Attached files
| file | filename |
|---|---|
| EX-31.2 - SECTION 302 CERT. CFO - Bronco Drilling Company, Inc. | exhibt31_2.htm |
| EX-10.6 - WARRANT - Bronco Drilling Company, Inc. | exhibi10_6.htm |
| EX-23.1 - CONSENT - Bronco Drilling Company, Inc. | exhibit23_1.htm |
| EX-31.1 - SECTION 302 CERT. CEO - Bronco Drilling Company, Inc. | exhibit31_1.htm |
| EX-32.1 - SECTION 906 CERT. CEO - Bronco Drilling Company, Inc. | exhibit32_1.htm |
| EX-10.5 - EMPLOYMENT AGREEMENT - Bronco Drilling Company, Inc. | exhibit10_5.htm |
| EX-32.2 - SECTION 906 CERT. CFO - Bronco Drilling Company, Inc. | exhibit32_2.htm |
| EX-21.1 - LIST OF SIGNIFICANT SUBSIDIARIES - Bronco Drilling Company, Inc. | exhibit21_1.htm |
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K
(Mark
One)
|
x
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the fiscal year ended December 31, 2009
or
|
¨
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the transition period from
to
Commission
file number 000-51471
Bronco
Drilling Company, Inc.
(Exact
name of registrant as specified in its charter)
|
Delaware
|
20-2902156
|
|
(State
or Other Jurisdiction of
Incorporation
or Organization)
|
(I.R.S.
Employer
Identification
No.)
|
|
16217
North May Avenue, Edmond, OK
|
73013
|
|
(Address
of Registrant’s Principal Executive Offices)
|
(Zip
Code)
|
(405)
242-4444
(Registrant’s
telephone number, including area code)
|
Securities
Registered Pursuant to Section 12(b) of the Act:
|
||
|
Title
of Each Class
|
Name
of Each Exchange on Which Registered
|
|
|
Common
Stock $0.01 Par Value per Share
|
The
Nasdaq Stock Market LLC
|
|
|
Securities
Registered Pursuant to Section 12(g) of the Act:
|
||
|
None
|
||
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes ¨ No x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the
Act. Yes ¨ No x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes x No ¨
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files). Yes
No
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendments to
this Form 10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, non-accelerated filer or a smaller reporting company. See
definitions of “accelerated filer”, “large accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (check one):
|
Large
Accelerated Filer ¨
|
Accelerated
Filer x
|
Non-Accelerated
Filer ¨
|
Smaller
Reporting Company ¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes ¨ No x
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant as of the most recently completed second fiscal
quarter (based on the closing price on the Nasdaq Stock Market on June 30, 2009)
was approximately $113,107,569.
As of
February 28, 2010, 27,211,449 shares of common stock were
outstanding.
Documents
Incorporated By Reference
Certain
information called for by Part III is incorporated by reference to either
certain sections of the Proxy Statement for the 2010 Annual Meeting of our
stockholders or an amendment to this Form 10-K which will be filed with the
Securities and Exchange Commission not later than 120 days after
December 31, 2009.
INDEX
|
Item
No.
|
Form
10-K
Report
Page
|
|
| 4 | ||
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1.
|
4 | |
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1A.
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9 | |
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1B.
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15 | |
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2.
|
15 | |
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3.
|
15 | |
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4.
|
15 | |
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5.
|
15 | |
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6.
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17 | |
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7.
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18 | |
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7A.
|
26 | |
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8.
|
26 | |
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9.
|
26 | |
|
9A.
|
26 | |
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9B.
|
28 | |
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10.
|
28 | |
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11.
|
28 | |
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12.
|
28 | |
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13.
|
28 | |
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14.
|
28 | |
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15.
|
28 | |
Our
disclosure and analysis in this Form 10-K 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-K 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-K 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 “Risk Factors” and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” sections and
elsewhere in this Form 10-K. All forward-looking statements speak only as of the
date of this Form 10-K. 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.
Unless
otherwise indicated or the context otherwise requires, all references in this
report to “Bronco,” the “Company,” “us,” “our,” or “we,” are to Bronco Drilling
Company, Inc., a Delaware corporation, and its consolidated
subsidiaries.
Our
Company
We provide
contract land drilling and workover services to independent oil and natural gas
exploration and production companies throughout the United
States. 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 2009. 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 two 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. As of February 28, 2010, we also owned a fleet of 60 trucks
used to transport our rigs.
We have a 40%
equity investment in Bronco Drilling MX, S. de R.L. de C.V., or Bronco MX, a
company organized under the laws of Mexico, Bronco MX provides contract land
drilling services and leases land drilling rigs to oil and natural gas companies
in Mexico. We also have a 25% equity investment in Challenger
Limited, or Challenger, a company organized under the laws of the Isle of
Man. 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 currently
conduct our operations through two operating segments: our contract land
drilling and our well servicing segments. The following is a
description of these two operating segments.
Contract Land
Drilling – Our contract land drilling segment provides contract land
drilling services. As of February 28, 2010, we owned a fleet of 37
marketed land drilling rigs. We currently operate our drilling rigs
in Oklahoma, Texas, Pennsylvania, West Virginia, North Dakota,
Utah and Louisiana. A majority of the wells we drill for
our customers are drilled in unconventional basins also known as resource
plays. These plays are generally characterized by complex geologic
formations that often require higher horsepower, premium rigs and experienced
crews to reach targeted depths. Our current fleet of 37 marketed drilling rigs
range from 950 to 2,000 horsepower. Accordingly, such rigs can, or in the case
of inventoried rigs upon refurbishment, will be able to, reach the depths
required and have the capability of drilling horizontal and directional 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.
Well Servicing
– Our 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. As of February 28, 2010 we owned a fleet of 61
workover rigs.
Financial
information about our operating segments is included in Note 9, Business Segments and
Concentrations, of the Notes to Consolidated Financial
Statements.
Our
Acquisitions
The following
table summarizes completed acquisitions in which we acquired rigs and rig
related equipment since June 2001:
|
Date
|
Acquisition
|
Purchase
Price
|
Number of Land
Drilling /Workover Rigs
|
||||||
|
June
2001
|
Ram
Petroleum
|
$ | 1,250,000 | 1 | |||||
|
May 2002
|
Bison
Drilling and Four Aces
Drilling
|
$ | 12,500,000 | 7 | |||||
|
August 2003
|
Elk Hill Drilling and U.S. Rig & Equipment
|
$ | 49,000,000 | 22 | |||||
|
July 2005
|
Strata
Drilling and Strata
Property
|
$ | 20,000,000 | 3 | |||||
|
October 2005
|
Eagle
Drilling
|
$ | 50,000,000 | 12 | |||||
|
October 2005
|
Thomas
Drilling
|
$ | 68,000,000 | 13 | |||||
|
January 2006
|
Big
A
Drilling
|
$ | 18,150,000 | 6 | |||||
|
January 2007
|
Eagle
Well
Service
|
$ | 32,085,000 | 31 | |||||
In May 2002,
we purchased seven drilling rigs ranging in size from 400 to 950 horsepower,
associated spare parts and equipment, drill pipe, haul trucks and vehicles from
Bison Drilling L.L.C. and Four Aces Drilling L.L.C.
In August
2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc., or
Elk Hill, and certain drilling rig structures and components from U.S.
Rig & Equipment, Inc., an affiliate of Elk Hill. In these transactions,
we acquired drilling rigs and inventoried structures and components which, with
refurbishment and upgrades, could be used to assemble 22 drilling rigs. At the
date of its acquisition, Elk Hill was an inactive corporation with no customers,
employees, operations or operational drilling rigs. We began refurbishing the
acquired rigs and have deployed seventeen of the rigs since November
2003.
In July 2005,
we acquired all of the membership interests of Strata Drilling, L.L.C. and
Strata Property, L.L.C., or together Strata. Included in the Strata
acquisitions were two operating rigs, one rig that was refurbished, related
structures, equipment and components and a 16 acre yard in Oklahoma City,
Oklahoma used for equipment storage and refurbishment of inventoried
rigs.
In September
2005, we acquired 18 trucks and related equipment through our acquisition of
Hays Trucking, Inc., or Hays Trucking, for a purchase price consisting of $3.0
million in cash, which included the repayment of $1.9 million of debt owed
by Hays Trucking, and 65,368 shares of our common stock.
In October
2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C., or Eagle
Drilling, for approximately $50.0 million plus approximately $500,000 of related
transaction costs, and 13 land drilling rigs from Thomas Drilling Co. for
approximately $68.0 million plus approximately $2.6 million of related
transaction costs.
In
January 2006, we purchased six land drilling rigs and certain other assets,
including heavy haul trucks and excess rig equipment and inventory, from Big A
Drilling L.L.C., or Big A, for $16.3 million in cash and 72,571 shares of our
common stock.
On January 9,
2007, we completed the acquisition of 31 workover rigs, 24 of which were
operating, from Eagle Well Service, Inc., or Eagle Well, and related
subsidiaries for $2.6 million in cash, 1,070,390 shares of our common stock, and
the assumption of certain liabilities. We subsequently deployed the
remaining seven rigs periodically during the first nine months of
2007.
