million were used
to repay the $180.0 million of borrowings outstanding under the Credit Facility as of July 31,
2009. The Credit Facility was then terminated, and we are unable to borrow any amounts under it.
We expect to rely on cash on hand in the near term and to evaluate alternatives with respect to a
new revolving credit facility or letter of credit facility in the future to address our long term
liquidity requirements. The indenture governing the Senior Secured Notes limits the amount that we
could borrow under a future secured credit facility to the difference between (i) $240 million and
(ii) the sum of (a) $212.9 million (the principal amount of the Senior Secured Notes, net of
offering discount) and (b) our outstanding collateralized letters of credit, subject to possible
upward adjustment of the amount in clause (i) based on our consolidated tangible assets. We
currently believe that our operating cash flows and cash on hand will be sufficient to fund our
near term liquidity requirements.
Net Cash Provided by Operating Activities
Cash flow from operating activities was $73.0 million for the six months ended June 30, 2009
as compared to $87.3 million during the same period in 2008. Operating cash flow was lower due to
the decrease in revenues partially offset by a decrease in our accounts receivable.
Capital Expenditures
Capital expenditures are the main component of our investing activities. Cash capital
expenditures (including acquisitions) during the first six months of 2009 were $26.4 million as
compared to $96.3 million in the same period of 2008. We added
$15.4 million of additional assets
through our capital lease program during the first six months of 2009 compared to $20.5 million in
the same period in 2008.
For 2009, we currently have planned approximately $40 million in cash capital expenditures and
$17.5 million in capital leases, none of which is planned for acquisitions. We do not budget
acquisitions in the normal course of business. The $57.5 million of capital expenditures planned
for property and equipment is primarily for (1) purchase of additional equipment to expand our
services, (2) continued refurbishment of our well servicing rigs and (3) replacement of existing
equipment. We regularly engage in discussions related to potential acquisitions related to the well
services industry.
Capital Resources and Financing
We currently believe that our operating cash flows and cash on hand will be sufficient to fund
our near term liquidity requirements.
Our ability to access additional sources of financing will be dependent on our operating cash
flows and demand for our services, which could be negatively impacted due to the extreme volatility
of commodity prices and declines in capital and debt markets.
Senior Notes
In April 2006, we completed a private offering of $225 million aggregate principal amount of
7.125% Senior Notes due April 15, 2016. The Senior Notes are jointly and severally guaranteed by
each of our subsidiaries. The net proceeds from the offering were used to retire our outstanding
Term B Loan balance and to pay down the outstanding balance under our previous credit facility.
Remaining proceeds were used for general corporate purposes, including acquisitions.
We issued the Senior Notes pursuant to an indenture, dated as of April 12, 2006, by and among
us, the guarantor parties thereto and The Bank of New York Trust Company, N.A., as trustee.
Interest on the Senior Notes accrues at a rate of 7.125% per year. Interest on the Senior
Notes is payable in cash semi-annually in arrears on April 15 and October 15 of each year. The
Senior Notes mature on April 15, 2016. The Senior Notes and the guarantees are unsecured and rank
equally with all of our and the guarantors existing and future unsecured and unsubordinated
obligations. The
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Senior Notes and the guarantees rank senior in right of payment to any of our and
the guarantors existing and future obligations that are, by their terms, expressly subordinated in right of payment to the Senior Notes and the
guarantees. The Senior Notes and the guarantees are effectively subordinated to our and the
guarantors secured obligations to the extent of the value of the assets securing such obligations.
The indenture contains covenants that limit the ability of us and certain of our subsidiaries
to:
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incur additional indebtedness; |
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pay dividends or repurchase or redeem capital stock; |
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make certain investments; |
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incur liens; |
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enter into certain types of transactions with affiliates; |
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limit dividends or other payments by restricted subsidiaries; and |
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sell assets or consolidate or merge with or into other companies. |
These limitations are subject to a number of important qualifications and exceptions.
Upon an Event of Default (as defined in the indenture), the trustee or the holders of at least
25% in aggregate principal amount of the Senior Notes then outstanding may declare all of the
amounts outstanding under the Senior Notes to be due and payable immediately.
We may, at our option, redeem all or part of the Senior Notes, at any time on or after April
15, 2011 at a redemption price equal to 100% of the principal amount thereof, plus a premium
declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.
If we experience certain kinds of changes of control, holders of the Senior Notes will be
entitled to require us to purchase all or a portion of the Senior Notes at 101% of their principal
amount, plus accrued and unpaid interest.
