|
|
|
|
|
|
2009
|
|
$
|
71,358
|
|
|
2010
|
|
|
1,411
|
|
|
2011
|
|
|
1,073
|
|
|
2012
|
|
|
752
|
|
|
2013
|
|
|
776
|
|
|
2014
and thereafter
|
|
|
1,575
|
|
|
|
|
$
|
76,945
|
|
|
|
|
|
|
|
4.
Workers’ Compensation and Health Insurance
The
Company is insured under a large deductible workers’ compensation insurance
policy. The policy generally provides for a $1,000 deductible per covered
accident. The Company maintains letters of credit in the aggregate amount of
$7,330 for the benefit of various insurance companies as collateral for
retrospective premiums and retained losses which may become payable under the
terms of the underlying insurance contracts. The letters of credit
are typically renewed annually. No amounts have been drawn under the
letters of credit. At June 30, 2008 and December 31, 2007, the Company had
deposits of $2,815 and $2,745, respectively, with an insurance company
collateralizing a letter of credit. The deposit is reflected in restricted cash
and deposit. Accrued expenses at June 30, 2008 and December 31, 2007 included
approximately $2,665 and $2,959, respectively, for estimated incurred but not
reported costs and premium accruals related to our workers’ compensation
insurance.
On
November 1, 2005, the Company initiated a self-insurance program for major
medical, hospitalization and dental coverage for employees and their dependents,
which is partially funded by payroll deductions. The Company provided for both
reported and incurred but not reported medical costs in the accompanying
consolidated balance sheets. We have a maximum liability of $100 per
employee/dependent per year. Amounts in excess of the stated maximum are covered
under a separate policy provided by an insurance company. Accrued expenses at
June 30, 2008 and December 31, 2007 included approximately $1,250 and $409,
respectively, for our estimate of incurred but not reported costs related to the
self-insurance portion of our health insurance.
5.
Transactions with Affiliates
The
Company has five operating leases with affiliated entities. Related
rent expense was approximately $86 and $156 for the three months and six months
ended June 30, 2008.
The
Company provided contract drilling services totaling $1,109 to affiliated
entities during the three and six months ended June 30,
2008. The Company provided contract drilling services totaling
$0 and $2,616 to affiliated entities during the three and six months ended June
30, 2007.
6.
Commitments and Contingencies
Following
the announcement of the merger agreement on January 24, 2008, three
purported class action complaints were filed challenging the proposed merger
between Allis-Chalmers Energy Inc. (“Allis-Chalmers”), the Company and Elway
Merger Sub, Inc. (“Merger Sub”). Two complaints were filed in Oklahoma in the
District Court of Oklahoma County, the first on
January 29, 2008 (the “Boothe action”), and the second on February 28,
2008 (the “Goff action”). The defendants named in both actions are the Company,
the board of directors of the Company and Allis-Chalmers. On April 9, 2008,
the Boothe action and the Goff action were consolidated into a single action
(together, the “Oklahoma action”). The defendants named in the Oklahoma action
are the Company, the board of directors of the Company and Allis-Chalmers. The
third complaint was filed in the Delaware Court of Chancery on January 29,
2008 (the “Delaware action”). The defendants named in the Delaware action are
the Company, the board of directors of the Company, Allis-Chalmers and Merger
Sub.
The
Oklahoma and Delaware actions generally allege that the proposed merger
consideration is inadequate, that the board of directors of the Company breached
its fiduciary duties and that Allis-Chalmers has aided and abetted the Company
board of directors’ alleged breaches of fiduciary duties. The actions also
allege that the preliminary joint proxy statement/prospectus included as part of
Allis-Chalmers’ registration statement on Form S-4, filed with the SEC on
February 20, 2008, contains materially incomplete and misleading
information. The actions generally request, among other things, that the suits
be designated class actions on behalf of the Company’s stockholders, that the
proposed merger be enjoined and that the board of directors of the Company
undertake an auction of the Company or otherwise take action to maximize
stockholder value. Additionally, the Delaware action requests that all allegedly
misleading or omitted information be corrected in Allis-Chalmers’ preliminary
joint proxy statement/prospectus. The Delaware action seeks monetary damages for
the Company’s stockholders and the Oklahoma action requests that the proposed
merger be rescinded if it is consummated.
Allis-Chalmers
and the Company filed motions to dismiss the Boothe action on February 21,
2008 and February 19, 2008, respectively. In response to these motions, the
parties to the Boothe action agreed to extend the time for the plaintiff to
amend his complaint, and for the defendants to amend or withdraw their motions
to dismiss, or file answers to the amended complaint. After the Boothe action
and the Goff action were consolidated into the Oklahoma action on April 9,
2008, the plaintiffs in the Oklahoma action filed a consolidated amended
complaint on April 17, 2008. Allis-Chalmers filed a motion to dismiss the
amended complaint on May 14, 2008, and the Company and the board of
directors of the Company filed a motion to dismiss the amended complaint on
May 19, 2008. In response to these motions, the parties to the Oklahoma
action agreed to extend the time for the plaintiffs to respond to the
defendants’ motions to dismiss. Under the agreement, the plaintiffs must respond
by September 3, 2008. Discovery in the Oklahoma action is ongoing at this
time.
The
plaintiff in the Delaware action filed an amended complaint on April 23,
2008. The parties to the Delaware action agreed to indefinitely extend the time
for the defendants to respond to the plaintiff’s amended complaint. Under the
agreement, no defendant must answer the plaintiff’s amended complaint or
otherwise respond until one of the following two events occurs: (1) the
plaintiff files a second amended complaint, in which case the defendants will
have 30 days from the date of service to answer the second amended complaint or
otherwise respond; or (2) the plaintiff provides written notice to all the
defendants that each defendant must answer the amended complaint, in which case
each defendant will have, upon receiving the written notice, 30 days to answer
the amended complaint or otherwise respond. Discovery in the Delaware action is
ongoing at this time.
Allis-Chalmers,
the Company, the board of directors of the Company and Merger Sub deny the
substantive allegations in the two complaints, believe the claims asserted are
baseless and intend to vigorously defend these actions. As of this
time, no order has been issued in either proceeding that would preclude the
consummation of the merger. Each of Allis-Chalmers and the Company
has the right to terminate the merger agreement in the event a court enjoins the
consummation of the merger.
Various
other claims and lawsuits, incidental to the ordinary course of business, are
pending against the Company. In the opinion of management, all matters are
adequately covered by insurance or, if not covered, are not expected to have a
material effect on the Company’s consolidated financial position, results of
operations or cash flows.
7.
Business Segments
The
Company’s reportable business segments are contract land drilling and well
servicing. The contract drilling segment utilizes a fleet of land
drilling rigs to provide contract drilling services to oil and natural gas
exploration and production companies. During the six months ended
June 30, 2008, our drilling rigs operated in Oklahoma, Texas, Colorado, Montana,
Utah, North Dakota, and Louisiana. The well servicing 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. During the
six months ended June 30, 2008, our workover rigs operated in Oklahoma, Texas,
Kansas, Colorado, Arkansas, Wyoming, and New Mexico. The accounting
policies of the segments are the same as those described in the summary of
significant accounting policies. The Company’s reportable segments
are strategic business units that offer different products and
services.