Our
Equity Investments
On
January 4, 2008, we acquired a 25% equity interest in Challenger Limited,
or Challenger, in exchange for six drilling rigs and $5.0 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. Five of the contributed drilling rigs
were from our existing marketed fleet and one was a newly constructed rig. The
general specifications of the contributed rigs are as
follows:
|
Approximate
|
|||||
|
Drilling
|
|||||
|
Rig
|
Design
|
Depth
(ft)
|
Type
|
Horsepower
|
|
|
3
|
Cabot
900
|
10,000
|
Mechanical
|
950
|
|
|
18
|
Gardner
Denver 1500E
|
25,000
|
Electric
|
2,000
|
|
|
19
|
Mid
Continent U-1220 EB
|
25,000
|
Electric
|
2,000
|
|
|
38
|
National
1320
|
25,000
|
Electric
|
2,000
|
|
|
93
|
National
T-32
|
8,000
|
Mechanical
|
500
|
|
|
96
|
Ideco
H-35
|
8,000
|
Mechanical
|
400
|
In a separate
transaction, we sold to Challenger four additional drilling rigs and ancillary
equipment for $13.0 million, payable in installments over thirty-six
months. During the second quarter of 2009, we agreed to reduce the
installment payments and assumed ownership of two drilling rigs originally sold
to Challenger. The general specifications of the two sold rigs are as
follows:
|
Rig
|
Design
|
Approximate
Drilling Depth (ft)
|
Type
|
Horsepower
|
|
|
91
|
Ideco
H-35
|
8,000
|
Mechanical
|
450
|
|
|
95
|
Emsco
GB800
|
12,000
|
Mechanical
|
1,000
|
We reviewed
our investment in Challenger at September 30, 2009 for impairment based on the
guidance of ASC Topic 323, Investments-Equity Method and Joint
Venture, which states that a loss in value of an investment which is an
other than temporary decline should be recognized. Evidence of a loss
in value might include the absence of an ability to recover the carrying amount
of the investment or inability of the investee to sustain an earnings capacity
which would justify the carrying amount of the investment. A current
fair value of an investment that is less than its carrying amount may indicate a
loss in value of the investment. Due to the recent volatility and
decline in oil and natural gas prices, a deteriorating global economic
environment and the anticipated future earnings of Challenger, we deemed it
necessary to test the investment for impairment. Fair value of the investment
was estimated using a combination of income, or discounted cash flows approach
and the market approach, which utilizes comparable companies’
data. The analysis resulted in a fair value of $39.8 million related
to our investment in Challenger, which was below the carrying value of the
investment and resulted in a non-cash impairment charge in the amount of $21.2
million.
In September
2009, Carso Infraestructura y Construcción, S.A.B. de C.V., or CICSA, purchased
from us 60% of the outstanding membership interests of Bronco MX for
approximately $30.0 million. After giving effect to the transaction, we
own the remaining 40% of the outstanding membership interests of Bronco
MX. Immediately prior to the sale of the membership interests to
CICSA, we contributed six drilling rigs and the future net profit
from rig leases relating to three additional drilling rigs, which
the Company contributed to Bronco MX upon the expiration of the leases
relating to such rigs. The general specifications of the 9 nine
contributed rigs are as follows:
|
Rig
|
Design
|
Approximate
Drilling Depth (ft)
|
Type
|
Horsepower
|
|
|
43
|
Gardner
Denver 800
|
15,000
|
Mechanical
|
1,000
|
|
|
4
|
Skytop
Brewster N46
|
14,000
|
Mechanical
|
950
|
|
|
53
|
Skytop
Brewster N42
|
12,000
|
Mechanical
|
850
|
|
|
55
|
Oilwell
660
|
12,000
|
Mechanical
|
1,000
|
|
|
58
|
National
N55
|
12,000
|
Mechanical
|
800
|
|
|
60
|
Skytop
Brewster N46
|
14,000
|
Mechanical
|
850
|
|
|
72
|
Skytop
Brewster N42
|
10,000
|
Mechanical
|
750
|
|
|
76
|
National
N55
|
12,000
|
Mechanical
|
700
|
|
|
78
|
Seaco
1200
|
12,000
|
Mechanical
|
1,200
|
|
Bronco MX is jointly
managed, with CICSA having three representatives on its board of managers and
the Company having two representatives on its board of managers. The
Company and CICSA, and their respective affiliates, intend to conduct all future
land drilling and workover rig services, rental, construction, refurbishment,
transportation, trucking and mobilization in Mexico and Latin America
exclusively through Bronco MX, subject to Bronco MX’s ability to
perform.
Overview
of Our Operating Segments
Contract
Land Drilling
A drilling
rig consists of engines, a hoisting system, a rotating system, pumps and related
equipment to circulate drilling fluid, blowout preventors and related
equipment.
Diesel or gas
engines are typically the main power sources for a drilling rig. Power
requirements for drilling jobs may vary considerably, but most drilling rigs
employ two or more engines to generate between 500 and 2,000 horsepower,
depending on well depth and rig design. Most drilling rigs capable of drilling
in deep formations, involving depths greater than 15,000 feet, use
diesel-electric power units to generate and deliver electric current through
cables to electrical switch gears, then to direct-current electric motors
attached to the equipment in the hoisting, rotating and circulating
systems.
Drilling rigs
use long strings of drill pipe and drill collars to drill wells. Drilling rigs
are also used to set heavy strings of large-diameter pipe, or casing, inside the
borehole. Because the total weight of the drill string and the casing can exceed
500,000 pounds, drilling rigs require significant hoisting and braking
capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or
derrick, a drilling line, a traveling block and hook assembly and ancillary
equipment that attaches to the rotating system, a mechanism known as the
drawworks. The drawworks mechanism consists of a revolving drum, around which
the drilling line is wound, and a series of shafts, clutches and chain and gear
drives for generating speed changes and reverse motion. The drawworks also
houses the main brake, which has the capacity to stop and sustain the weights
used in the drilling process. When heavy loads are being lowered, a hydromatic
or electric auxiliary brake assists the main brake to absorb the great amount of
energy developed by the mass of the traveling block, hook assembly, drill pipe,
drill collars and drill bit or casing being lowered into the well.
The rotating
equipment from top to bottom consists of a swivel, the kelly bushing, the kelly,
the rotary table, drill pipe, drill collars and the drill bit. We refer to the
equipment between the swivel and the drill bit as the drill stem. The swivel
assembly sustains the weight of the drill stem, permits its rotation and affords
a rotating pressure seal and passageway for circulating drilling fluid into the
top of the drill string. The swivel also has a large handle that fits inside the
hook assembly at the bottom of the traveling block. Drilling fluid enters the
drill stem through a hose, called the rotary hose, attached to the side of the
swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40
feet long, that transmits torque from the rotary table to the drill stem and
permits its vertical movement as it is lowered into the hole. The bottom end of
the kelly fits inside a corresponding triangular, square or hexagonal opening in
a device called the kelly bushing. The kelly bushing, in turn, fits into a part
of the rotary table called the master bushing. As the master bushing rotates,
the kelly bushing also rotates, turning the kelly, which rotates the drill pipe
and thus the drill bit. Drilling fluid is pumped through the kelly on its way to
the bottom. The rotary table, equipped with its master bushing and kelly
bushing, supplies the necessary torque to turn the drill stem. The drill pipe
and drill collars are both steel tubes through which drilling fluid can be
pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or
joints, with threaded sections on each end. Drill collars are heavier than drill
pipe and are also threaded on the ends. Collars are used on the bottom of the
drill stem to apply weight to the drilling bit. At the end of the drill stem is
the bit, which chews up the formation rock and dislodges it so that drilling
fluid can circulate the fragmented material back up to the surface where the
circulating system filters it out of the fluid.
Drilling
fluid, often called mud, is a mixture of clays, chemicals and water or oil,
which is carefully formulated for the particular well being drilled. Bulk
storage of drilling fluid materials, the pumps and the mud-mixing equipment are
placed at the start of the circulating system. Working mud pits and reserve
storage are at the other end of the system. Between these two points the
circulating system includes auxiliary equipment for drilling fluid maintenance
and equipment for well pressure control. Within the system, the drilling mud is
typically routed from the mud pits to the mud pump and from the mud pump through
a standpipe and the rotary hose to the drill stem. The drilling mud travels down
the drill stem to the bit, up the annular space between the drill stem and the
borehole and through the blowout preventer stack to the return flow line. It
then travels to a shale shaker for removal of rock cuttings, and then back to
the mud pits, which are usually steel tanks. The reserve pits, usually one or
two fairly shallow excavations, are used for waste material and excess water
around the location.
There are
numerous factors that differentiate drilling rigs, including their power
generation systems and their drilling depth capabilities. The actual drilling
depth capability of a rig may be less than or more than its rated depth
capability due to numerous factors, including the size, weight and amount of the
drill pipe on the rig. The intended well depth and the drill site conditions
determine the amount of drill pipe and other equipment needed to drill a well.
Generally, land rigs operate with crews of five to six persons.
As of
February 28, 2010, our drilling rig fleet consisted of 37 marketed drilling
rigs, 13 of which were operating on term contracts. Thirty-two of
these drilling rigs have undergone significant refurbishment since October 2003
by us or the parties from which the rigs were purchased. The
following table sets forth information regarding utilization for our fleet of
marketed drilling rigs:
|
Year
Ended December 31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Average
number of operating drilling rigs
|
44
|
44
|
51
|
|||
|
Revenue
days
|
5,699
|
12,712
|
14,245
|
|||
|
Utilization
Rates
|
36%
|
79%
|
76%
|
|||
We believe
that our operating drilling rigs and other related equipment are in good
operating condition. Our employees perform periodic maintenance and
minor repair work on our drilling rigs. Historically, we have relied on various
oilfield service companies for major repair work and overhaul of our drilling
equipment. We own a 41,000 square foot machine shop in Oklahoma City, which
allows us to refurbish and repair our rigs and equipment in-house. In the event
of major breakdowns or mechanical problems, our rigs could be subject to
significant idle time and a resulting loss of revenue if the necessary repair
services are not immediately available. We also own a fleet of 60
trucks and related transportation equipment that we use to transport our
drilling rigs to and from drilling sites. By owning our own trucks,
we reduce the cost of rig moves, downtime between rig moves and general wear and
tear on our drilling rigs.