Credit Facility
On May 4, 2009 we entered into Amendment and Consent No. 1 (the Amendment) to our Fourth
Amended and Restated Credit Agreement, dated as of February 6, 2007 (the Existing Credit
Agreement). Among other things, the Amendment:
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created Tranche A Revolving Loans, which have the same maturity date as the revolving
loans under the Existing Credit Agreement (December 15, 2010), and Tranche B Revolving
Loans, which have an extended maturity date of January 31, 2012; |
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changed the applicable margins for Alternative Base Rate or Eurodollar revolving loans;
and |
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increased the maximum leverage ratio to 3.75 to 1.00 from 3.25 to 1.00. |
Under the Credit Facility, Basic Energy Services, Inc. was the sole borrower and each of our
subsidiaries was a subsidiary guarantor. The Credit Facility provided for a $225 million revolving
line of credit (the Revolver). The Credit Facility included provisions allowing us to request an
increase in commitments of up to $100.0 million aggregate principal amount subject to meeting
certain tangible value requirements and subject to lender participation at the time of the request.
The commitment under the Revolver provided for (1) the borrowing of funds, (2) the issuance of up
to $30 million of letters of credit and (3) $2.5 million of swing-line loans. The Credit Facility
was secured by substantially all of our tangible and intangible assets. The amount of commitments
under the Tranche A Revolving Loans was $80 million and amount under the Tranche B Revolving Loans
was $145 million.
For Tranche A Revolving Loans and Tranche B Revolving Loans, ABR Loans bore interest at the
highest of (i) the banks prime rate, (ii) the federal funds rate plus 0.50% per year, and (iii)
the adjusted LIBOR rate for an interest period of one-month beginning on
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the day of the ABR Loan plus 100 basis points, plus an applicable margin. The applicable margin for ABR Loans rangee from
0.25% to 0.50% for Tranche A Revolving Loans and ranged from 2.50% to 3.50% for Tranche B Revolving
Loans. The applicable margin for Eurodollar revolving loans with respect to any Tranche B Revolving
Loan ranged from 3.50% to 4.50%. Furthermore, the applicable commitment fee for the unused portion
of any Tranche B revolving commitments, based on average daily unused amounts, was 1.0% per annum,
as compared to 0.375% per annum for Tranche A revolving commitments.
Pursuant to the Credit Facility, we were required to apply proceeds from certain specified
events to reduce principal outstanding borrowings under the Revolver, including:
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assets sales greater than $2.0 million individually or $7.5 million in the aggregate on
an annual basis; |
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100% of the net cash proceeds from any debt issuance, including certain permitted
unsecured senior or senior subordinated debt, but excluding certain other permitted debt
issuances; and |
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50% of the net cash proceeds from any equity issuance (including equity issued upon the
exercise of any warrant or option). |
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The Credit Facility contained various restrictive covenants and compliance requirements,
including the following: |
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limitations on the incurrence of additional indebtedness; |
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restrictions on mergers, sales or transfer of assets without the lenders consent; |
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limitations on dividends and distributions; and |
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various financial covenants, including: |
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a maximum leverage ratio of 3.75 to 1.00, and |
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a minimum interest coverage ratio of 3.00 to 1.00. |
On July 31, 2009, in connection with our sale of the Senior Secured Notes, we repaid all of
the borrowings outstanding under the Credit Facility, and the Credit Facility was terminated.
Other Debt
We have a variety of other capital leases and notes payable outstanding that is generally
customary in our business. None of these debt instruments is material individually. As of June 30,
2009, we had total capital leases of approximately $75.3 million.
Credit Rating Agencies
In July 2009 our Senior Notes rating was changed from BB- to B- by Standard and Poors and B1
to Caa1 by Moodys. Our Credit Facility rating was changed from
BB+ to BB- by Standard and Poors
and Ba1 to Ba2 by Moodys. Our Senior Unsecured Notes were rated at BB- by Standard and Poors and
Ba3 by Moodys.
Preferred Stock
At June 30, 2009 and December 31, 2008, we had 5,000,000 shares of $.01 par value preferred
stock authorized, of which none was designated, issued or outstanding.
Other Matters
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a current
or future effect on our financial condition or results of operations.