The following table sets forth
certain financial information with respect to the Company’s reportable
segments:
|
|
|
Contract
drilling
|
|
|
Well
servicing
|
|
|
Total
|
|
|
Three
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
60,494
|
|
|
$
|
9,320
|
|
|
$
|
69,814
|
|
|
Direct
operating costs
|
|
|
(36,715
|
)
|
|
|
(6,079
|
)
|
|
|
(42,794
|
)
|
|
Segment
profits
|
|
$
|
23,779
|
|
|
$
|
3,241
|
|
|
$
|
27,020
|
|
|
Depreciation
and amortization
|
|
$
|
11,027
|
|
|
$
|
1,430
|
|
|
$
|
12,457
|
|
|
Capital
expenditures
|
|
$
|
17,130
|
|
|
$
|
4,501
|
|
|
$
|
21,631
|
|
|
Identifiable
assets
|
|
$
|
534,738
|
|
|
$
|
65,051
|
|
|
$
|
599,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
69,291
|
|
|
$
|
5,429
|
|
|
$
|
74,720
|
|
|
Direct
operating costs
|
|
|
(40,514
|
)
|
|
|
(3,280
|
)
|
|
|
(43,794
|
)
|
|
Segment
profits
|
|
$
|
28,777
|
|
|
$
|
2,149
|
|
|
$
|
30,926
|
|
|
Depreciation
and amortization
|
|
$
|
9,997
|
|
|
$
|
897
|
|
|
$
|
10,894
|
|
|
Capital
expenditures
|
|
$
|
7,302
|
|
|
$
|
8,315
|
|
|
$
|
15,617
|
|
|
Identifiable
assets
|
|
$
|
484,506
|
|
|
$
|
44,679
|
|
|
$
|
529,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
drilling
|
|
|
Well
servicing
|
|
|
Total
|
|
|
Six
Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
114,567
|
|
|
$
|
17,543
|
|
|
$
|
132,110
|
|
|
Direct
operating costs
|
|
|
(69,909
|
)
|
|
|
(11,022
|
)
|
|
|
(80,931
|
)
|
|
Segment
profits
|
|
$
|
44,658
|
|
|
$
|
6,521
|
|
|
$
|
51,179
|
|
|
Depreciation
and amortization
|
|
$
|
21,649
|
|
|
$
|
2,733
|
|
|
$
|
24,382
|
|
|
Capital
expenditures
|
|
$
|
32,470
|
|
|
$
|
7,689
|
|
|
$
|
40,159
|
|
|
Identifiable
assets
|
|
$
|
534,738
|
|
|
$
|
65,051
|
|
|
$
|
599,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
143,870
|
|
|
$
|
9,831
|
|
|
$
|
153,701
|
|
|
Direct
operating costs
|
|
|
(81,313
|
)
|
|
|
(5,922
|
)
|
|
|
(87,235
|
)
|
|
Segment
profits
|
|
$
|
62,557
|
|
|
$
|
3,909
|
|
|
$
|
66,466
|
|
|
Depreciation
and amortization
|
|
$
|
20,499
|
|
|
$
|
1,600
|
|
|
$
|
22,099
|
|
|
Capital
expenditures
|
|
$
|
21,796
|
|
|
$
|
10,030
|
|
|
$
|
31,826
|
|
|
Identifiable
assets
|
|
$
|
484,506
|
|
|
$
|
44,679
|
|
|
$
|
529,185
|
|
The following
table reconciles the segment profits above to the operating income as reported
in the consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Three
Months Ended
|
|
|
|
|
June
30, 2008
|
|
|
June
30, 2007
|
|
|
Segment
profits
|
|
$
|
27,020
|
|
|
$
|
30,926
|
|
|
General
and administrative expenses
|
|
|
(5,414
|
)
|
|
|
(5,399
|
)
|
|
Depreciation
and amortization
|
|
|
(12,457
|
)
|
|
|
(10,894
|
)
|
|
Gain
(Loss) on Challenger transaction
|
|
|
(1,507
|
)
|
|
|
-
|
|
|
Operating
income
|
|
$
|
7,642
|
|
|
$
|
14,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
|
June
30, 2008
|
|
|
June
30, 2007
|
|
|
Segment
profits
|
|
$
|
51,179
|
|
|
$
|
66,466
|
|
|
General
and administrative expenses
|
|
|
(11,153
|
)
|
|
|
(10,091
|
)
|
|
Depreciation
and amortization
|
|
|
(24,382
|
)
|
|
|
(22,099
|
)
|
|
Gain
(Loss) on Challenger transaction
|
|
|
3,200
|
|
|
|
-
|
|
|
Operating
income
|
|
$
|
18,844
|
|
|
$
|
34,276
|
|
|
|
|
|
|
|
|
|
|
|
8.
Net Income Per Common Share
The
following table presents a reconciliation of the numerators and denominators of
the basic and diluted earnings per share (“EPS”) and diluted EPS comparisons as
required by SFAS No. 128:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
4,339
|
|
|
$
|
8,714
|
|
|
$
|
12,487
|
|
|
$
|
20,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares
|
|
|
26,270
|
|
|
|
26,019
|
|
|
|
26,267
|
|
|
|
25,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
$
|
0.17
|
|
|
$
|
0.33
|
|
|
$
|
0.48
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
4,339
|
|
|
$
|
8,714
|
|
|
$
|
12,487
|
|
|
$
|
20,101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
(thousands)
|
|
|
26,270
|
|
|
|
26,019
|
|
|
|
26,267
|
|
|
|
25,963
|
|
|
Restricted
stock/Options (thousands)
|
|
|
118
|
|
|
|
97
|
|
|
|
73
|
|
|
|
65
|
|
|
|
|
|
26,388
|
|
|
|
26,116
|
|
|
|
26,340
|
|
|
|
26,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
per share
|
|
$
|
0.16
|
|
|
$
|
0.33
|
|
|
$
|
0.47
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average number of diluted shares
excludes 0 and 25,584 shares for the three months ended June 30, 2008 and 2007,
respectively, and 2,097 and 31,310 shares for the six months ended
respectively, subject to restricted stock awards due
to their antidilutive effects.
9.
Equity Transactions
In March
2007, the Company closed a public offering of 3,450,000 shares of common stock
at a price of $22.75 per share. In the offering, a total of 1,700,000 shares
were sold by the Company and 1,750,000 shares were sold by the selling
stockholder. The offering resulted in net proceeds to the Company of
approximately $36,229, excluding offering expenses of $577. The Company did not
receive any proceeds from the sale of shares by the selling
stockholder.
Effective
January 9, 2007, the Company issued 1,070,390 shares of common stock to the
equity owners of Eagle in connection with the Company’s acquisition of
Eagle.
10.
Stock Options and Stock Option Plan
The Company’s
2005 Stock Incentive Plan was adopted on July 20, 2005 and amended on
November 16, 2005 (the “2005 Plan”). The compensation cost that has been
charged against income before taxes related to stock options was $480 and $1,007
for the three and six months ended June 30, 2007, respectively. These
options are reported as equity instruments and their fair value is amortized to
expense using the straight line method over the vesting period. The shares of
stock issued upon the exercise of the options will be from authorized but
unissued common stock.
The
Company receives a tax deduction for certain stock option exercises during the
period the options are exercised, generally for the excess of the price at which
the options are sold over the exercise price of the options. There have been no
stock options exercised under the 2005 Plan.
The
purpose of the 2005 Plan was to enable the Company, and any of its affiliates,
to attract and retain the services of the types of employees, consultants and
directors who will contribute to its long-range success and to provide
incentives which are linked directly to increases in share value which will
inure to the benefit of the Company’s stockholders. The 2005 Plan provided a
means by which eligible recipients of awards may be given an opportunity to
benefit from increases in value of the Company’s common stock through the
granting of incentive stock options and nonstatutory stock options. Eligible
award recipients under the 2005 Plan were employees, consultants and directors
of the Company and its affiliates. Incentive stock options under the 2005 Plan
could be granted only to employees. Awards other than incentive stock options
under the 2005 Plan could be granted to employees, consultants and directors.
The shares that may be issued upon exercise of the options will be from
authorized but unissued common stock, and the maximum aggregate amount of such
common stock which could be issued upon exercise of all awards under the plan,
including incentive stock options, could not exceed 1,000,000 shares, subject to
adjustment to reflect certain corporate transactions or changes in the Company’s
capital structure.
The
Company’s board of directors and a majority of the Company’s stockholders
approved the Company’s 2006 Stock Incentive Plan (the “2006 Plan,” and together
with the 2005 Plan, the “Plans”), effective April 20, 2006. No
further awards will be made under the 2005 Plan. The purpose of the
2006 Plan is to provide a means by which eligible recipients of awards may be
given an opportunity to benefit from increases in value of the Company’s common
stock through the granting of one or more of the following awards: (1) incentive
stock options, (2) nonstatutory stock options, (3) restricted awards, (4)
performance awards and (5) stock appreciation rights. The maximum
aggregate amount of the Company’s common stock which may be issued upon exercise
of all awards under the 2006 Plan, may not exceed 2,500,000 shares, less shares
underlying options granted to employees under the 2005 Plan prior to the
adoption of the 2006 Plan. There have been no stock options exercised
under the 2006 Plan.
On April
20, 2007, the Company filed a Tender Offer Statement on Schedule TO relating to
the Company’s offer to twenty-five eligible directors, officers, employees and
consultants to exchange certain outstanding options to purchase shares of the
Company’s common stock for restricted stock awards consisting of the right to
receive restricted shares of the Company’s common stock (the “Restricted Stock
Awards”). The offer expired on May 21, 2007. Pursuant to the offer, the Company
accepted for cancellation eligible options to purchase 729,000 shares of the
Company’s common stock tendered by directors, officers, employees and
consultants eligible to participate in the offer. Subject to the
terms and conditions of the offer, on May 21, 2007 the Company granted one
Restricted Stock Award in exchange for every two shares of common stock
underlying the eligible options tendered. The Restricted Stock Awards
will vest in equal amounts on January 1, 2008 and
January 1, 2009, subject to earlier vesting or forfeiture in certain
circumstances. The Company granted the Restricted Stock Awards under the 2006
Plan.
An
incremental cost was computed in accordance with SFAS No. 123(R) upon the
conversion of options to restricted stock. The incremental cost was
measured as the excess of the fair value of the modified award over the fair
value to the original award immediately preceding conversion, measured based on
the share price and other pertinent factors at that date. The
incremental cost to be recognized over the vesting period of the modified award
is $387.
The fair
value of each option award is estimated on the date of grant using a
Black-Scholes valuation model that uses the assumptions noted in the following
table. Expected volatilities are based on the historical volatility of a
selected peer. The majority of the Company’s options were held by employees that
made up one group with similar expected exercise behavior for valuation
purposes. The expected term of options granted is estimated based on an average
of the vesting period and the contractual period. The risk-free rate for periods
within the contractual life of the option is based on the U.S. Treasury yield
curve in effect at the time of the grant.
Under the
2005 Plan, employee stock options become exercisable in equal monthly
installments over a three-year period, and all options generally expire ten
years after the date of grant. Under the 2006 Plan, employee stock options
become exercisable to the extent the options have become vested pursuant to the
vesting schedule set forth in the applicable stock option award certificate, and
all options generally expire ten years after the date of grant. The
Plans provide that all options must have an exercise price not less than the
fair market value of the Company’s common stock on the date of the grant. The
Company did not have any outstanding options at June 30, 2008.
The
Company has not declared dividends since it became a public company and does not
intend to do so in the foreseeable future, and thus did not use a dividend
yield. Expected life has been determined using the permitted simplified
method. In each case, the actual value that will be realized, if any,
will depend on the future performance of the common stock and overall stock
market conditions. There is no assurance that the value an optionee actually
realizes will be at or near the value estimated using the Black–Scholes model.