As a provider
of contract land drilling services, our business and the profitability of our
operations depend on the level of drilling activity by oil and natural gas
exploration and production companies operating in the geographic markets where
we operate. The oil and natural gas exploration and production industry is a
historically cyclical industry characterized by significant changes in the
levels of exploration and development activities. For example, as oil and
natural gas prices steeply declined and credit markets tightened in late
calendar 2008, customers aggressively reduced drilling budgets. As a
result, we experienced a decline in rig utilization. During periods
of lower levels of drilling activity, price competition tends to increase and
results in decreases in the profitability of daywork contracts. In this lower
level of drilling activity and competitive price environment, we may be more
inclined to enter into footage contracts that expose us to greater risk of loss
without commensurate increases in potential contract profitability.
We obtain our
contracts for drilling oil and natural gas wells either through competitive
bidding or through direct negotiations with customers. We typically enter into
drilling contracts that provide for compensation on a daywork basis.
Occasionally we enter into drilling contracts that provide for compensation on a
footage basis. The 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.
Generally, our contracts provide for the drilling of a single well and typically
permit the customer to terminate on short notice, usually on payment of an
agreed fee. During 2009, the Company recorded $7.9 million of
contract drilling revenue related to terminated contracts.
The following
table presents, by type of contract, information about the total number of wells
we completed for our customers during the years ended December 31, 2009,
2008 and 2007.
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Daywork
Contracts
|
152 | 378 | 430 | |||||||||
|
Footage
Contracts
|
- | - | 3 | |||||||||
|
Turnkey
Contracts
|
- | - | - | |||||||||
|
Total
|
152 | 378 | 433 | |||||||||
Daywork
Contracts. Under daywork drilling contracts, we provide a drilling rig
with required personnel to our customer who supervises the drilling of the well.
We are paid based on a negotiated fixed rate per day while the rig is used.
Daywork drilling contracts specify the equipment to be used, the size of the
hole and the depth of the well. Under a daywork drilling contract, the customer
bears a large portion of the out-of-pocket drilling costs and we generally bear
no part of the usual risks associated with drilling, such as time delays and
unanticipated costs.
Footage
Contracts. Under footage contracts, we are paid a fixed amount for each
foot drilled, regardless of the time required or the problems encountered in
drilling the well. We typically pay more of the out-of-pocket costs associated
with footage contracts as compared to daywork contracts. The risks to us on a
footage contract are greater because we assume most of the risks associated with
drilling operations generally assumed by the operator in a daywork contract,
including the risk of blowout, loss of hole, stuck drill pipe, machinery
breakdowns, abnormal drilling conditions and risks associated with
subcontractors’ services, supplies, cost escalation and personnel. When we enter
into footage contracts, we endeavor to manage this additional risk through the
use of engineering expertise and bid the footage contracts accordingly, and we
typically maintain insurance coverage against some, but not all, drilling
hazards. However, the occurrence of uninsured or under-insured losses or
operating cost overruns on our footage jobs could have a negative impact on our
profitability. While we have historically entered into few footage
contracts, we may enter into more of such arrangements in the future to the
extent warranted by market conditions.
Turnkey
Contracts. Turnkey contracts typically provide for a drilling company to
drill a well for a customer to a specified depth and under specified conditions
for a fixed price, regardless of the time required or the problems encountered
in drilling the well. The drilling company would provide technical expertise and
engineering services, as well as most of the equipment and drilling supplies
required to drill the well. The drilling company may subcontract for related
services, such as the provision of casing crews, cementing and well logging.
Under typical turnkey drilling arrangements, a drilling company would not
receive progress payments and would be paid by its customer only after it had
performed the terms of the drilling contract in full.
Although we
have not historically entered into any turnkey contracts, we may decide to enter
into such arrangements in the future to the extent warranted by market
conditions. It is also possible that we may acquire such contracts in connection
with future acquisitions. The risks to a drilling company under a turnkey
contract are substantially greater than on a well drilled on a daywork basis.
This is primarily because under a turnkey contract the drilling company assumes
most of the risks associated with drilling operations generally assumed by the
operator in a daywork contract, including the risk of blowout, loss of hole,
stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks
associated with subcontractors’ services, supplies, cost escalations and
personnel.
Well
Servicing
Our well
servicing segment provides a broad range of well services to oil and natural gas
exploration and production companies, including maintenance, workover, new well
completion, and plugging and abandonment. Our workover rigs provide
the means for hoisting equipment and tools into and out of the well bore, and
our well servicing equipment and capabilities are essential to facilitate most
other services performed on a well. Our well servicing segment services, which
are performed to maintain and improve production throughout the productive life
of an oil and gas well, include:
|
•
|
maintenance
work involving removal, repair and replacement of down-hole equipment and
returning the well to production after these operations are
completed;
|
|
•
|
hoisting
tools and equipment required by the operation into and out of the well, or
removing equipment from the well bore, to facilitate specialized
production enhancement and well repair operations performed by other
oilfield service
companies;
|
|
•
|
plugging
and abandonment services when a well has reached the end of its productive
life; and
|
|
•
|
completion
work involving selectively perforating the well casing at the depth of
discrete producing zones, stimulating and testing these zones and
installing down-hole
equipment.
|
We generally charge our customers an hourly
rate for these services, which varies based on a number of considerations
including market conditions in each region, the type of rig and ancillary
equipment required, and the necessary personnel. Our fleet includes 61 well servicing rigs as of
February 28, 2010, including 37 newbuilds since January 2007. We temporarily
suspended operations in our well servicing segment in June 2009. We
intend to restructure this business unit in anticipation of more favorable
market conditions. Currently, Bronco senior management is rebuilding the
management team within Bronco Energy Services. Several candidates have been
identified to lead this division going forward. The plan for potential
redeployment includes new geographic markets, a greater focus on completion
services as well as the exploration of potential expansion into international
markets where we feel we have a competitive advantage.
Maintenance. Regular
maintenance is generally required throughout the life of a well to sustain
optimal levels of oil and gas production. We provide well service rigs,
equipment and crews for these maintenance services. Maintenance services are
often performed on a series of wells in proximity to each other. These services
consist of routine mechanical repairs necessary to maintain production, such as
repairing inoperable pumping equipment in an oil well or replacing defective
tubing in a gas well, and removing debris such as sand and paraffin from the
well. Other services include pulling the rods, tubing, pumps and other downhole
equipment out of the well bore to identify and repair a production problem.
These downhole equipment failures are typically caused by the repetitive pumping
action of an oil well. Corrosion, water cut, grade of oil, sand production and
other factors can also result in frequent failures of downhole
equipment.
The need for
maintenance activity does not directly depend on the level of drilling activity,
although it is impacted by fluctuations in oil and gas prices. Additionally,
demand for our maintenance services is affected by changes in the total number
of producing oil and gas wells in our geographic service areas.
Our regular
well maintenance services involve relatively low-cost, short-duration jobs which
are part of normal well operating costs. Demand for well maintenance is driven
primarily by the production requirements of the local oil or gas fields and, to
a lesser degree, the actual prices received for oil and gas. Well operators
cannot delay all maintenance work without a significant impact on production.
Operators may, however, choose to temporarily shut in producing wells when oil
or gas prices are too low to justify additional expenditures, including
maintenance.
Workover. In
addition to periodic maintenance, producing oil and gas wells occasionally
require major repairs or modifications called workovers, which are typically
more complex and more time consuming than maintenance operations. Workover
services include extensions of existing wells to drain new formations either
through perforating the well casing to expose additional productive zones not
previously produced, deepening well bores to new zones or the drilling of
lateral well bores to improve reservoir drainage patterns. Our workover rigs are
also used to convert former producing wells to injection wells through which
water or carbon dioxide is then pumped into the formation for enhanced oil
recovery operations. Workovers also include major subsurface repairs such as
repair or replacement of well casing, recovery or replacement of tubing and
removal of foreign objects from the well bore. These extensive workover
operations are normally performed by a workover rig with additional specialized
auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud
tanks and fishing tools, depending upon the particular type of workover
operation. A workover may require a few days to several weeks and generally
requires additional auxiliary equipment. The demand for workover services is
sensitive to oil and gas producers’ intermediate and long-term expectations for
oil and gas prices. As oil and gas prices increase, the level of workover
activity tends to increase as oil and gas producers seek to increase output by
enhancing the efficiency of their wells. Exploration and Production companies
tend to reduce their budgets during a declining commodity price environment,
similarly to what we are experiencing currently, which can result in a
significant reduction in demand for our workover services.
New Well
Completion. New well completion services involve the
preparation of newly drilled wells for production. The completion process may
involve selectively perforating the well casing in the productive zones to allow
oil or gas to flow into the well bore, stimulating and testing these zones and
installing the production string and other downhole equipment. We provide well
service rigs to assist in this completion process. Newly drilled wells are
frequently completed by well servicing rigs to minimize the use of higher cost
drilling rigs in the completion process. The completion process typically
requires a few days to several weeks, depending on the nature and type of the
completion, and generally requires additional auxiliary equipment. Accordingly,
completion services require less well-to-well mobilization of equipment and
generally provide higher operating margins than regular maintenance work. The
demand for completion services is directly related to drilling activity levels,
which are sensitive to expectations relating to and changes in oil and gas
prices. Oil and natural gas producers attempt to maximize the
productivity of their wells in a higher priced environment.