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Net Operating Losses
As of June 30, 2009, we had approximately $2.3 million of net operating loss carryforwards
related to the pre-acquisition period of a 2003 acquisition, which are subject to an annual
limitation of approximately $900,000. The carryforwards begin to expire in 2017.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157,
Fair Value Measurements (SFAS No. 157), which became effective for our financial assets and
liabilities on January 1, 2008 and became effective for our non-financial assets and liabilities on
January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value
and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair
value measurements but would apply to assets and liabilities that are required to be recorded at
fair value under other accounting standards. This standard was adopted for financial assets and
liabilities as of January 1, 2008 and was adopted for non-financial assets and liabilities,
including fair value measurements for asset impairments, goodwill and intangible asset impairments,
purchase price allocations and asset retirement obligations, on January 1, 2009. The adoption of
this standard did not have any impact on the fair value of any of our financial assets or
liabilities.
In December 2007, the FASB issued SFAS No. 141R, Business Combination s (SFAS No. 141R),
which became effective for us on January 1, 2009. This Statement requires an acquirer to recognize
the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at
the acquisition date at their fair values as of that date. An acquirer is required to recognize
assets or liabilities arising from all other contingencies (contractual contingencies) as of the
acquisition date, measured at their acquisition-date fair values, only if it is more likely than
not that they meet the definition of an asset or a liability in FASB Concepts Statement No. 6,
Elements of Financial Statements. Any acquisition related costs are to be expensed instead of
capitalized. The impact to us from the adoption of SFAS No. 141R in 2009 will vary acquisition by
acquisition.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements (SFAS No. 160), which became effective for us on January 1, 2009. This
standard establishes accounting and reporting standards for ownership interests in subsidiaries
held by parties other than the parent, the amount of consolidated net income attributable to the
parent and to the noncontrolling interest, changes in a parents ownership interest and the
valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The
Statement also establishes reporting requirements that provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and the interests of the
non-controlling owners. This pronouncement has not had a significant impact on our results of
operation or consolidated financial position since we do not have any noncontrolling interests.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities (SFAS No. 161), which became effective for us on January 1, 2009. This
standard improves financial reporting for derivative instruments and hedging activities by
requiring enhanced disclosures to expand on these instruments effects on a companys financial
position, financial performance and cash flows. This pronouncement has not had a significant impact
on our results of operation or consolidated financial position since we do not have any derivative
instruments.
In April 2008, the FASB issued FASB Staff Position SFAS No. 142-3, Determination of Useful
Life of Intangible Assets (FSP No. 142-3). FSP No. 142-3 amends the factors that should be
considered in developing the renewal or extension assumptions used to determine the useful life of
a recognized intangible asset under SFAS No. 142. FSP No. 142-3 is effective for fiscal years
beginning after December 15, 2008. This pronouncement has not had a significant impact on our
results of operation or consolidated financial position.
In June 2008, the FASB issued FASB Staff Position EITF 03-6-1, Determining Whether
Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF
03-6-1). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions
are participating securities prior to vesting and, therefore, need to be included in the earnings
allocation in computing earnings per share (EPS) under the two-class method described in
paragraphs 60 and 61 of SFAS No. 128, Earnings Per Share. FSP EITF 03-6-1 is effective for
financial statements issued for fiscal years and interim periods beginning after December 15, 2008
and requires retrospective adjustment for all comparable prior periods presented. FSP EITF 03-6-1
has not had a significant impact on our results of operation or consolidated financial position
since we do not have any participating securities.
38
In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS No. 165), which became
effective for us on April 1, 2009. This standard establishes principles and requirements for
disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential
disclosure. It also establishes the circumstances under which an entity shall recognize events or
transactions occurring after the balance sheet date. The adoption of
this standard requires the Company to disclose the date through which
subsequent events have been reviewed.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and
the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement no. 162
(SFAS No. 168), which became effective for us on July 1, 2009. SFAS No. 168 establishes the FASB
Accounting Standards Codification as the source of authoritative accounting principles recognized
by the FASB to be applied by nongovernmental entities in the preparation of financial statements in
conformity with GAAP. SFAS No. 168 is not expected to change GAAP and will not have a material
impact on our consolidated financial statements.
Impact of Inflation on Operations
Management is of the opinion that inflation has not had a significant impact on our business,
other than increases in fuel costs and personnel expenses during 2008.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As of June 30, 2009, we had $180.0 million outstanding under the revolving portion of our
credit facility subject to variable interest rate risk. The impact of a 1% increase in interest
rates on this amount of debt would result in increased interest expense of approximately $1.8
million annually and a decrease in net income of approximately $1.1 million.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Based on their evaluation as of the end of the period covered by this report, our principal
executive officer and principal financial officer have concluded that our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to
ensure that information required to be disclosed in reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time periods specified in
the SECs rules and forms and effective to ensure that information required to be disclosed in such
reports is accumulated and communicated to our management, including our principal executive
officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the most recent fiscal quarter, there have been no changes in our internal control over
financial reporting that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, Basic is a party to litigation or other legal proceedings that Basic
considers to be a part of the ordinary course of business. Basic is not currently involved in any
legal proceedings that it considers probable or reasonably possible, individually or in the
aggregate, to result in a material adverse effect on its financial condition, results of operations
or liquidity.