The following table provides information relating to activity in the Plans
during the first six months of 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
Remaining
|
|
|
Aggregate
|
|
|
|
|
|
|
|
Exercise
Price
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
|
Shares
|
|
|
per
Share
|
|
|
Life
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
outstanding at December 31, 2007
|
|
|
20,000
|
|
|
$
|
26.14
|
|
|
|
8.30
|
|
|
$
|
(227
|
)
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Converted
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Forfeited/expired
|
|
|
(20,000
|
)
|
|
|
26.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
outstanding at June 30, 2008
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
fully vested and exercisable at June 30, 2008
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
Date
|
|
|
Grant
Date
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Fair
Value
|
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
nonvested at December 31, 2007
|
|
|
9,319
|
|
|
$
|
13.34
|
|
|
$
|
121
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
Vested
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
Converted
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
Forfeited/expired
|
|
|
(9,319
|
)
|
|
|
13.34
|
|
|
|
(121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
nonvested at June 30, 2008
|
|
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
June 30, 2008, there was $0 of total unrecognized compensation cost related to
nonvested share-based compensation arrangements granted under the
Plans.
11.
Restricted Stock
Under all
restricted stock awards to date, shares were issued when granted and nonvested
shares are subject to forfeiture for failure to fulfill service
conditions. Restricted stock awards are valued at the grant date
market value of the underlying common stock and are being amortized to
operations over the respective vesting period. Compensation expense
for the three and six months ended June 30, 2008, related to shares of
restricted stock was $1,438 and $2,588, respectively, and for the three and six
months ended June 30, 2007 was $501 and $666,
respectively. Restricted stock activity for the six months ended June
30, 2008 was as follows:
|
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
|
|
Grant
Date
|
|
|
|
|
Shares
|
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2007
|
|
|
553,445
|
|
|
|
16.64
|
|
|
Granted
|
|
|
230,874
|
|
|
|
13.94
|
|
|
Vested
|
|
|
(245,778
|
)
|
|
|
16.56
|
|
|
Forfeited/expired
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at June 30, 2008
|
|
|
538,541
|
|
|
$
|
15.50
|
|
|
|
|
|
|
|
|
|
|
|
There was
$5,635 of total unrecognized compensation cost related to nonvested restricted
stock awards to be recognized over a weighted-average period of 1.24 years as of
June 30, 2008.
12.
Employee Benefit Plans
The Company
implemented a new 401(k) retirement plan for its eligible employees during 2007.
Under the plan, the Company matches 100% of employees’ contributions up to 5% of
eligible compensation. Employee and employer contributions vest immediately. The
Company’s contributions for the three and six months ended June 30,
2008 were $282 and $540, respectively, and for the three and six months
ended June 30, 2007 were $265 and $511, respectively.
The following
discussion and analysis should be read in conjunction with the “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”
section and audited consolidated financial statements and related notes thereto
included in our Annual Report on Form 10-K, filed with the Securities and
Exchange Commission, or SEC, on March 17, 2008 and with the unaudited
consolidated financial statements and related notes thereto presented in this
Quarterly Report on Form 10-Q.
Disclosure
Regarding Forward-Looking Statements
Our
disclosure and analysis in this Form 10-Q may include forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as
amended, or the Securities Act, Section 21E of the Securities Exchange Act
of 1934, as amended, or the Exchange Act, and the Private Securities Litigation
Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking
statements give our current expectations and projections relating to our
financial condition, results of operations, plans, objectives, future
performance and business. You can identify these statements by the fact that
they do not relate strictly to historical or current facts. These statements may
include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,”
“plan,” “believe” and other words and terms of similar meaning in connection
with any discussion of the timing or nature of future operating or financial
performance or other events. All statements other than statements of historical
facts included in this Form 10-Q that address activities, events or developments
that we expect, believe or anticipate will or may occur in the future are
forward-looking statements.
These
forward-looking statements are largely based on our expectations and beliefs
concerning future events, which reflect estimates and assumptions made by our
management. These estimates and assumptions reflect our best judgment based on
currently known market conditions and other factors relating to our operations
and business environment, all of which are difficult to predict and many of
which are beyond our control.
Although we
believe our estimates and assumptions to be reasonable, they are inherently
uncertain and involve a number of risks and uncertainties that are beyond our
control. In addition, management’s assumptions about future events may prove to
be inaccurate. Management cautions all readers that the forward-looking
statements contained in this Form 10-Q are not guarantees of future performance,
and we cannot assure any reader that those statements will be realized or the
forward-looking events and circumstances will occur. Actual results may differ
materially from those anticipated or implied in the forward-looking statements
due to the factors listed in the “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and “Risk Factors” sections of
this Quarterly Report on Form 10-Q and our most recent Annual Report on Form
10-K. All forward-looking statements speak only as of the date of this Form
10-Q. We do not intend to publicly update or revise any forward-looking
statements as a result of new information, future events or otherwise, except as
required by law. These cautionary statements qualify all forward-looking
statements attributable to us or persons acting on our behalf.
Overview
We provide
contract land drilling and workover services to oil and natural gas exploration
and production companies. As of July 31, 2008, we owned a fleet of 56 land
drilling rigs, of which 45 were marketed and 11 were held in inventory. We also
owned a fleet of 61 workover rigs, of which 56 were operating and five were in
the process of being manufactured. As of July 31, 2008, we also owned a fleet of
70 trucks used to transport our rigs.
We commenced
operations in 2001 with the purchase of one stacked 650-horsepower drilling rig
that we refurbished and deployed. We subsequently made selective acquisitions of
both operational and inventoried drilling rigs, as well as ancillary equipment.
Our management team has significant experience not only with acquiring rigs, but
also with refurbishing and deploying inventoried rigs. We have successfully
refurbished and brought into operation 25 inventoried drilling rigs during the
period from November 2003 through December 2007. In addition, we have a 41,000
square foot machine shop in Oklahoma City, which allows us to refurbish and
repair our rigs and equipment in-house. This facility, which complements our
three drilling rig refurbishment yards, significantly reduces our reliance on
outside machine shops and the attendant risk of third-party delays in our rig
refurbishment program.
We currently
operate our drilling rigs in Oklahoma, Texas, Colorado, Utah, North Dakota, and
Louisiana. Our workover rigs are currently operating in Oklahoma,
Texas, Kansas, Colorado and New Mexico. A majority of the wells we
have drilled for our customers have been drilled in search of natural gas
reserves. Natural gas is often found in deep and complex geologic formations
that generally require higher horsepower, premium rigs and experienced crews to
reach targeted depths. Our current fleet of 56 rigs includes 36 rigs ranging
from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of
inventoried rigs upon refurbishment, will be able to, reach the depths required
to explore for deep natural gas reserves. Our higher horsepower land drilling
rigs can also drill horizontal wells, which are increasing as a percentage of
total wells drilled in North America. We believe our premium rig fleet,
inventory and experienced crews position us to benefit from the natural gas
drilling activity in our core operating areas.
On January
23, 2008, we entered into a merger agreement, as amended by the First Amendment
thereto, dated as of June 1, 2008, which we refer to collectively as the merger
agreement with Allis-Chalmers Energy Inc., which we refer to as Allis-Chalmers,
providing for the acquisition of us by Allis-Chalmers. Pursuant to
the merger agreement, we and Allis-Chalmers agreed that, subject to the
satisfaction of several closing conditions (including approval by each company’s
stockholders), Bronco would merge with and into Elway Merger Sub, LLC., a
wholly-owned subsidiary of Allis-Chalmers, which we refer to as Merger Sub, and
Merger Sub would survive the merger and simultaneously change its name to
“Bronco Drilling Company LLC”. The merger agreement was approved by
our board of directors and by the respective boards of directors of
Allis-Chalmers and Merger Sub.
The merger
agreement provides that at the effective time of the merger, our stockholders
will receive merger consideration comprised of (1) $200.0 million in cash and
(2) 16,846,500 shares of Allis-Chalmers common stock. For more
information regarding the merger, please refer to the joint proxy
statement/prospectus of Allis-Chalmers and Bronco filed by Allis-Chalmers with
the SEC on July 15, 2008, and other relevant materials concerning the proposed
merger that have been or will be filed by us or Allis-Chalmers
with the SEC.
We earn our
contract drilling revenues by drilling oil and natural gas wells for our
customers. We obtain our contracts for drilling oil and natural gas wells either
through competitive bidding or through direct negotiations with customers. Our
drilling contracts generally provide for compensation on either a daywork or
footage basis. We have not historically entered into turnkey contracts and do
not intend to enter into turnkey contracts, subject to changes in market
conditions, although it is possible that we may acquire such contracts in
connection with future acquisitions. Contract terms we offer generally depend on
the complexity and risk of operations, the on-site drilling conditions, the type
of equipment used and the anticipated duration of the work to be performed.
Although we currently have 19 of our rigs operating under agreements with
durations of up to two years, our contracts generally provide for the drilling
of a single well and typically permit the customer to terminate on short
notice.
A significant
performance measurement in our industry is operating rig utilization. We compute
operating rig utilization rates by dividing revenue days by total available days
during a period. Total available days are the number of calendar days during the
period that we have owned the operating rig. Revenue days for each operating rig
are days when the rig is earning revenues under a contract, i.e. when the rig
begins moving to the drilling location until the rig is released from the
contract. On daywork contracts, during the mobilization period we typically earn
a fixed amount of revenue based on the mobilization rate stated in the contract.