Plugging and
Abandonment. Well servicing rigs are also used in the process
of permanently closing oil and gas wells no longer capable of producing in
economic quantities. Plugging and abandonment work can be performed with a well
servicing rig along with wireline and cementing equipment; however, this service
is typically provided by companies that specialize in plugging and abandonment
work. Many well operators bid this work on a “turnkey” basis, requiring the
service company to perform the entire job, including the sale or disposal of
equipment salvaged from the well as part of the compensation received, and
complying with state regulatory requirements. Plugging and abandonment work can
provide favorable operating margins and is less sensitive to oil and gas pricing
than drilling and workover activity since well operators must plug a well in
accordance with state regulations when it is no longer
productive.
We gauge
activity levels in our well servicing rig operations based on rig utilization
rate. We compute operating workover rig utilization rates by dividing
revenue hours by total available hours during a period. Total available hours
are the number of hours during the period that we have owned the operating
workover rig based on a 50-hour work week per rig.
For the years
ended December 31, 2009, 2008, and 2007, our workover rig
utilization rates, revenue hours and average number of operating workover rigs
were as follows:
|
Year
Ended December 31,
|
||||||
|
2009
|
2008
|
2007
|
||||
|
Average
number of operating workover rigs
|
52
|
52
|
33
|
|||
|
Revenue
hours
|
11,386
|
91,591
|
63,746
|
|||
|
Utilization
Rates
|
17%
|
68%
|
78%
|
|||
Customers
and Marketing
We market our
drilling and workover rigs to a number of major and independent oil and gas
companies that are active in the geographic areas in which we operate. The
following table shows our customers that accounted for more than 5% of our total
revenue for each of our last three years. In the opinion of
management, the loss of any of our customers individually would not have a
material adverse effect on our business.
|
Customer
|
Total
Revenue Percentage
|
||
|
2009
|
|||
|
Comstock
Oil and Gas
|
12 | % | |
|
Whiting
Petroleum
|
9 | % | |
|
Pemex
Exploracion
|
8 | % | |
|
Laredo
Petroleum
|
6 | % | |
|
Antero
Resources
|
6 | % | |
|
Hunt
Oil Company
|
5 | % | |
|
JMA
Energy Company, LLC
|
5 | % | |
|
2008
|
|||
|
Antero
Resources
|
11 | % | |
|
XTO
Energy
|
7 | % | |
|
JMA
Energy Company, LLC
|
5 | % | |
|
Pablo
Energy II, LLC
|
5 | % | |
|
2007
|
|||
|
Antero
Resources
|
11 | % | |
|
Chesapeake
Energy Corporation
|
8 | % | |
|
Comstock
Oil and Gas
|
7 | % | |
|
XTO
Energy
|
6 | % | |
|
Pablo
Energy II, LLC
|
5 | % |
We primarily
market our drilling and workover rigs through employee marketing
representatives. These marketing representatives use personal contacts and
industry periodicals and publications to determine which operators are planning
to drill oil and natural gas wells in the near future in our market areas. Once
we have been placed on the “bid list” for an operator, we will typically be
given the opportunity to bid on most future wells for that operator in the areas
in which we operate. Our rigs are typically contracted on a well-by-well
basis.
Competition
Contract
Land Drilling
We encounter
substantial competition from other drilling contractors. Our primary market area
is highly fragmented and competitive. The fact that drilling rigs are mobile and
can be moved from one market to another in response to market conditions
heightens the competition in the industry.
The
drilling contracts we compete for are usually awarded on the basis of
competitive bids. Our principal competitors are Nabors Industries, Inc.,
Patterson-UTI Energy, Inc., Unit Corp., Union Drilling, Inc., Pioneer Drilling
Company and Helmerich & Payne, Inc. There are numerous smaller
companies that compete in our service markets as well. We believe pricing and
rig availability are the primary factors our potential customers consider in
determining which drilling contractor to select. In addition, we believe the
following factors are also important:
|
•
|
the
type and condition of each of the competing drilling
rigs;
|
|
•
|
the
mobility and efficiency of the
rigs;
|
|
•
|
the
quality of service and experience of the rig
crews;
|
|
•
|
the
offering of ancillary services;
and
|
|
•
|
the
ability to provide drilling equipment adaptable to, and personnel familiar
with, new technologies and drilling
techniques.
|
While we must
be competitive in our pricing, our competitive strategy generally emphasizes the
quality of our equipment and the experience of our rig crews to differentiate us
from our competitors. This strategy is less effective as lower demand for
drilling services or an oversupply of rigs usually results in increased price
competition and makes it more difficult for us to compete on the basis of
factors other than price. In all of the markets in which we compete, an
oversupply of rigs can cause greater price competition.
Contract
drilling companies compete primarily on a regional basis, and the intensity of
competition may vary significantly from region to region at any particular time.
If demand for drilling services improves in a region where we operate, our
competitors might respond by moving in suitable rigs from other regions. An
influx of drilling rigs from other regions could rapidly intensify competition
and reduce profitability.
Many of our
competitors have greater financial, technical and other resources than we do.
Their greater capabilities in these areas may enable them to:
|
•
|
better
withstand industry downturns;
|
|
•
|
compete
more effectively on the basis of price and
technology;
|
|
•
|
better
retain skilled rig personnel;
and
|
|
•
|
build
new rigs or acquire and refurbish existing rigs so as to be able to place
rigs into service more quickly than us in periods of high drilling
demand.
|
|
|
Well
Servicing
|
The market
for well servicing is highly competitive. Competition is influenced
by such factors as price, capacity, availability of work crews, type and
condition of equipment and reputation and experience of the service
provider. We believe that pricing is generally the primary factor in
determining which service provider is awarded the work. Our
competition includes small regional contractors as well as larger companies with
international operations. Our principal competitors are Basic Energy Services,
Inc., Key Energy Services Inc., Nabors Industries, Inc. and Complete Production
Services, Inc.. These competitors operate in most of the large oil and gas
producing regions in the U.S. In addition, there are numerous smaller
companies that compete in our well service markets.
Raw
Materials
The materials
and supplies we use in our drilling and well service operations include fuels to
operate our drilling and well service equipment, drilling mud, drill pipe, drill
collars, drill bits and cement. We do not rely on a single source of supply for
any of these items. While we are not currently experiencing any shortages, from
time to time there have been shortages of drilling equipment and supplies during
periods of high demand.
Shortages
could result in increased prices for drilling equipment or supplies that we may
be unable to pass on to customers. In addition, during periods of shortages, the
delivery times for equipment and supplies can be substantially longer. Any
significant delays in our obtaining drilling equipment or supplies could limit
drilling operations and jeopardize our relations with customers. In addition,
shortages of drilling equipment or supplies could delay and adversely affect our
ability to obtain new contracts for our rigs, which could have a material
adverse effect on our financial condition and results of
operations.
Operating
Risks and Insurance
Our
operations are subject to the many hazards inherent in the contract land
drilling and well servicing business, including the risks of:
|
|
•
|
blowouts;
|
|
•
|
fires
and explosions;
|
|
•
|
loss
of well control;
|
|
•
|
collapse
of the borehole;
|
|
•
|
lost
or stuck drill strings;
and
|
|
•
|
damage
or loss from natural
disasters.
|
Any of these
hazards can result in substantial liabilities or losses to us from, among other
things:
|
•
|
suspension
of drilling
operations;
|
|
•
|
damage
to, or destruction of, our property and equipment and that of
others;
|
|
•
|
personal
injury and loss of
life;
|
|
•
|
damage
to producing or potentially productive oil and natural gas formations
through which we drill;
and
|
|
•
|
environmental
damage.
|
We seek to
protect ourselves from some but not all operating hazards through insurance
coverage. However, some risks are either not insurable or insurance is available
only at rates that we consider uneconomical. Depending on competitive
conditions and other factors, we attempt to obtain contractual protection
against uninsured operating risks from our customers. However, customers who
provide contractual indemnification protection may not in all cases have
sufficient financial resources or maintain adequate insurance to support their
indemnification obligations. We can offer no assurance that our insurance or
indemnification arrangements will adequately protect us against liability or
loss from all the hazards of our operations. The occurrence of a significant
event that we have not fully insured or indemnified against or the failure of a
customer to meet its indemnification obligations to us could materially and
adversely affect our results of operations and financial condition. Furthermore,
we may not be able to maintain adequate insurance in the future at rates we
consider reasonable.
Our insurance
coverage includes property insurance on our rigs, drilling equipment and real
property. Our insurance coverage for property damage to our rigs and to our
drilling equipment is based on a third party estimate of the appraised value of
the rigs and drilling equipment. The policy provides for a deductible on
drilling rigs of $1.0 million per occurrence and $50,000 per occurrence for
workover rigs. Our umbrella liability insurance coverage is $25.0 million per
occurrence and in the aggregate, with a deductible of $10,000 per occurrence. We
believe that we are adequately insured for public liability and property damage
to others with respect to our operations. However, such insurance may not be
sufficient to protect us against liability for all consequences of well
disasters, extensive fire damage or damage to the environment.
Employees
As of
February 28, 2010, we had 646 employees. Approximately, 117 of these employees
are salaried administrative or supervisory employees. The rest of our employees
are hourly employees, the majority of whom operate or maintain our drilling rigs
and rig-hauling trucks. The number of hourly employees fluctuates depending on
the number of drilling projects we are engaged in at any particular time. None
of our employees are subject to collective bargaining arrangements.
Our
operations require the services of employees having the technical training and
experience necessary to obtain the proper operational results. As a result, our
operations depend, to a considerable extent, on the continuing availability of
such personnel. Although we have not encountered material difficulty in hiring
and retaining qualified rig crews, shortages of qualified personnel can occur in
our industry. If we should suffer any material loss of personnel to competitors
or be unable to employ additional or replacement personnel with the requisite
level of training and experience to adequately operate our equipment, our
operations could be materially and adversely affected. While we believe our wage
rates are competitive and our relationships with our employees are satisfactory,
a significant increase in the wages paid by other employers could result in a
reduction in our workforce, increases in wage rates, or both. The occurrence of
either of these events for a significant period of time could have a material
and adverse effect on our financial condition and results of
operations.