ITEM 1A. RISK FACTORS
For information regarding risks that may affect our business, see the risk factors included in
our most recent annual report on Form 10-K under the heading Risk Factors.
39
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes stock repurchase activity for the three months ended June 30,
2009 (dollars in thousands, except average price paid per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuer Purchases of Equity Securities |
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Approximate Dollar Value |
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
of Shares that May Yet |
|
|
Total Number of |
|
Average Price Paid |
|
Part of Publicly |
|
be Purchased Under |
Period |
|
Shares Purchased (1) |
|
per share |
|
Announced Program |
|
the Program (2) |
April 1 April 30 |
|
|
1,978 |
|
|
$ |
6.70 |
|
|
|
|
|
|
$ |
35,188 |
|
May 1 May 31 |
|
|
572 |
|
|
$ |
10.09 |
|
|
|
|
|
|
$ |
35,188 |
|
June 1 June 30 |
|
|
635 |
|
|
$ |
7.50 |
|
|
|
|
|
|
$ |
35,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,185 |
|
|
$ |
7.47 |
|
|
|
|
|
|
$ |
35,188 |
|
|
|
|
(1) |
|
These shares were repurchased from various employees to provide such employees the cash
amounts necessary to pay certain tax liabilities associated with the vesting of restricted
shares owned by them. The shares were repurchased on various dates based on the average price
per share on the date of repurchase. |
|
(2) |
|
On October 13, 2008, we announced that our Board of Directors had authorized the repurchase
of up to $50.0 million of shares of our common stock from time to time in open market or
private transactions, at our discretion. The stock repurchase program was suspended by the
Board of Directors during the first quarter of 2009. |
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We held our Annual Meeting of Stockholders (the Annual Meeting) on May 26, 2009 in Midland,
Texas to elect three Class I directors to serve until the Annual Meeting of Stockholders in 2012,
to approve the Fourth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan and to
approve the ratification of the appointment of KPMG LLP as our independent auditor for fiscal year
2009. A total of 39,996,668 shares of our common stock were present at the meeting in person or by
proxy, which represented 98.3% of the outstanding shares of our common stock as of April 23, 2009,
the record date for the Annual Meeting.
Director nominees were elected at the Annual Meeting based on the following vote tabulation:
|
|
|
|
|
|
|
|
|
|
|
Votes in Favor |
|
Votes Withheld |
Steven A. Webster |
|
|
30,164,578 |
|
|
|
9,832,089 |
|
H. H. Wommack, III |
|
|
31,477,260 |
|
|
|
8,519,407 |
|
Sylvester P. Johnson, IV |
|
|
34,057,967 |
|
|
|
5,938,700 |
|
The directors with terms of office continuing after the Annual Meeting are as follows:
The Directors with terms expiring in 2010
William E. Chiles
Robert F. Fulton
The Directors with terms expiring in 2011
James S. DAgostino
Kenneth V. Huseman
Thomas P. Moore, Jr.
Stockholders approved the Fourth Amended and Restated Basic Energy Services, Inc. 2003
Incentive Plan at the Annual Meeting based on the following vote tabulation:
|
|
|
|
|
|
|
For |
|
Against |
|
Abstentions |
|
Broker Non-Vote |
35,148,865
|
|
739,878
|
|
19,315
|
|
4,088,610 |
40
Stockholders approved the ratification of the appointment of KPMG LLP as our independent
auditor for fiscal year 2009 at the Annual Meeting based on the following vote tabulation:
|
|
|
|
|
For |
|
Against |
|
Abstentions |
39,935,633
|
|
43,415
|
|
17,619 |
41
ITEM 6. EXHIBITS
|
|
|
Exhibit |
|
|
No. |
|
Description |
|
|
|
3.1*
|
|
Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005.