We begin earning our contracted daywork rate when we begin drilling the well.
Occasionally, in periods of increased demand, we will receive a percentage of
the contracted dayrate during the mobilization period. We account for these
revenues as mobilization fees.
For the three
and six months ended June 30, 2008 and 2007 and for the years ended December 31,
2007, 2006 and 2005, our rig utilization rates, revenue days and average number
of operating rigs were as follows:
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Years
Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Average
number of operating rigs
|
|
|
45
|
|
|
|
52
|
|
|
|
45
|
|
|
|
52
|
|
|
|
51
|
|
|
|
45
|
|
|
|
17
|
|
|
Revenue
days
|
|
|
3,355
|
|
|
|
3,624
|
|
|
|
6,203
|
|
|
|
7,255
|
|
|
|
14,245
|
|
|
|
15,202
|
|
|
|
5,781
|
|
|
Utilization
Rates
|
|
|
82
|
%
|
|
|
76
|
%
|
|
|
76
|
%
|
|
|
78
|
%
|
|
|
76
|
%
|
|
|
93
|
%
|
|
|
95
|
%
|
The decrease
in the number of revenue days in the six month-period ended June 30, 2008 as
compared to the same period in 2007 is attributable to a decrease in our rig
utilization rate and average number of operating rigs due primarily to the rigs
sold and contributed to Challenger. See “—Recent Highlights”
below.
Market
Conditions in Our Industry
The
United States contract land drilling services industry is highly cyclical.
Volatility in oil and natural gas prices can produce wide swings in the levels
of overall drilling activity in the markets we serve and affect the demand for
our drilling services and the dayrates we can charge for our rigs. The
availability of financing sources, past trends in oil and natural gas prices and
the outlook for future oil and natural gas prices strongly influence the number
of wells oil and natural gas exploration and production companies decide to
drill.
The
following table depicts the prices for near month delivery contracts for crude
oil and natural gas as traded on the NYMEX, as well as the most recent Baker
Hughes domestic land rig count, on the dates indicated:
|
|
|
At
June 30,
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil (Bbl)
|
|
$
|
140.00
|
|
|
$
|
95.98
|
|
|
$
|
61.05
|
|
|
$
|
61.04
|
|
|
Natural
gas (Mmbtu)
|
|
$
|
13.35
|
|
|
$
|
7.48
|
|
|
$
|
6.30
|
|
|
$
|
11.23
|
|
|
U.S.
Land Rig Count
|
|
|
1,849
|
|
|
|
1,719
|
|
|
|
1,626
|
|
|
|
1,391
|
|
We
believe capital spent on incremental natural gas production will be driven by an
increase in hydrocarbon demand as well as changes in supply of natural gas. The
Energy Information Administration estimated that U.S. consumption of natural gas
exceeded domestic production by 16% in 2005 and forecasts that U.S. consumption
of natural gas will exceed U.S. domestic production by 24% in 2010. In addition,
a study published by the National Petroleum Council in September 2003 concluded
from drilling and production data over the preceding ten years that average
“initial production rates from new wells have been sustained through the use of
advanced technology; however, production declines from these initial rates have
increased significantly; and recoverable volumes from new wells drilled in
mature producing basins have declined over time.” The report went on to state
that “without the benefit of new drilling, indigenous supplies have reached a
point at which U.S. production declines by 25% to 30% each year” and predicted
that in ten years eighty percent of gas production “will be from wells yet to be
drilled.” We believe all of these factors tend to support a higher natural gas
price environment, which should create strong incentives for oil and natural gas
exploration and production companies to increase drilling activity in the U.S.
Consequently, these factors may result in higher rig dayrates and rig
utilization.
Critical
Accounting Policies and Estimates
Our
discussion and analysis of our financial condition and results of operations is
based upon our consolidated financial statements, which have been prepared in
accordance with accounting policies that are described in the notes to our
consolidated financial statements. The preparation of the consolidated financial
statements requires management to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. We continually evaluate our
judgments and estimates in determining our financial condition and operating
results. Estimates are based upon information available as of the date of the
financial statements and, accordingly, actual results could differ from these
estimates, sometimes materially. Critical accounting policies and estimates are
defined as those that are both most important to the portrayal of our financial
condition and operating results and require management’s most subjective
judgments. The most critical accounting policies and estimates are described
below.
Revenue and Cost
Recognition
—We earn our revenues by drilling oil and natural gas wells
for our customers under daywork or footage contracts, which usually provide for
the drilling of a single well. We recognize revenues on daywork contracts for
the days completed based on the dayrate each contract specifies. Mobilization
revenues and costs are deferred and recognized over the drilling days of the
related drilling contract. Individual contracts are usually completed in less
than 120 days. We follow the percentage-of-completion method of accounting for
footage contract drilling arrangements. Under this method, drilling revenues and
costs related to a well in progress are recognized proportionately over the time
it takes to drill the well. Percentage of completion is determined based upon
the amount of expenses incurred through the measurement date as compared to
total estimated expenses to be incurred drilling the well. Mobilization costs
are not included in costs incurred for percentage-of-completion calculations.
Mobilization costs on footage contracts and daywork contracts are deferred and
recognized over the days of actual drilling. Under the percentage-of-completion
method, management estimates are relied upon in the determination of the total
estimated expenses to be incurred drilling the well. When estimates of revenues
and expenses indicate a loss on a contract, the total estimated loss is
accrued.
Our
management has determined that it is appropriate to use the
percentage-of-completion method to recognize revenue on our footage contracts,
which is the predominant practice in the industry. Although our footage
contracts do not have express terms that provide us with rights to receive
payment for the work that we perform prior to drilling wells to the agreed upon
depth, we use this method because, as provided in applicable accounting
literature, we believe we achieve a continuous sale for our work-in-progress and
we believe, under applicable state law, we ultimately could recover the fair
value of our work-in-progress even in the event we were unable to drill to the
agreed upon depth in breach of the applicable contract. However, ultimate
recovery of that value, in the event we were unable to drill to the agreed upon
depth in breach of the contract, would be subject to negotiations with the
customer and the possibility of litigation.
We are
entitled to receive payment under footage contracts when we deliver to our
customer a well completed to the depth specified in the contract, unless the
customer authorizes us to drill to a shallower depth. Since inception, we have
completed all our footage contracts. Although our initial cost estimates for
footage contracts do not include cost estimates for risks such as stuck drill
pipe or loss of circulation, we believe that our experienced management team,
our knowledge of geologic formations in our areas of operations, the condition
of our drilling equipment and our experienced crews enable us to make reasonably
dependable cost estimates and complete contracts according to our drilling plan.
While we do bear the risk of loss for cost overruns and other events that are
not specifically provided for in our initial cost estimates, our pricing of
footage contracts takes such risks into consideration. When we encounter, during
the course of our drilling operations, conditions unforeseen in the preparation
of our original cost estimate, we immediately adjust our cost estimate for the
additional costs to complete the contracts. If we anticipate a loss on a
contract in progress at the end of a reporting period due to a change in our
cost estimate, we immediately accrue the entire amount of the estimated loss,
including all costs that are included in our revised estimated cost to complete
that contract, in our consolidated statement of operations for that reporting
period. We are more likely to encounter losses on footage contracts
in years in which revenue rates are lower for all types of
contracts.
Revenues
and costs during a reporting period could be affected by contracts in progress
at the end of a reporting period that have not been completed before our
financial statements for that period are released. We had no footage contracts
in progress at June 30, 2008 and December 31, 2007. At June 30, 2008
and December 31, 2007, our contract drilling in progress totaled $1.4 million
and $2.1 million, respectively, all of which relates to the revenue recognized
but not yet billed or costs deferred on daywork contracts in
progress.
We accrue
estimated contract costs on footage contracts for each day of work completed
based on our estimate of the total costs to complete the contract divided by our
estimate of the number of days to complete the contract. Contract costs include
labor, materials, supplies, repairs and maintenance and operating overhead
allocations. In addition, the occurrence of uninsured or under-insured losses or
operating cost overruns on our footage contracts could have a material adverse
effect on our financial position and results of operations. Therefore, our
actual results could differ significantly if our cost estimates are later
revised from our original estimates for contracts in progress at the end of a
reporting period that were not completed prior to the release of our financial
statements.
Accounts
Receivable
—We evaluate the creditworthiness of our customers based on
their financial information, if available, information obtained from major
industry suppliers, current prices of oil and natural gas and any past
experience we have with the customer. Consequently, an adverse change in those
factors could affect our estimate of our allowance for doubtful accounts. In
some instances, we require new customers to establish escrow accounts or make
prepayments. We typically invoice our customers at 30-day intervals during the
performance of daywork contracts and upon completion of the daywork contract.
Footage contracts are invoiced upon completion of the contract. Our typical
contract provides for payment of invoices in 10 to 30 days. We generally do not
extend payment terms beyond 30 days. We are currently involved in legal actions
to collect various overdue accounts receivable. Our allowance for
doubtful accounts was $1.2 million and $1.8 million at June 30, 2008 and
December 31, 2007, respectively. Any allowance established is subject to
judgment and estimates made by management. We determine our allowance by
considering a number of factors, including the length of time trade accounts
receivable are past due, our previous loss history, our customer’s current
ability to pay its obligation to us and the condition of the general economy and
the industry as a whole. We write off specific accounts receivable when they
become uncollectible and payments subsequently received on such receivables
reduce the allowance for doubtful accounts.