Governmental
Regulation
Our
operations are subject to stringent federal, state and local laws and
regulations governing the protection of the environment and human health and
safety. Several such laws and regulations relate to the handling, storage and
disposal of oilfield waste and restrict the types, quantities and concentrations
of such regulated substances that can be released into the environment. Several
such laws also require removal and remedial action and other cleanup under
certain circumstances, commonly regardless of fault. Planning, implementation
and maintenance of protective measures are required to prevent accidental
discharges. Spills of oil, natural gas liquids, drilling fluids and other
substances may subject us to penalties and cleanup requirements. In addition,
our operations are sometimes conducted in or near ecologically sensitive areas,
which are subject to special protective measures and which may expose us to
additional operating costs and liabilities related to restricted operations, for
accidental discharges of oil, natural gas, drilling fluids, contaminated water
or other substances or for noncompliance with other aspects of applicable laws
and regulations. Historically, we have not been required to obtain environmental
or other permits prior to drilling a well. Instead, the operator of the oil and
gas property has been obligated to obtain the necessary permits at its own
expense.
The federal
Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act,
the Resource Conservation and Recovery Act, the Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, the Safe Drinking Water
Act, the Occupational Safety and Health Act, or OSHA, and their state
counterparts and similar statutes and related regulations are the primary
vehicles for imposition of such requirements and for civil, criminal and
administrative penalties and other sanctions for violation of their
requirements. The OSHA hazard communication standard and related regulations,
the Environmental Protection Agency “community right-to-know” regulations under
Title III of the federal Superfund Amendment and Reauthorization Act and
comparable state statutes require us to organize and report information about
the hazardous materials we use in our operations to employees, state and local
government authorities and local citizens. In addition, CERCLA, also known as
the “Superfund” law, and similar state statutes impose strict liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered responsible for the release or threatened release of
hazardous substances into the environment. These persons include the current
owner or operator of a facility where a release has occurred, the owner or
operator of a facility at the time a release occurred and companies that
disposed of or arranged for the disposal of hazardous substances found at a
particular site. This liability may be joint and several. Such liability, which
may be imposed for the conduct of others and for conditions others have caused,
includes the cost of removal and remedial action as well as damages to natural
resources. Few defenses exist to the liability imposed by environmental laws and
regulations. It is also not uncommon for third parties to file claims for
personal injury and property damage caused by substances released into the
environment.
Environmental
laws and regulations are complex and subject to frequent changes. Failure to
comply with governmental requirements or inadequate cooperation with
governmental authorities could subject a responsible party to administrative,
civil or criminal action. We may also be exposed to environmental or other
liabilities originating from businesses and assets that we acquired from others.
We believe we are in substantial compliance with applicable environmental laws
and regulations and, to date, such compliance has not materially affected our
capital expenditures, earnings or competitive position. We do not expect to
incur material capital expenditures in our next fiscal year in order to comply
with current or reasonably anticipated environment control requirements.
However, our compliance with amended, new or more stringent requirements,
stricter interpretations of existing requirements or the future discovery of
regulatory noncompliance or contamination may require us to make material
expenditures or subject us to liabilities that we currently do not
anticipate.
As we
continue to expand our operations outside of the United States, we must comply
with numerous laws and regulations relating to international business
operations, including the Foreign Corrupt Practices Act, or FCPA. The
creation and implementation of international business practices compliance
programs is costly and such programs are difficult to enforce, particularly
where reliance on third parties is required.
The FCPA
prohibits any U.S. individual or business from paying, offering, or authorizing
payment or offering of anything of value, directly or indirectly, to any foreign
official, political party or candidate for the purpose of influencing any act or
decision of the foreign entity in order to assist the individual or business in
obtaining or retaining business. The FCPA also obligates companies whose
securities are listed in the United States to comply with certain accounting
provisions requiring the company to maintain books and records that accurately
and fairly reflect all transactions of the corporation, including international
subsidiaries, and to devise and maintain an adequate system of internal
accounting controls for international operations. The anti-bribery provisions of
the FCPA are enforced primarily by the U.S. Department of Justice. The SEC is
involved with enforcement of the books and records provisions of the
FCPA.
The failure
to comply with laws governing international business practices may result in
substantial penalties, including suspension or debarment from government
contracting. Violation of the FCPA can result in significant civil and criminal
penalties. A failure to satisfy any of our obligations under laws governing
international business practices could have a negative impact on our operations
and harm our reputation. The SEC also may suspend or bar issuers from trading
securities on United States exchanges for violations of the FCPA’s accounting
provisions.
In addition,
our business depends on the demand for land drilling services from the oil and
natural gas industry and, therefore, is affected by tax, environmental and other
laws relating to the oil and natural gas industry generally, by changes in those
laws and by changes in related administrative regulations. It is possible that
these laws and regulations may in the future add significantly to our operating
costs or those of our customers or otherwise directly or indirectly affect our
operations.
Available
Information
Our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and all amendments to those reports filed or furnished pursuant to Section 13(a)
or 15(d) of the Exchange Act are made available free of charge on the Investor
Relations page of our website at www.broncodrill.com
as soon as reasonably practicable after such material is electronically filed
with, or furnished to, the SEC. Our code of conduct and business
ethics is also available on our website. Information contained on our
website, or on other websites that may be linked to our website, is not
incorporated by reference in this annual report on Form 10-K and should not be
considered part of this report or any other filing that we make with the
SEC.
You should
consider each of the following factors as well as the other information in this
Report in evaluating our business. Additional risks and uncertainties
not presently known to us or that we currently consider immaterial may also
impair our business operations. If any of the following risks
actually occur, our business and financial results could be
harmed. You should refer to the other information set forth in this
Report, including our financial statements and the related notes.
Risks
Relating to the Oil and Natural Gas Industry
We
derive all our revenues from companies in the oil and natural gas exploration
and production industry, a historically cyclical industry with levels of
activity that are significantly affected by the levels and volatility of oil and
natural gas prices.
Worldwide
political, economic and military events have contributed to oil and natural gas
price volatility and are likely to continue to do so in the future. Depending on
the market prices of oil and natural gas, oil and natural gas exploration and
production companies may cancel or curtail their drilling programs, thereby
reducing demand for our services. Oil and natural gas prices have been volatile
historically and, we believe, will continue to be so in the future. Many factors
beyond our control affect oil and natural gas prices, including:
|
•
|
the
cost of exploring for, producing and delivering oil and natural
gas;
|
|
•
|
the
discovery rate of new oil and natural gas
reserves;
|
|
•
|
the
rate of decline of existing and new oil and natural gas
reserves;
|
|
•
|
available
pipeline and other oil and natural gas transportation
capacity;
|
|
•
|
the
ability of oil and natural gas companies to raise
capital;
|
|
•
|
actions
by OPEC, the Organization of Petroleum Exporting
Countries;
|
|
•
|
political
instability in the Middle East and other major oil and natural gas
producing
regions;
|
|
•
|
economic
conditions in the United States and
elsewhere;
|
|
•
|
governmental
regulations, both domestic and
foreign;
|
|
•
|
domestic
and foreign tax
policy;
|
|
•
|
weather
conditions in the United States and
elsewhere;
|
|
•
|
the
pace adopted by foreign governments for the exploration, development and
production of their national
reserves;
|
|
•
|
the
price of foreign imports of oil and natural gas;
and
|
|
•
|
the
overall supply and demand for oil and natural
gas.
|
Any prolonged
reduction in the overall level of exploration and development activities,
whether resulting from changes in oil and natural gas prices or otherwise, can
adversely impact us in many ways by negatively affecting:
|
•
|
our
revenues, cash flows and
profitability;
|
|
•
|
our
ability to maintain or increase our borrowing
capacity;
|
|
•
|
our
ability to obtain additional capital to finance our business and make
acquisitions, and the cost of that
capital;
|
|
•
|
our
ability to retain skilled rig personnel whom we would need in the event of
an upturn in the demand for our services;
and
|
|
•
|
the
fair market value of our rig
fleet.
|
As oil and
natural gas prices steeply declined and the credit markets tightened in late
calendar 2008, customers aggressively reduced drilling budgets. This
reduction in demand combined with the reactivation and construction of new land
drilling and workover rigs in the United States during the last several years
has resulted in excess capacity compared to demand. Tightening credit
markets have also reduced our customer’s ability to fund drilling
programs. As a result, we experienced a decline in rig utilization
and average dayrates. We believe that utilization and average
dayrates have stabilized and are now slowly improving. We expect oil
and natural gas prices to continue to be volatile and to affect our financial
condition, operations and ability to access sources of
capital. Continued low market prices for natural gas and economic
conditions that have eroded residential and commercial demand for oil and
natural gas may result in further decreases in demand for our drilling and
workover rigs and adversely affect our operating results.
Risks
Relating to Our Business
Global
economic conditions may adversely affect our operating results.