(Incorporated by reference to Exhibit 3.1 of the Companys Registration Statement on Form S-1 (SEC File
No. 333-127517), filed on September 28, 2005) |
|
|
|
3.2*
|
|
Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by
reference to Exhibit 3.1 of the Companys Current Report on Form 8-K (SEC File No. 001-32693), filed on
December 18, 2007) |
|
|
|
4.1*
|
|
Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to
Exhibit 3.1 of the Companys Registration Statement on Form S-1 (SEC File No. 333-127517), filed on
November 4, 2005) |
|
|
|
4.2*
|
|
Indenture dated April 12, 2006, among the Company, the guarantors party thereto, and The Bank of New
York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Companys
Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006) |
|
|
|
4.3*
|
|
Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Companys
Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006) |
|
|
|
4.4*
|
|
First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among
the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company,
N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Companys Current Report on Form 8-K
(SEC File No. 001-32693), filed on July 20, 2006) |
|
|
|
4.5*
|
|
Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture
dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the
Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on form 8-K (SEC File No 001-32693), filed on May 1, 2007) |
|
|
|
4.6*
|
|
Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among
the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company,
N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Companys Current Report on Form 8-K
(SEC File No 001-32693), filed on May 1, 2007) |
|
|
|
4.7*
|
|
Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006
among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon
Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Companys Annual
Report on Form 10-K (SEC File No. 001-32693), filed March 19, 2009) |
|
|
|
31.1
|
|
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act |
|
|
|
31.2
|
|
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act |
|
|
|
32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
Incorporated by reference |
42
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
|
BASIC ENERGY SERVICES, INC. |
By: |
/s/ Kenneth V. Huseman
|
|
|
|
Name: |
Kenneth V. Huseman |
|
|
|
Title: |
President, Chief Executive Officer and
Director (Principal Executive Officer) |
|
|
|
|
|
|
By: |
/s/ Alan Krenek
|
|
|
|
Name: |
Alan Krenek |
|
|
|
Title: |
Senior Vice President, Chief Financial
Officer, Treasurer and Secretary (Principal
Financial Officer and Principal Accounting Officer) |
|
|
Date: July 31, 2009
43
Exhibit Index
|
|
|
Exhibit |
|
|
No. |
|
Description |
|
|
|
3.1*
|
|
Amended and Restated Certificate of Incorporation of the Company, dated September 22, 2005.
(Incorporated by reference to Exhibit 3.1 of the Companys Registration Statement on Form S-1 (SEC File
No. 333-127517), filed on September 28, 2005) |
|
|
|
3.2*
|
|
Amended and Restated Bylaws of the Company, effective as of December 17, 2007. (Incorporated by
reference to Exhibit 3.1 of the Companys Current Report on Form 8-K (SEC File No. 001-32693), filed on
December 18, 2007) |
|
|
|
4.1*
|
|
Specimen Stock Certificate representing common stock of the Company. (Incorporated by reference to
Exhibit 3.1 of the Companys Registration Statement on Form S-1 (SEC File No. 333-127517), filed on
November 4, 2005) |
|
|
|
4.2*
|
|
Indenture dated April 12, 2006, among the Company, the guarantors party thereto, and The Bank of New
York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Companys
Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006) |
|
|
|
4.3*
|
|
Form of 7.125% Senior Note due 2016. (Included in the Indenture filed as Exhibit 4.1 of the Companys
Current Report on Form 8-K (SEC File No. 001-32693), filed on April 13, 2006) |
|
|
|
4.4*
|
|
First Supplemental Indenture dated as of July 14, 2006 to Indenture dated as of April 12, 2006 among
the Company, as Issuer, the Subsidiary Guarantors named therein and The Bank of New York Trust Company,
N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Companys Current Report on Form 8-K
(SEC File No. 001-32693), filed on July 20, 2006) |
|
|
|
4.5*
|
|
Second Supplemental Indenture dated as of April 26, 2007 and effective as of March 7, 2007 to Indenture
dated as of April 12, 2006 among the Company as Issuer, the Subsidiary Guarantors named therein and the
Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the
Companys Current Report on form 8-K (SEC File No 001-32693), filed on May 1, 2007) |
|
|
|
4.6*
|
|
Third Supplemental Indenture dated as of April 26, 2007 to Indenture dated as of April 12, 2006 among
the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Trust Company,
N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Companys Current Report on Form 8-K
(SEC File No 001-32693), filed on May 1, 2007) |
|
|
|
4.7*
|
|
Fourth Supplemental Indenture dated as of February 9, 2009 to Indenture dated as of April 12, 2006
among the Company as Issuer, the Subsidiary Guarantors named therein and the Bank of New York Mellon
Trust Company, N.A., as Trustee. (Incorporated by reference to Exhibit 4.7 of the Companys Annual
Report on Form 10-K (SEC File No. 001-32693), filed March 19, 2009) |
|
|
|
31.1
|
|
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act |
|
|
|
31.2
|
|
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act |
|
|
|
32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
Incorporated by reference |
44