If a
customer defaults on its payment obligation to us under a footage contract, we
would need to rely on applicable law to enforce our lien rights, because our
footage contracts do not expressly grant to us a security interest in the work
we have completed under the contract and we have no ownership rights in the
work-in-progress or completed drilling work, except any rights arising under the
applicable lien statute on foreclosure. If we were unable to drill to the agreed
on depth in breach of the contract, we might also need to rely on equitable
remedies outside of the contract, including quantum meruit, available in
applicable courts to recover the fair value of our work-in-progress under a
footage contract.
Asset Impairment
and Depreciation
—We review long-lived assets to be held and used for
impairment whenever events or changes in circumstances indicate that the
carrying amount of the assets may not be recoverable. We also
evaluate the carrying value of goodwill during the fourth quarter of each year
and between annual evaluations if events occur or circumstances change that
would more likely than not reduce the fair value below its carrying
amount. Factors that we consider important and could trigger an
impairment review would be our customers’ financial condition and any
significant negative industry or economic trends. More specifically, among other
things, we consider our contract revenue rates, our rig utilization rates, cash
flows from our drilling rigs, current oil and natural gas prices, industry
analysts’ outlook for the industry and their view of our customers’ access to
debt or equity and the trends in the price of used drilling equipment observed
by our management. If a review of our drilling rigs, intangible assets and
goodwill indicate that our carrying value exceeds the estimated undiscounted
future cash flows, we are required under applicable accounting standards to
write down the drilling equipment, intangible assets and goodwill to its fair
market value. A one percent write-down in the cost of our drilling equipment,
intangible assets, and goodwill, at June 30, 2008, would have resulted in a
corresponding decrease in our net income of approximately $2.7
million.
Our
determination of the estimated useful lives of our depreciable assets, directly
affects our determination of depreciation expense and deferred taxes. A decrease
in the useful life of our drilling equipment would increase depreciation expense
and reduce deferred taxes. We provide for depreciation of our drilling rigs,
transportation and other equipment on a straight-line method over useful lives
that we have estimated and that range from three to fifteen years after the rig
was placed into service. We record the same depreciation expense whether an
operating rig is idle or working. Depreciation is not recorded on an inventoried
rig until placed in service. Our estimates of the useful lives of our drilling,
transportation and other equipment are based on our experience in the drilling
industry with similar equipment.
We
capitalize interest cost as a component of drilling and workover rigs
refurbished for our own use. During the three and six months ended June 30,
2008, we capitalized approximately $77,000 and $459,000, respectively, and
during the three and six months ended June 30, 2007 we capitalized approximately
$449,000 and $903,000, respectively.
Stock Based
Compensation---
We have adopted SFAS No. 123(R), “
Share-Based Payment
” upon
granting our first stock options on August 16, 2005. SFAS No. 123(R)
requires a public entity to measure the costs of employee services received in
exchange for an award of equity or liability instruments based on the grant-date
fair value of the award. That cost will be recognized over the periods during
which an employee is required to provide service in exchange for the
award. Stock compensation expense was $1.4 million and $2.6 million
for the three and six months ended June 30, 2008, respectively, and $981,000 and
$1.7 million for the three and six months ended June 30, 2007,
respectively.
The fair
value of each option award is estimated on the date of grant using a Black
Scholes valuation model that uses various assumptions related to volatility,
expected life, forfeitures, exercise patterns, risk free rates and expected
dividends. Expected volatilities are based on the historical volatility of a
selected peer and other factors. The majority of our options were granted to
employees that made up one group with similar expected exercise behavior for
valuation purposes. The expected term of options granted was estimated based on
an average of the vesting period and the contractual period. The risk-free rate
for periods within the contractual life of the option was based on the U.S.
Treasury yield curve in effect at the time of the grant.
We have
not declared dividends since we became a public company and do not intend to do
so in the foreseeable future, and thus did not use a dividend yield. Expected
life has been determined using the permitted short cut method.
Under our
2005 Stock Incentive Plan, employee stock options become exercisable in equal
monthly installments over a three-year period, and all options generally expire
ten years after the date of grant. The 2005 Plan provides that all options must
have an exercise price not less than the fair market value of our common stock
on the date of the grant.
On April
20, 2007, we filed a Tender Offer Statement on Schedule TO relating to our offer
to twenty-five eligible directors, officers, employees and consultants to
exchange certain outstanding options to purchase shares of our common stock for
restricted stock awards consisting of the right to receive restricted shares of
our common stock, which we refer to as the “restricted stock awards.” The offer
expired on May 21, 2007. Pursuant to the offer, we accepted for cancellation
eligible options to purchase 729,000 shares of our common stock tendered by
directors, officers, employees and consultants eligible to participate in the
offer. Subject to the terms and conditions of the offer, on May 21,
2007 we granted one restricted stock award in exchange for every two shares of
common stock underlying the eligible options tendered. Half of the
restricted stock awards vested on January 1, 2008 and the balance vest
on January 1, 2009, subject to earlier vesting or forfeiture in
certain circumstances. We granted the restricted stock awards under our 2006
Stock Incentive Plan, effective as of April 20, 2006.
An
incremental cost was computed in accordance with SFAS No. 123(R) upon the
conversion of options to restricted stock. The incremental cost was
measured as the excess of the fair value of the modified award over the fair
value to the original award immediately preceding conversion, measured based on
the share price and other pertinent factors at that date. The
incremental cost to be recognized over the vesting period of the modified award
is $387,000.
Deferred Income
Taxes
—We provide deferred income taxes for the basis difference in our
property and equipment, stock compensation expense and other items between
financial reporting and tax reporting purposes. For property and equipment,
basis differences arise from differences in depreciation periods and methods and
the value of assets acquired in a business acquisition where we acquire the
stock in an entity rather than just its assets. For financial reporting
purposes, we depreciate the various components of our drilling rigs and
refurbishments over fifteen years, while federal income tax rules require that
we depreciate drilling rigs and refurbishments over five years. Therefore, in
the first five years of our ownership of a drilling rig, our tax depreciation
exceeds our financial reporting depreciation, resulting in our providing
deferred taxes on this depreciation difference. After five years, financial
reporting depreciation exceeds tax depreciation, and the deferred tax liability
begins to reverse.
Other Accounting
Estimates
—Our other accrued expenses as of June 30, 2008 and
December 31, 2007 included accruals of approximately $2.7 million and $3.0
million, respectively, for costs under our workers’ compensation insurance. We
have a deductible of $1.0 million per covered accident under our workers’
compensation insurance. We maintain letters of credit in the aggregate amount of
$7.3 million for the benefit of various insurance companies as collateral for
retrospective premiums and retained losses which may become payable under the
terms of the underlying insurance contracts. The letters of credit
are typically renewed annually. No amounts have been drawn under the
letters of credit. At June 30, 2008 and December 31, 2007, we had deposits
of $2.8 million and $2.7 million, respectively, with an insurance company
collateralizing a letter of credit. We accrue for these costs as claims are
incurred based on cost estimates established for each claim by the insurance
companies providing the administrative services for processing the claims,
including an estimate for incurred but not reported claims, estimates for claims
paid directly by us, our estimate of the administrative costs associated with
these claims and our historical experience with these types of
claims. We also have a self-insurance program for major medical,
hospitalization and dental coverage for employees and their
dependents. We recognize both reported and incurred but not reported
costs related to the self-insurance portion of our health
insurance. Since the accrual is based on estimates of expenses for
claims, the ultimate amount paid may differ from accrued amounts.
Recent Accounting
Pronouncements
—
In
September 2006, the FASB issued SFAS No. 157, or SFAS 157, “
Fair Value
Measurements
.” This Statement defines fair value, establishes
a framework for measuring fair value in generally accepted accounting
principles, or GAAP, and expands disclosures about fair value measurements. This
Statement applies under other accounting pronouncements that require or permit
fair value measurements, the FASB having previously concluded in those
accounting pronouncements that fair value is the relevant measurement attribute.
Accordingly, this Statement does not require any new fair value measurements.
This Statement is effective for fiscal years beginning after November 15, 2007;
however, on February 12, 2008, the FASB issued FSP FAS No. 157-2,
Effective Dates of FASB Statement
No. 157,
which delays the effective date of SFAS No. 157 to fiscal years
beginning after November 15, 2008 for all nonfinancial assets and nonfinancial
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis. The adoption of the
provisions of SFAS 157 did not have a material impact on our financial
statements.
In February
2007, the FASB issued SFAS No. 159, or SFAS 159, “
The Fair Value Option for Financial
Assets and Financial Liabilities−Including an amendment of FASB Statement No.
115
.” SFAS No. 159 permits entities to choose to measure many financial
instruments and certain other items at fair value. Unrealized gains and losses
on items for which the fair value option has been elected will be recognized in
earnings at each subsequent reporting date. SFAS No. 159 is effective for fiscal
years beginning January 1, 2008. The adoption of the provisions of SFAS 159 did
not have a material impact on our financial statements.
In December
2007, the FASB issued SFAS No. 141 (revised 2007) “
Business Combinations
”, or
SFAS 141R. SFAS 141R establishes principles and requirements for how the
acquirer of a business recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree. SFAS 141R also provides guidance for recognizing and
measuring the goodwill acquired in the business combination and determines what
information to disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination. SFAS No. 141R
applies prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or
after December 15, 2008. We are currently evaluating the potential
impact, if any, of the adoption of SFAS 141R on our consolidated financial
statements.