Oil and
natural gas prices, and market expectations of potential changes in these
prices, significantly impact the level of worldwide drilling and well servicing
activities. Oil and natural gas prices steeply declined and the
credit markets tightened in late calendar 2008. During this time
there was also significant deterioration in the global economic
environment. As part of this deterioration, there has been
significant uncertainty in the capital markets and access to financing has been
reduced. As a result of these conditions, customers reduced their
drilling and well servicing programs, which is resulted in a significant
decrease in demand for our services. We believe that utilization has
stabilized and is now slowly improving. Furthermore, these factors
could result in certain of our customers experiencing an inability to pay
suppliers, including us, if they are not able to access capital to fund their
operations. These conditions could have a material adverse effect on
our business, financial condition, cash flows and results of
operations. The following table depicts the prices for near month
delivery contracts for crude oil and natural gas as traded on the
NYMEX.
|
Natural
Gas Price
|
||||||||||||||||
|
per
Mcf
|
Oil
Price per Bbl
|
|||||||||||||||
|
Quarter
|
High
|
Low
|
High
|
Low
|
||||||||||||
|
2010:
|
||||||||||||||||
|
First
(through March 1, 2010)
|
$ | 6.01 | $ | 4.68 | $ | 83.18 | $ | 71.19 | ||||||||
|
2009:
|
||||||||||||||||
|
Fourth
|
$ | 5.99 | $ | 4.25 | $ | 81.37 | $ | 69.57 | ||||||||
|
Third
|
$ | 4.88 | $ | 2.51 | $ | 74.37 | $ | 59.52 | ||||||||
|
Second
|
$ | 4.45 | $ | 3.25 | $ | 72.68 | $ | 45.88 | ||||||||
|
First
|
$ | 6.07 | $ | 3.63 | $ | 54.34 | $ | 33.98 | ||||||||
|
2008:
|
||||||||||||||||
|
Fourth
|
$ | 7.73 | $ | 5.29 | $ | 98.53 | $ | 33.87 | ||||||||
|
Third
|
$ | 13.58 | $ | 7.22 | $ | 145.29 | $ | 95.71 | ||||||||
|
Second
|
$ | 13.35 | $ | 9.32 | $ | 140.21 | $ | 100.98 | ||||||||
|
First
|
$ | 10.23 | $ | 7.62 | $ | 110.33 | $ | 86.99 | ||||||||
Our
acquisition strategy exposes us to various risks, including those relating to
difficulties in identifying suitable acquisition opportunities and integrating
businesses, assets and personnel, as well as difficulties in obtaining financing
for targeted acquisitions and the potential for increased leverage or debt
service requirements.
As a
component of our business strategy, we have pursued and intend to continue to
pursue selected acquisitions of complementary assets and businesses. In May
2002, we purchased seven drilling rigs, associated spare parts and equipment,
drill pipe, haul trucks and vehicles. In August 2003, we acquired drilling rigs
and inventoried structures and components which, with refurbishment and
upgrades, could be used to assemble 22 drilling rigs. In July 2005, we acquired
three additional rigs and related inventory, equipment, components and a rig
yard. On October 3, 2005, we acquired five operating rigs, seven inventoried
rigs and rig equipment and parts. On October 14, 2005, we acquired nine
operating rigs, two rigs undergoing refurbishment, two inventoried rigs and rig
equipment and parts. On January 18, 2006, we acquired six operating land
drilling rigs and certain other assets, including heavy haul trucks and excess
rig equipment. On January 9, 2007, we acquired 31 workover rigs through our
acquisition of Eagle Well. Acquisitions, including those described
above, involve numerous risks, including:
|
•
|
unanticipated
costs and assumption of liabilities and exposure to unforeseen liabilities
of acquired companies, including but not limited to environmental
liabilities;
|
|
•
|
difficulty
in integrating the operations and assets of the acquired business and the
acquired personnel and distinct
cultures;
|
|
•
|
our
ability to properly access and maintain an effective internal control
environment over an acquired company, in order to comply with public
reporting
requirements;
|
|
•
|
potential
loss of key employees and customers of the acquired
companies;
|
|
•
|
risk
of entering markets in which we have limited prior experience;
and
|
|
•
|
an
increase in our expenses and working capital
requirements.
|
The process
of integrating an acquired business may involve unforeseen costs and delays or
other operational, technical and financial difficulties and may require a
disproportionate amount of management attention and financial and other
resources. Our failure to achieve consolidation savings, to incorporate the
acquired businesses and assets into our existing operations successfully or to
minimize any unforeseen operational difficulties could have a material adverse
effect on our financial condition and results of operations.
In addition,
we may not have sufficient capital resources to complete additional
acquisitions. Historically, we have funded the acquisition of rigs and the
refurbishment of our rig fleet through a combination of debt and equity
financing and cash flows from operations. We may incur substantial additional
indebtedness to finance future acquisitions and also may issue equity, debt or
convertible securities in connection with such acquisitions. Debt service
requirements could represent a significant burden on our results of operations
and financial condition and the issuance of additional equity or convertible
securities could be dilutive to our existing stockholders. Furthermore, we may
not be able to obtain additional financing on satisfactory terms. Even if we
have access to the necessary capital, we may be unable to continue to identify
additional suitable acquisition opportunities, negotiate acceptable terms or
successfully acquire identified targets.
Increases
in the supply of rigs could decrease revenue rates and utilization
rates.
An increase
in the supply of land drilling and workover rigs, whether through new
construction or refurbishment, could decrease revenue rates and utilization
rates, which would adversely affect our revenues and profitability. In addition,
such adverse affect on our revenue and profitability caused by such increased
competition and lower revenue rates and utilization rates could be further
aggravated by any downturn in oil and natural gas prices. There has been a
substantial increase in the supply of land drilling and workover rigs in the
United States over the past five years which has contributed to a broad decline
in revenue rates and utilization industry wide.
Our
indebtedness could restrict our operations and make us more vulnerable to
adverse economic conditions.
As of
December 31, 2009, our total debt was approximately $56.4 million and we
had the ability to incur an additional $8.5 million of debt under our revolving
credit facility (net of outstanding letters of credit of $11.5
million).
Our current
and future indebtedness could have important consequences,
including:
|
•
|
impairing
our ability to make investments and obtain additional financing for
working capital, capital expenditures, acquisitions or other general
corporate
purposes;
|
|
•
|
limiting
our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to make
principal and interest payments on our
indebtedness;
|
|
•
|
making
us more vulnerable to a downturn in our business, our industry or the
economy in general as a substantial portion of our operating cash flow
could be required to make principal and interest payments on our
indebtedness, making it more difficult to react to changes in our business
and in industry and market
conditions;
|
|
•
|
limiting
our ability to obtain additional financing that may be necessary to
operate or expand our
business;
|
|
•
|
putting
us at a competitive disadvantage to competitors that have less
debt; and
|
|
•
|
increasing
our vulnerability to rising interest
rates.
|
We anticipate
that our cash generated by operations and our ability to borrow under the
currently unused portion of our revolving credit facility should allow us to
meet our routine financial obligations for the foreseeable future. However, our
ability to make payments on our indebtedness, and to fund planned capital
expenditures, will depend on our ability to generate cash in the future. This,
to a certain extent, is subject to conditions in the oil and gas industry,
general economic and financial conditions, competition in the markets where we
operate, the impact of legislative and regulatory actions on how we conduct our
business and other factors, all of which are beyond our control. If our business
does not generate sufficient cash flow from operations to service our
outstanding indebtedness, we may have to undertake alternative financing plans,
such as:
|
•
|
refinancing
or restructuring our
debt;
|
|
•
|
selling
assets;
|
|
•
|
reducing
or delaying acquisitions or capital investments, such as refurbishments of
our rigs and related equipment;
or
|
|
•
|
seeking
to raise additional
capital.
|
However, we
may be unable to implement alternative financing plans, if necessary, on
commercially reasonable terms or at all, and any such alternative financing
plans might be insufficient to allow us to meet our debt obligations. If we are
unable to generate sufficient cash flow or are otherwise unable to obtain the
funds required to make principal and interest payments on our indebtedness, or
if we otherwise fail to comply with the various covenants in our revolving
credit facility or other instruments governing any future indebtedness, we could
be in default under the terms of our revolving credit facility or such
instruments. In the event of a default, the lender under our revolving credit
facility, Banco Inbursa S.A. (“Banco Inbursa”), could elect to declare all the
loans made under such facility to be due and payable together with accrued and
unpaid interest and terminate its commitments thereunder and we or one or more
of our subsidiaries could be forced into bankruptcy or liquidation. Any of the
foregoing consequences could materially and adversely affect our business,
financial condition, results of operations and prospects.
Our
revolving credit facility imposes restrictions on us that may affect our ability
to successfully operate our business.
Our revolving
credit facility limits our ability to take various actions, such
as:
|
•
|
limitations
on the incurrence of additional
indebtedness;
|
|
•
|
restrictions
on investments, mergers or consolidations, asset dispositions,
acquisitions, transactions with affiliates and other transactions without
the lender’s consent;
and
|
|
•
|
limitation
on dividends and
distributions.
|
In addition,
our revolving credit facility requires us to maintain certain financial ratios
and to satisfy certain financial conditions, which may require us to reduce our
debt or take some other action in order to comply with them. The failure to
comply with any of these financial conditions, such as financial ratios or
covenants, would cause an event of default under our revolving credit facility.
An event of default, if not waived, could result in acceleration of the
outstanding indebtedness under our revolving credit facility, in which case the
debt would become immediately due and payable. If this occurs, we may not be
able to pay our debt or borrow sufficient funds to refinance it. Even if new
financing is available, it may not be available on terms that are acceptable to
us. These restrictions could also limit our ability to obtain future financings,
make needed capital expenditures, withstand a downturn in our business or the
economy in general, or otherwise conduct necessary corporate activities. We also
may be prevented from taking advantage of business opportunities that arise
because of the limitations imposed on us by the restrictive covenants under our
revolving credit facility.
Our
lender may not grant additional waivers under our revolving credit
facility.