In December
2007, the FASB issued SFAS No. 160, or SFAS 160, “
Noncontrolling Interests in
Consolidated Financial Statements — an amendment of ARB No. 51.
” SFAS 160
establishes accounting and reporting standards for the noncontrolling interest
in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a
noncontrolling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements. SFAS 160 requires retroactive adoption of the presentation
and disclosure requirements for existing minority interests. All other
requirements of SFAS 160 shall be applied prospectively. SFAS 160 is effective
for fiscal years, and interim periods within those fiscal years, beginning on or
after December 15, 2008. We are currently evaluating the potential
impact, if any, of the adoption of SFAS 141R on our consolidated financial
statements.
In March
2008, the FASB issued SFAS No. 161, or SFAS 161, “Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No.
133.” SFAS 161 requires enhanced disclosures for derivative
instruments and hedging activities that include how and why an entity uses
derivatives, how instruments and the related hedged items are accounted for
under FAS 133 and related interpretations, and how derivative instruments and
related hedged items affect the entity’s financial position, results of
operations and cash flows. SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008. We do not expect the adoption of SFAS 161 to have a material impact on
our financial position or results of operations.
Recent
Highlights
The
following are highlights that impacted our liquidity or results of operations
for the six months ended June 30, 2008:
On January 4,
2008, Bronco MENA Investments LLC, one of our wholly-owned subsidiaries, closed
a transaction with Challenger Limited, or Challenger, a company organized under
the laws of the Isle of Man, and certain of its affiliates to acquire a 25%
equity interest in Challenger in exchange for six drilling rigs and $5.1 million
in cash. Challenger is an international provider of contract land
drilling and workover services to oil and natural gas companies with its
principal operations in Libya. We also sold to Challenger four
drilling rigs and ancillary equipment for $13.0 million, payable in
installments. We recorded a net gain of $3.2 million relating to the
exchange and sale of rigs and equipment to Challenger. The
transactions were completed on January 4, 2008. Prior to these
transactions, Challenger owned a fleet of 23 rigs. We recorded equity
in (loss) income of investment of $(69,000) and $1.8 million for the three
and six months ended June 30, 2008 related to our equity investment in
Challenger.
Eight of the
rigs contributed or sold to Challenger are in Libya with three of the rigs
currently operating. Challenger is still in the process of securing a
debt facility to meet short-term capital needs including those related to
start-up of our rigs and to mitigate downtime that has affected Challenger’s
operations due to past underinvestment in adequate rig supplies and spare
equipment. We believe that an entry into a debt facility by
Challenger is an important factor in determining the long-term success of
Challenger and anticipate that Challenger will continue to have unpredictable
financial results in the near future.
On January
23, 2008, we entered into a merger agreement, as amended by the First Amendment
thereto, dated as of June 1, 2008, which we refer to collectively as the merger
agreement, with Allis-Chalmers, providing for the acquisition of us by
Allis-Chalmers. Pursuant to the merger agreement, we and
Allis-Chalmers agreed that, subject to the satisfaction of several closing
conditions (including approval by each company’s stockholders), Bronco would
merge with and into Elway Merger Sub, LLC, a wholly-owned subsidiary of
Allis-Chalmers, which we refer to as Merger Sub, and Merger Sub would survive
the merger and simultaneously change its name to “Bronco Drilling Company
LLC”. The merger agreement was approved by our board of directors and
by the respective boards of directors of Allis-Chalmers and Merger
Sub.
The merger
agreement provides that at the effective time of the merger, our stockholders
will receive merger consideration comprised of (1) $200.0 million in cash and
(2) 16,846,500 shares of Allis-Chalmers common stock. For more
information regarding the merger, please refer to the joint proxy
statement/prospectus of Allis-Chalmers and Bronco filed by Allis-Chalmers with
the SEC on July 15, 2008 and other relevant materials that have been or will be
filed by us or Allis-Chalmers with the SEC.
During the
second quarter of 2008, we increased our number of term contracts and now have
approximately 57% of our estimated revenue days for the last two quarters of
2008 and 32% of our estimated revenue days for 2009 covered by term
contracts. Total contracted revenue days do not include days
attributable to our multi-well contracts, as we do not attempt to quantify the
duration of those contracts. Inclusion of such contracts would
increase the percentages stated above.
During the
second quarter of 2008, we bid and won a tender in Mexico with
Pemex. This tender will require three rigs operating in the
Chicontepec basin near Poza Rica, Mexico. Two of the rigs have begun
to mobilize to Mexico with the third to follow in the coming
weeks. We anticipate all three will operating in Mexico by the end of
August. The duration of the contract with Pemex for these rigs is
through the end of 2009.
We currently
have six rigs contractually committed to the Bakken Shale. All of
these rigs will require winterization and other modifications. Two of
the rigs will require major modifications and refurbishment which will include a
conversion from mechanical to electric power. We expect these rigs to
be deployed to the Bakken during the third and fourth quarters of
2008.
Results
of Operations
Three
Months Ended June 30, 2008 Compared to Three Months Ended June 30,
2007
Contract Drilling
Revenue.
For the three months ended June 30, 2008, we reported
contract drilling revenues of $60.5 million, a 13% decrease from revenues of
$69.3 million for the same period in 2007. The decrease is primarily due to a
decrease in dayrates, revenue days and average number of rigs working for the
three months ended June 30, 2008 as compared to the same period in 2007. Average
dayrates for our drilling services decreased $1,464, or 8%, to $16,332 for the
three months ended June 30, 2008 from $17,796 in the same period in 2007.
Revenue days decreased 7% to 3,355 days for the three months ended June 30, 2008
from 3,624 days during the same period in 2007. Our average number of operating
rigs decreased to 45 from 52, or 14%, for the three months ended June 30, 2008
as compared to the same period in 2007. The decrease in the number of revenue
days and size of our operating rig fleet for the three months ended June 30,
2008, as compared to the same period in 2007, is primarily due to the sale and
contribution of rigs to Challenger.
Well Service
Revenue.
For the three months ended June 30, 2008, we
reported well service revenues of approximately $9.3 million, a 72% increase
from revenues of $5.4 million for the same period in 2007. The
increase is primarily due to an increase in revenue hours and average number of
operating workover rigs for the three months ended June 30, 2008 as compared to
the same period in 2007. Revenue hours increased 77% to 25,533 hours
for the three months ended June 30, 2008 from 14,427 hours during the same
period in 2007. Our average number of operating workover rigs
increased to 53 from 29, or 84%, for the three months ended June 30, 2008 as
compared to the same period in 2007. The increase in revenue hours
and size of our operating workover rig fleet is due to additional workover rigs
purchased.
Equity in Loss of
Investment.
Equity in loss of investment was $69,000 for the
three months ended June 30, 2008 related to our investment in
Challenger. The loss was due to Challenger’s inability to meet
short-term capital needs including those related to start-up of the Bronco rigs
and to mitigate downtime that has plagued the company's operations due to past
underinvestment in adequate rig supplies and spare
equipment. Challenger is in the process of securing a debt facility
which is a pivotal component in determining the long-term success of
Challenger.
Contract Drilling
Expense.
Direct rig cost decreased $3.8 million to $36.7 million for
the three months ended June 30, 2008 from $40.5 million for the same period in
2007. This 9% decrease is primarily due to the decrease in revenue days and the
decrease in average number of operating rigs in our fleet for the three months
ended June 30, 2008 as compared to the same period in 2007. As a
percentage of contract drilling revenue, drilling expense increased to 61% for
the three-month period ended June 30, 2008 from 58% for the same period in 2007
due primarily to a decrease in dayrates for the three months ended June 30, 2008
compared to the same period in 2007.
Well Service
Expense.
Well service expense increased $2.8 million to $6.1 million for
the three months ended June 30, 2008 from $3.3 million for the same period in
2007. This 85% increase is primarily due to the increase in revenue
hours and the average number of operating workover rigs in our fleet for the
three months ended June 30, 2008 as compared to the same period in
2007.
Depreciation
Expense.
Depreciation expense increased $1.6 million to $12.5
million for the three months ended June 30, 2008 from $10.9 million for the same
period in 2007. The increase is primarily due to the 4% increase in fixed
assets.
General and
Administrative Expense
. General and administrative expense increased
$15,000 to $5.4 million for the three months ended June 30, 2008 from $5.4
million for the same period in 2007. The increase is the result of an increase
in payroll costs of $535,000, an increase in stock compensation expense of
$457,000, an increase in professional fees expense of $212,000, and an increase
in rent expense of $72,000. The increase in payroll costs is primarily due
to our increased administrative employee count and related wage
increases. The increase in stock compensation expense is attributed
to grants of restricted stock during 2007 and the six months ended June 30,
2008. The increase in professional fees is due to services provided
related to the Challenger transaction and merger agreement. These
increases were partially offset by a decrease in accounts receivable write offs
of $1.2 million.
Interest
Expense
. Interest expense increased $367,000 to $1.2 million for the
three months ended June 30, 2008 from $795,000 for the same period in 2007. The
increase is due to a decrease in the capitalization of interest related to our
rig refurbishment program and a higher outstanding balance on our revolving
credit facility, partially offset by a decrease in the average interest rate on
our revolving credit facility We capitalized $77,000 of interest for
the three months ended June 30, 2008 as compared to $449,000 for the same period
in 2007.
Income Tax
Expense
. We recorded a tax expense of $2.7 million for the three
months ended June 30, 2008, all of which was deferred tax expense. This compares
to a deferred tax expense of $5.4 million for the three months ended June 30,
2007. This decrease is due to the decrease in pre-tax income.
Six
months Ended June 30, 2008 Compared to Six months Ended June 30,
2007
Contract Drilling
Revenue.
For the six months ended June 30, 2008, we reported
contract drilling revenues of $114.6 million, a 20% decrease from revenues of
$143.9 million for the same period in 2007. The decrease is primarily due to a
decrease in dayrates, revenue days and average number of rigs working for the
six months ended June 30, 2008 as compared to the same period in 2007. Average
dayrates for our drilling services decreased $1,676, or 9%, to $16,591 for the
six months ended June 30, 2008 from $18,267 in the same period in 2007. Revenue
days decreased 15% to 6,203 days for the six months ended June 30, 2008 from
7,255 days during the same period in 2007. Our average number of operating rigs
decreased to 45 from 52, or 13%, for the six months ended June 30, 2008 as
compared to the same period in 2007. The decrease in the number of revenue days
and size of our operating rig fleet for the six months ended June 30, 2008 as
compared to the same period in 2007 is primarily due to the sale and
contribution of rigs to Challenger.
Well Service
Revenue.
For the six months ended June 30, 2008, we
reported well service revenues of approximately $17.5 million, a 78% increase
from revenues of $9.8 million for the same period in 2007. The
increase is primarily due to an increase in revenue hours and average number of
operating workover rigs for the six months ended June 30, 2008 as compared to
the same period in 2007. Revenue hours increased 87% to 49,398 hours
for the six months ended June 30, 2008 from 26,474 hours during the same period
in 2007. Our average number of operating workover rigs increased to
51 from 27, or 89%, for the six months ended June 30, 2008 as compared to the
same period in 2007. The increase in revenue hours and size of our
operating workover rig fleet is due to additional workover rigs
purchased.
Equity in Income of
Investment.
Equity in income of investment was $1.8 million
for the six months ended June 30, 2008 related to our investment in
Challenger. Challenger is still in the process of securing a debt
facility to meet short-term capital needs including those related to start-up of
our rigs and to mitigate downtime that has affected Challenger’s operations due
to past underinvestment in adequate rig supplies and spare
equipment. The debt facility is a pivotal component in determining
the long-term success of Challenger.
Contract Drilling
Expense.
Direct rig cost decreased $11.4 million to $69.9 million
for the six months ended June 30, 2008 from $81.3 million for the same period in
2007. This 14% decrease is primarily due to the decrease in revenue days and the
decrease in average number of operating rigs in our fleet for the six months
ended June 30, 2008 as compared to the same period in 2007. As a
percentage of contract drilling revenue, drilling expense increased to 61% for
the three-month period ended June 30, 2008 from 57% for the same period in 2007
due primarily to a decrease in dayrates for the six months ended June 30, 2008
as compared to the same period in 2007.
Well Service
Expense.
Well service expense increased $5.1 million to $11.0 million for
the six months ended June 30, 2008 from $5.9 million for the same period in
2007. This 86% increase is primarily due to the increase in revenue
hours and the average number of operating workover rigs in our fleet for the six
months ended June 30, 2008 as compared to the same period in 2007.
Depreciation
Expense.
Depreciation expense increased $2.3 million to $24.4
million for the six months ended June 30, 2008 from $22.1 million for the same
period in 2007. The increase is primarily due to the 4% increase in fixed
assets.
General and
Administrative Expense
. General and administrative expense increased
$1.1 million to $11.2 million for the six months ended June 30, 2008 from $10.1
million for the same period in 2007. The increase is the result of an increase
in payroll costs of $1.1 million, an increase in stock compensation expense
of $915,000, and an increase in professional fees expense of
$304,000 The increase in payroll costs is primarily due to our
increased administrative employee count and related wage
increases. The increase in stock compensation expense is attributed
to grants of restricted stock during 2007 and the six months ended June 30,
2008. The increase in professional fees is due to services provided
related to the Challenger transaction and merger agreement. These
increases were partially offset by a decrease in accounts receivable write offs
of $1.2 million and a decrease in yard expense of $332,000.
Interest
Expense
. Interest expense increased $324,000 to $2.4 million for the
six months ended June 30, 2008 from $2.1 million for the same period in 2007.
The increase is due to a decrease in the capitalization of interest related to
our rig refurbishment program and a higher outstanding balance on our revolving
credit facility partially offset by a decrease in the average interest rate on
our revolving credit facility. We capitalized $459,000 of interest for the
six months ended June 30, 2008 as compared to $903,000 for the same period in
2007.
Income Tax
Expense.
We recorded a tax expense of $7.2 million for the six
months ended June 30, 2008 all of which was deferred tax expense. This compares
to a deferred tax expense of $12.5 million for the six months ended June 30,
2007. This decrease is due to the decrease in pre-tax income.
Liquidity
and Capital Resources
Operating
Activities
.
Net cash provided by
operating activities was $38.3 million for the six months ended June 30, 2008 as
compared to $32.9 million in 2007. The increase of $5.4 million from 2007
to 2008 was primarily due to an increase in cash receipts from customers,
partially offset by higher cash payments to suppliers.
Investing
Activities
.
We use a significant
portion of our cash flows from operations and financing activities for
acquisitions and the refurbishment of our rigs. Cash used in investing
activities was $43.0 million for the six months ended June 30, 2008 as compared
to $31.7 million for the same period in 2007. For the six
months ended June 30, 2008, we used $41.0 million to purchase fixed assets and
$5.1 million to purchase an equity interest in Challenger. These
amounts were partially offset by $3.0 million of proceeds received from the sale
of assets. For the six months ended June 30, 2007, we used
$ 31.8 million to purchase fixed assets and $2.3 million to purchase Eagle
Well Service, Inc, or Well Services. These amounts were partially
offset by $2.4 million of proceeds received from the sale of
assets.
Financing
Activities
.
Our cash flows provided
by financing activities were $8.8 million for the six months ended June 30, 2008
as compared to $7.0 million used in financing activities for the same period in
2007. For the six months ended June 30, 2008, our net cash provided by financing
activities related to borrowings of $10.0 million under our credit facility with
Fortis Capital Corp. and borrowings of $846,000 from various lenders, partially
offset by principal payments of $2.0 million to various lenders. Our
net cash used in 2007 for financing activities related to principal
payments of $19.0 million under our credit agreement with Fortis Capital Corp.,
partially offset by borrowings of $12.0 million under our credit facility with
Fortis Capital Corp.
Sources of
Liquidity
.
Our primary sources of
liquidity are cash from operations and debt and equity financing.
Debt
Financing
. On January 13, 2006, we entered into a
$150.0 million revolving credit facility with Fortis Capital Corp., as
administrative agent, lead arranger and sole bookrunner, and a syndicate of
lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business
Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital,
Comerica Bank and Caterpillar Financial Services Corporation. The revolving
credit facility matures on January 13, 2009. The Company intends to
refinance the revolving credit facility during 2008. The initial
aggregate revolving commitment of $150.0 million is automatically and
permanently reduced by $10.0 million at the end of each fiscal quarter starting
September 30, 2006. The aggregate revolving commitment was $80.0
million as of June 30, 2008. We had $2.6 million available under the
credit facility at June 30, 2008. Loans under the revolving credit facility bear
interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our
option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending
on the ratio of our outstanding senior debt to “Adjusted EBITDA,” as defined in
the credit agreement.
The
revolving credit facility also provides for a quarterly commitment fee of
0.5% per annum of the unused portion of the revolving credit facility, and
fees for each letter of credit issued under the facility. Commitment fees
expense for the three and six months ended June 30, 2008 were $56,000 and
$115,000, respectively, and for the three and six months ended June 30, 2007
were $68,000 and $149,000, respectively. Our subsidiaries have
guaranteed the loans and other obligations under the revolving credit facility.
The obligations under the revolving credit facility and the related guarantees
are secured by a first priority security interest in substantially all of our
assets, as well as the shares of capital stock of our direct and indirect
subsidiaries.
The
revolving credit facility contains customary covenants for facilities of this
type, including among other things, covenants that restrict our ability to make
capital expenditures, incur indebtedness, incur liens, dispose of property,
repay debt, pay dividends, repurchase shares and make certain acquisitions. The
financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00
and a maximum total leverage ratio of 2.00 to 1.00. We were in compliance with
all covenants at June 30, 2008. The revolving credit facility
provides for mandatory prepayments under certain circumstances. The revolving
credit facility contains various events of default, including failure to pay
principal and interest when due, breach of covenants, materially incorrect
representations, default under certain other agreements, bankruptcy or
insolvency, the occurrence of specified ERISA events, entry of enforceable
judgments against us in excess of $3.0 million not stayed, and the occurrence of
a change of control. If an event of default occurs, all commitments under the
revolving credit facility may be terminated and all of our obligations under the
revolving credit facility could be accelerated by the lenders, causing all loans
outstanding (including accrued interest and fees payable thereunder) to be
declared immediately due and payable.
We are
party to term installment loans for an aggregate principal amount of
approximately $4.5 million. These term loans are payable in 96 monthly
installments, mature in 2013 and 2014 and have a weighted average annual
interest rate of 6.92%. The proceeds from these term loans were used to purchase
cranes.
We are
party to a term loan agreement with Ameritas Life Insurance Corp. for an
aggregate principal amount of approximately $1.6 million related to the
acquisition of a building. This term loan is payable in 166 monthly
installments, matures in 2021 and has an interest rate of 6%.