In February
2010, our lender agreed to waive our compliance with the total leverage ratio
covenant contained in our revolving credit facility through the quarter ended
June 30, 2010, and any default or event of default that may occur as a result of
our non-compliance with this covenant through the quarter ended June 30,
2010. If we are unable to comply with this covenant after the waiver
period, or any other covenant or restriction contained in our revolving credit
facility, there can be no assurances that our lender will grant additional
waivers on commercially reasonable terms, if at all.
Carlos
Slim Helú, members of his family and affiliated entities may exercise
significant influence in our affairs and their interests may differ from the
interests of our other stockholders.
According to
a Schedule 13D/A filed with the SEC by Carlos Slim Helú, certain members of
his family and affiliated entities (the “Slim Affiliates”) on March 8,
2010, collectively these individuals and entities owned approximately 15%
of our common stock. Additionally, CICSA (which is also a Slim Affiliate)
holds a warrant to purchase up to 5,440,770 shares of our common stock (the
“Warrant”) that we originally issued in connection with our revolving credit
facility. The Warrant, if exercised by CICSA, would permit the Slim
Affiliates to acquire up to 19.99% of our outstanding common
stock. As a consequence of the significant ownership of our common
stock held by the Slim Affiliates, collectively, they may exercise significant
influence over the outcome of matters involving a vote of our stockholders,
including the election of our directors, a merger or other business combination
or a sale of a substantial amount of our assets.
Banco Inbursa is the
lender under our revolving credit facility, and is currently our largest
creditor. CICSA owns 60% of the equity of Bronco MX, which is a joint
venture in Mexico in which we own the other 40%. Because of the
contractual and business relationships we have with the Slim Affiliates, the
interests of the Slim Affiliates may differ from the interests of our other
stockholders, and the revolving credit facility, the joint venture documentation
relating to Bronco MX and the Warrant contain provisions that may tend to
increase the influence the Slim Affiliates may exercise in our
affairs.
For instance,
the joint venture represents a significant investment by us that will be
controlled by the Slim Affiliates, who, among other things, will be able to
influence the amount and timing of any distributions of cash or property by
Bronco MX to its equity holders, including us. Our revolving credit
facility contains a variety of customary affirmative and negative covenants that
limit our ability to engage in certain actions unless we obtain a waiver or
consent from Banco Inbursa. If we are unable to satisfy our
obligations to make mandatory payments of principal and/or interest under our
revolving credit facility our failure to do so could lead to an event of
default under the revolving credit facility, which would permit Banco Inbursa to
exercise various contractual remedies under the revolving credit facility,
including accelerating the maturity of our obligations and foreclosing upon our
assets securing the revolving credit facility. The Warrant includes a
covenant that restricts our ability to issue shares of common stock (or rights
or warrants or other securities exercisable or convertible into or exchangeable
for shares of common stock) at a consideration per share that is less than 95%
of the market price of our common stock, subject to certain
exceptions. If it became necessary for us to raise capital and we
were unable to sell shares of common stock in a manner that complied with the
Warrant, we would be required to obtain a waiver of this requirement or risk
liability for breach of contract. If we were unable to obtain a waiver, it could
have a material adverse affect on our business, financial condition and results
of operation.
Our
investments in Challenger and Bronco MX are illiquid and may never generate
cash.
There
currently is no readily available market that would facilitate the disposal of
our 25% equity investment in Challenger or our 40% equity investment in Bronco
MX. Furthermore, based on these minority equity positions, we may not
directly receive cash proceeds resulting from the operations of Challenger or
Bronco MX. We cannot assure that the investments will ever yield cash
proceeds, absent a liquidating event or the increase in our equity position
above a threshold that would constitute control.
Our
minority equity investment in Challenger and Bronco MX limits our control of
those companies.
Bronco
representatives hold two of the eight total board seats on the Challenger board
of directors and two of the five total board seats on the Bronco MX board of
managers. We also have various rights as a shareholder of these companies,
including:
|
•
|
preemptive
rights;
|
|
•
|
transfer
rights;
|
|
•
|
tag-along
rights;
|
|
•
|
drag-along
rights;
and
|
|
•
|
certain
voting
rights.
|
Bronco is one
of three shareholder groups in Challenger. Any two of the three
shareholders can effectuate decisions at the board level. Due to our
minority equity interest in Challenger, we cannot accomplish specific objectives
or initiatives if we are unable to align our interest with at least one of the
remaining shareholders. Bronco is one of two shareholder groups in
Bronco MX. Due to our minority equity interest in Bronco MX, we
cannot accomplish specific objectives or initiatives if we are unable to align
our interests with the other shareholder.
International
operations are subject to uncertain political, economic and other risks which
could affect our financial results.
We currently
have a 40% investment in Bronco MX, a company organized under the laws of
Mexico, and a 25% investment in Challenger, an Isle of Man company with its
principal operations in Libya. Risks associated with international
operations and Challenger and Bronco MX’s operations include:
|
•
|
terrorist
acts, war and civil
disturbances;
|
|
•
|
expropriation
or nationalization of
assets;
|
|
•
|
renegotiation
or nullification of existing
contracts;
|
|
•
|
foreign
taxation, including changes in law or interpretation of existing
law;
|
|
•
|
assaults
on property or
personnel;
|
|
•
|
changing
political
conditions;
|
|
•
|
foreign
and domestic monetary policies;
and
|
|
•
|
travel
limitations or operational problems caused by public health
threats.
|
As we expand
our operations outside of the United States, we must comply with numerous laws
and regulations relating to international business operations, including the
Foreign Corrupt Practices Act, or FCPA. The creation and
implementation of international business practices compliance programs is costly
and such programs are difficult to enforce, particularly where reliance on third
parties is required.
The FCPA
prohibits any U.S. individual or business from paying, offering, or authorizing
payment or offering of anything of value, directly or indirectly, to any foreign
official, political party or candidate for the purpose of influencing any act or
decision of the foreign entity in order to assist the individual or business in
obtaining or retaining business. The FCPA also obligates companies whose
securities are listed in the United States to comply with certain accounting
provisions requiring the company to maintain books and records that accurately
and fairly reflect all transactions of the corporation, including international
subsidiaries, and to devise and maintain an adequate system of internal
accounting controls for international operations. The anti-bribery provisions of
the FCPA are enforced primarily by the U.S. Department of Justice. The SEC is
involved with enforcement of the books and records provisions of the
FCPA.
The failure
to comply with laws governing international business practices may result in
substantial penalties, including suspension or debarment from government
contracting. Violation of the FCPA can result in significant civil and criminal
penalties. A failure to satisfy any of our obligations under laws governing
international business practices could have a negative impact on our operations
and harm our reputation. The SEC also may suspend or bar issuers from trading
securities on United States exchanges for violations of the FCPA’s accounting
provisions.
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
The fact that
drilling and workover rigs are mobile and can be moved from one market to
another in response to market conditions heightens the competition in the
industry.
The contracts
we compete for are usually awarded on the basis of competitive bids or direct
negotiations with customers. We believe pricing and quality of equipment are the
primary factors our potential customers consider in determining which service
provider to select. In addition, we believe the following factors are also
important:
|
•
|
the
type and condition of each of the competing drilling and workover
rigs;
|
|
•
|
the
mobility and efficiency of the
rigs;
|
|
•
|
the
quality of service and experience of the rig
crews;
|
|
•
|
the
offering of ancillary services;
and
|
|
•
|
the
ability to provide drilling equipment adaptable to, and personnel familiar
with, new technologies and drilling
techniques.
|
Service
companies compete primarily on a regional basis, and the intensity of
competition may vary significantly from region to region at any particular time.
If demand for our services improves in a region where we operate, our
competitors might respond by moving in suitable rigs from other regions. An
influx of rigs from other regions could rapidly intensify competition and reduce
profitability.
We
face competition from competitors with greater resources that may make it more
difficult for us to compete, which can reduce our revenue rates and utilization
rates.
Some of our
competitors have greater financial, technical and other resources than we do
that may make it more difficult for us to compete, which can reduce our revenue
rates and utilization rates. Their greater capabilities in these areas may
enable them to:
|
•
|
better
withstand industry
downturns;
|
|
•
|
compete
more effectively on the basis of price and
technology;
|
|
•
|
retain
skilled rig personnel;
and
|
|
•
|
build
new rigs or acquire and refurbish existing rigs so as to be able to place
rigs into service more quickly than us in periods of high drilling
demand.
|
In
the event we enter into footage or turnkey contracts, we could be subject to
unexpected cost overruns, which could negatively impact our
profitability.
For the years
ended December 31, 2009, 2008 and 2007, less than 1% of our total revenues
were derived from footage contracts. Under footage contracts, we are paid a
fixed amount for each foot drilled, regardless of the time required or the
problems encountered in drilling the well. We typically pay more of the
out-of-pocket costs associated with footage contracts as compared to daywork
contracts. The risks to us on a footage contract are greater because we assume
most of the risks associated with drilling operations generally assumed by the
operator in a daywork contract, including the risk of blowout, loss of hole,
stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks
associated with subcontractors’ services, supplies, cost escalation and
personnel. The occurrence of uninsured or under-insured losses or operating cost
overruns on our footage jobs could have a negative impact on our profitability.
Similar to our footage contracts, under turnkey contacts drilling companies
assume most of the risks associated with drilling operations that the operator
generally assumes under a daywork contract. Although we historically have not
entered into turnkey contracts, if we were to enter into a turnkey contract or
acquire such a contract in connection with future acquisitions, the occurrence
of uninsured or under-insured losses or operating cost overruns on such a job
could negatively impact our profitability.
Our
operations involve operating hazards, which if not insured or indemnified
against, could adversely affect our results of operations and financial
condition.