Issuances
of Equity.
In
connection with our acquisition of Well Services in January 2007, we issued
1,070,390 shares of our common stock.
Capital
Expenditures.
We believe
that cash flow from our operations and borrowings under our revolving credit
facility will be sufficient to fund our operations for at least the next 12
months. During 2008, the Company intends to refinance its revolving
credit facility that matures on January 13, 2009. However, additional
capital may be required for future acquisitions. While we would expect to fund
such acquisitions with additional borrowings and the issuance of debt and equity
securities, we cannot assure you that such funding will be available or, if
available, that it will be on terms acceptable to us.
We are
subject to market risk exposure related to changes in interest rates on our
outstanding floating rate debt. Borrowings under our revolving credit facility
bear interest at a floating rate equal to LIBOR plus a margin that can range
from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range
from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to
Adjusted EBITDA, as defined in our credit agreement with Fortis Capital Corp. An
increase or decrease of 1% in the interest rate would have a corresponding
decrease or increase in our net income (loss) of approximately $436,000
annually, based on the $70.0 million outstanding in the aggregate under our
credit facility as of June 30, 2008.
Evaluation of Disclosure Control and
Procedures
.
As of the end
of the period covered by this Quarterly Report on Form 10−Q, our management,
under the supervision and with the participation of our Chief Executive Officer
and Chief Financial Officer, evaluated the effectiveness of the design and
operation of our disclosure controls and procedures (as defined in Rules
13a−15(e) or 15d−15(e) under the Securities Exchange Act of 1934, as amended).
Based on that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that as of June 30, 2008 our disclosure controls and
procedures are effective.
Disclosure
controls and procedures are controls and procedures designed to ensure that
information required to be disclosed in our reports filed or submitted under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and forms; and include
controls and procedures designed to ensure that information is accumulated and
communicated to our management, and made known to our Chief Executive Officer
and Chief Financial Officer, particularly during the period when this Quarterly
Report on Form 10−Q was prepared, as appropriate to allow timely decision
regarding the required disclosure.
Changes in Internal Control over
Financial Reporting
.
There were no
changes in our internal control over financial reporting that occurred during
the second quarter of 2008 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial
reporting.
Following
the announcement of the merger agreement on January 24, 2008, three
purported class action complaints were filed challenging the proposed merger
between Allis-Chalmers, Bronco and Merger Sub. Two complaints were filed in
Oklahoma in the District Court of Oklahoma County, the first on January 29,
2008, which we refer to as the Boothe action, and the second on
February 28, 2008, which we refer to as the Goff action. The defendants
named in both actions are Bronco, the Bronco board of directors and
Allis-Chalmers. On April 9, 2008, the Boothe action and the Goff action
were consolidated into a single action, which we refer to as the Oklahoma
action. The defendants named in the Oklahoma action are Bronco, the Bronco board
of directors and Allis-Chalmers. The third complaint was filed in the Delaware
Court of Chancery on January 29, 2008, which we refer to as the Delaware
action. The defendants named in the Delaware action are Bronco, the Bronco board
of directors, Allis-Chalmers and Merger Sub.
The
Oklahoma and Delaware actions generally allege that the proposed merger
consideration is inadequate, that the Bronco board of directors breached its
fiduciary duties and that Allis-Chalmers has aided and abetted the Bronco board
of directors’ alleged breaches of fiduciary duties. The actions also allege that
the preliminary joint proxy statement/prospectus included as part of
Allis-Chalmers’ registration statement on Form S-4, filed with the SEC on
February 20, 2008, contains materially incomplete and misleading
information. The actions generally request, among other things, that the suits
be designated class actions on behalf of the Bronco stockholders, that the
proposed merger be enjoined and that the Bronco board of directors undertake an
auction of Bronco or otherwise take action to maximize stockholder value.
Additionally, the Delaware action requests that all allegedly misleading or
omitted information be corrected in Allis-Chalmers’ preliminary joint proxy
statement/prospectus. The Delaware action seeks monetary damages for Bronco’s
stockholders and the Oklahoma action requests that the proposed merger be
rescinded if it is consummated. All stockholders of Allis-Chalmers and Bronco
are encouraged to read the complaints in their entirety to apprise themselves of
the plaintiffs’ allegations, which the plaintiffs purport to make on behalf of
themselves and Bronco’s other stockholders.
Allis-Chalmers
and Bronco filed motions to dismiss the Boothe action on February 21, 2008
and February 19, 2008, respectively. In response to these motions, the
parties to the Boothe action agreed to extend the time for the plaintiff to
amend his complaint, and for the defendants to amend or withdraw their motions
to dismiss, or file answers to the amended complaint. After the Boothe action
and the Goff action were consolidated into the Oklahoma action on April 9,
2008, the plaintiffs in the Oklahoma action filed a consolidated amended
complaint on April 17, 2008. Allis-Chalmers filed a motion to dismiss the
amended complaint on May 14, 2008, and Bronco and the Bronco board of
directors filed a motion to dismiss the amended complaint on May 19, 2008.
In response to these motions, the parties to the Oklahoma action agreed to
extend the time for the plaintiffs to respond to the defendants’ motions to
dismiss. Under the agreement, the plaintiffs must respond by September 3, 2008.
Discovery in the Oklahoma action is ongoing at this time.
The
plaintiff in the Delaware action filed an amended complaint on April 23,
2008. The parties to the Delaware action agreed to indefinitely extend the time
for the defendants to respond to the plaintiff’s amended complaint. Under the
agreement, no defendant must answer the plaintiff’s amended complaint or
otherwise respond until one of the following two events occurs: (1) the
plaintiff files a second amended complaint, in which case the defendants will
have 30 days from the date of service to answer the second amended complaint or
otherwise respond; or (2) the plaintiff provides written notice to all the
defendants that each defendant must answer the amended complaint, in which case
each defendant will have, upon receiving the written notice, 30 days to answer
the amended complaint or otherwise respond. Discovery in the Delaware action is
ongoing at this time.
Allis-Chalmers,
Bronco, the Bronco board of directors and Merger Sub deny the substantive
allegations in the two complaints, believe the claims asserted are baseless and
intend to vigorously defend these actions. As of this time, no order
has been issued in either proceeding that would preclude the consummation of the
merger. Each of Allis-Chalmers and the Company has the right to
terminate the merger agreement in the event a court enjoins the consummation of
the merger.
Various
other claims and lawsuits, incidental to the ordinary course of business, are
pending against the Company. In the opinion of management, all matters are
adequately covered by insurance or, if not covered, are not expected to have a
material effect on the Company’s consolidated financial position, results of
operations or cash flows.
There
have been no material changes to the Risk Factors previously disclosed in our
Annual Report on Form 10-K for the year ended December 31, 2007 filed with
the SEC on March 17, 2008.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Item 4.
Submission of Matters to a Vote of Security Holders
None.
Item 5.
Other Information
None.
Exhibits:
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Exhibit
No.
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2.1
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Merger
Agreement, dated as of August 11, 2005, by and among Bronco Drilling
Holdings, L.L.C, Bronco Drilling Company, L.L.C. and Bronco Drilling
Company, Inc. (incorporated by reference to Exhibit 2.1 to the
Registration Statement on Form S-1, File No. 333-128861, filed by the
Company with the SEC on October 6, 2005).
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2.2
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Agreement
and Plan of Merger, dated as of January 23, 2008, by and among Bronco
Drilling Company, Inc., Allis-Chalmers Energy, Inc. and Elway Merger Sub,
Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on
Form 8-K, File No. 000-51471, filed by the Company with the SEC on January
24, 2008).
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2.3
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First
Amendment, dated as of June 1, 2008, to Agreement and Plan of Merger by
and among Allis-Chalmers Energy, Inc., Bronco Drilling Company, Inc. and
Elway Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K, File No. 000-51471, filed by the Company with
the SEC on June 2, 2008).
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3.1
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Amended
and Restated Certificate of Incorporation of the Company, dated August 11,
2005 (incorporated by reference to Exhibit 2.1 to the Registration
Statement on Form S-1, File No. 333-128861, filed by the Company with the
SEC on October 6, 2005).
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3.2
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Bylaws
of the Company (incorporated by reference to Exhibit 3.2 to Amendment No.
1 to the Registration Statement on Form S-1, File No. 333-125405, filed by
the Company with the SEC on July 14, 2005).
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4.1
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Form
of Common Stock certificate (incorporated by reference to Exhibit 4.1 to
Amendment No. 2 to the Registration Statement on Form S-1, File No.
333-125405, filed by the Company with the SEC on August 2,
2005).
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*31.1
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Certification
of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to
Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as
amended.
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*31.2
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Certification
of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to
Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as
amended
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*32.1
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Certification
of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to
Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as
amended, and Section 1350 of Chapter 63 of Title 18 of the United States
Code.
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*32.2
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Certification
of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to
Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as
amended, and Section 1350 of Chapter 63 of Title 18 of the United States
Code.
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Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on their behalf by the undersigned,
thereunto duly authorized.
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Dated:
August 8, 2008
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BRONCO
DRILLING COMPANY, INC.
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By:
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/
s
/ Zachary M.
Graves
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Zachary
M. Graves
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Chief
Financial Officer
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(Principal
Accounting and Financial Officer)
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Dated:
August 8, 2008
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By:
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/s/
D. Frank Harrison
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D.
Frank Harrison
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Chief
Executive Officer
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(Authorized
Officer and Principal Executive
Officer)
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