Our
operations are subject to the many hazards inherent in the contract land
drilling and well servicing business, including the risks of:
|
•
|
blowouts;
|
|
•
|
fires
and
explosions;
|
|
•
|
loss
of well
control;
|
|
•
|
collapse
of the
borehole;
|
|
•
|
lost
or stuck drill strings;
and
|
|
•
|
damage
or loss from natural
disasters.
|
Any of
these hazards can result in substantial liabilities or losses to us from, among
other things:
|
•
|
suspension
of
operations;
|
|
•
|
damage
to, or destruction of, our property and equipment and that of
others;
|
|
•
|
personal
injury and loss of
life;
|
|
•
|
damage
to producing or potentially productive oil and natural gas formations
through which we drill;
and
|
|
•
|
environmental
damage.
|
We seek to
protect ourselves from some but not all operating hazards through insurance
coverage. However, some risks are either not insurable or insurance is available
only at rates that we consider uneconomical. Depending on competitive conditions
and other factors, we attempt to obtain contractual protection against uninsured
operating risks from our customers. However, customers who provide contractual
indemnification protection may not in all cases maintain adequate insurance to
support their indemnification obligations. Our insurance or indemnification
arrangements may not adequately protect us against liability or loss from all
the hazards of our operations. The occurrence of a significant event that we
have not fully insured or indemnified against or the failure of a customer to
meet its indemnification obligations to us could materially and adversely affect
our results of operations and financial condition. Furthermore, we may be unable
to maintain adequate insurance in the future at rates we consider
reasonable.
We
face increased exposure to operating difficulties because we primarily focus on
drilling for natural gas.
A majority of
our drilling contracts are with exploration and production companies in search
of natural gas. Drilling on land for natural gas generally occurs at deeper
drilling depths than drilling for oil. Although deep-depth drilling exposes us
to risks similar to risks encountered in shallow-depth drilling, the magnitude
of the risk for deep-depth drilling is greater because of the higher costs and
greater complexities involved in drilling deep wells. We generally enter into
International Association of Drilling Contractors contracts that contain
“daywork” indemnification language that transfers responsibility for down hole
exposures such as blowout and fire to the operator, leaving us responsible only
for damage to our rig and our personnel. If we do not adequately insure the risk
from blowouts or if our contractual indemnification rights are insufficient or
unfulfilled, our profitability and other results of operation and our financial
condition could be adversely affected in the event we encounter blowouts or
other significant operating difficulties while drilling at deeper depths. If our
primary focus shifts from drilling for customers in search of natural gas to
drilling for customers in search of oil, a portion of our rig fleet could be
disadvantaged in competing for new oil drilling projects as compared to
competitors that primarily use shallower drilling depth rigs when drilling in
search of oil.
Our
operations are subject to various laws and governmental regulations that could
restrict our future operations and increase our operating costs.
Many aspects
of our operations are subject to various federal, state and local laws and
governmental regulations, including laws and regulations governing:
|
•
|
environmental
quality;
|
|
•
|
pollution
control;
|
|
•
|
remediation
of
contamination;
|
|
•
|
preservation
of natural resources;
and
|
|
•
|
worker
safety.
|
The federal
Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act,
the federal Resource Conservation and Recovery Act, the federal Comprehensive
Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe
Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their
state counterparts and similar statutes are the primary vehicles for imposition
of such requirements and for civil, criminal and administrative penalties and
other sanctions for violation of their requirements. The OSHA hazard
communication standard, the Environmental Protection Agency “community
right-to-know” regulations under Title III of the federal Superfund Amendment
and Reauthorization Act and comparable state statutes require us to organize and
report information about the hazardous materials we use in our operations to
employees, state and local government authorities and local citizens. In
addition, CERCLA, also known as the “Superfund” law, and similar state statutes
impose strict liability, without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered responsible for the
release or threatened release of hazardous substances into the environment.
These persons include the current owner or operator of a facility where a
release has occurred, the owner or operator of a facility at the time a release
occurred, and companies that disposed of or arranged for the disposal of
hazardous substances found at a particular site. This liability may be joint and
several. Such liability, which may be imposed for the conduct of others and for
conditions others have caused, includes the cost of removal and remedial action
as well as damages to natural resources. Few defenses exist to the liability
imposed by environmental laws and regulations. It is also not uncommon for third
parties to file claims for personal injury and property damage caused by
substances released into the environment.
Environmental
laws and regulations are complex and subject to frequent changes. Failure to
comply with governmental requirements or inadequate cooperation with
governmental authorities could subject a responsible party to administrative,
civil or criminal action. We may also be exposed to environmental or other
liabilities originating from businesses and assets that we acquired from others.
We are in substantial compliance with applicable environmental laws and
regulations and, to date, such compliance has not materially affected our
capital expenditures, earnings or competitive position. We do not expect to
incur material capital expenditures in our next fiscal year in order to comply
with current or reasonably anticipated environment control requirements.
However, our compliance with amended, new or more stringent requirements,
stricter interpretations of existing requirements or the future discovery of
regulatory noncompliance or contamination may require us to make material
expenditures or subject us to liabilities that we currently do not
anticipate.
We are aware
of the increasing focus of local, state, national and international regulatory
bodies on GHG emissions and climate change issues. We are also aware of
legislation proposed by United States lawmakers to reduce GHG emissions, as well
as GHG emissions regulations enacted by the U.S. Environmental Protection
Agency. We will continue to monitor and assess any new policies, legislation or
regulations in the areas where we operate to determine the impact of GHG
emissions and climate change on our operations and take appropriate actions,
where necessary. Any direct and indirect costs of meeting these requirements may
adversely affect our business, results of operations and financial
condition.
In addition,
our business depends on the demand for land drilling services from the oil and
natural gas industry and, therefore, is affected by tax, environmental and other
laws relating to the oil and natural gas industry generally, by changes in those
laws and by changes in related administrative regulations. It is possible that
these laws and regulations may in the future add significantly to our operating
costs or those of our customers or otherwise directly or indirectly affect our
operations.
We
rely on a few key employees whose absence or loss could disrupt our operations
resulting in a loss of revenues.
Many key
responsibilities within our business have been assigned to a small number of
employees. The loss of their services could disrupt our operations resulting in
a loss of revenues. Although we have employment agreements with a small number
of our employees, as a practical matter such employment agreements will not
assure the retention of those employees. In addition, we do not maintain “key
person” life insurance policies on any of our employees. As a result, we are not
insured against any losses resulting from the death of our key
employees.
We
may be unable to attract and retain qualified, skilled employees necessary to
operate our business.
Our success
depends in large part on our ability to attract and retain skilled and qualified
personnel. Our inability to hire, train and retain a sufficient number of
qualified employees could impair our ability to manage and maintain our
business. We require skilled employees who can perform physically demanding
work. Shortages of qualified personnel can occur in our industry. As a result of
the volatility of the oil and natural gas industry and the demanding nature of
the work, potential employees may choose to pursue employment in fields that
offer a more desirable work environment at wage rates that are competitive with
ours. If we should suffer any material loss of personnel to competitors or be
unable to employ additional or replacement personnel with the requisite level of
training and experience to adequately operate our equipment, our operations
could be materially and adversely affected. With a reduced pool of workers, it
is possible that we will have to raise wage rates to attract workers from other
fields and to retain our current employees. If we are not able to increase our
service rates to our customers to compensate for wage-rate increases, our
profitability and other results of operations may be adversely affected.
Shortages
in equipment and supplies could limit our operations and jeopardize our
relations with customers.
The materials
and supplies we use in our operations include fuels to operate our drilling
equipment, drilling mud, drill pipe, drill collars, drill bits and cement.
Shortages in drilling equipment and supplies could limit our drilling operations
and jeopardize our relations with customers. We do not rely on a single source
of supply for any of these items. From time to time there have been shortages of
drilling equipment and supplies during periods of high demand which we believe
could reoccur. Shortages could result in increased prices for drilling equipment
or supplies that we may be unable to pass on to customers. In addition, during
periods of shortages, the delivery times for equipment and supplies can be
substantially longer. Any significant delays in our obtaining drilling equipment
or supplies could limit our operations and jeopardize our relations with
customers. In addition, shortages of drilling equipment or supplies could delay
and adversely affect our ability to obtain new contracts for our drilling rigs,
which could negatively impact our revenues and profitability.
If
the price of our common stock fluctuates significantly, your investment could
lose value.
Prior to our
initial public offering in August 2005, there had been no public market for our
common stock. Although our common stock is now quoted on The Nasdaq Global
Select Market, we cannot assure you that an active public market will continue
to exist for our common stock or that our common stock will continue to trade in
the public market at or above current prices. If an active public market for our
common stock does not continue, the trading price and liquidity of our common
stock will be materially and adversely affected. If there is a thin
trading market or “float” for our stock, the market price for our common stock
may fluctuate significantly more than the stock market as a
whole. Without a large float, our common stock is less liquid than
the stock of companies with broader public ownership and, as a result, the
trading price of our common stock may be more volatile. In addition,
in the absence of an active public trading market, investors may be unable to
liquidate their investment in us. In addition, the stock market is
subject to significant price and volume fluctuations, and the price of our
common stock could fluctuate widely in response to several factors,
including:
|
•
|
our
quarterly operating
results;
|
|
•
|
changes
in our earnings
estimates;
|
|
•
|
additions
or departures of key
personnel;
|
|
•
|
changes
in the business, earnings estimates or market perceptions of our
competitors;
|
|
•
|
changes
in general market or economic conditions;
and
|
|
•
|
announcements
of legislative or regulatory
change.
|
The stock
market has experienced extreme price and volume fluctuations in recent years
that have significantly affected the quoted prices of the securities of many
companies, including companies in our industry. The changes often appear to
occur without regard to specific operating performance. The price of our common
stock could fluctuate based upon factors that have little or nothing to do with
our company and these fluctuations could materially reduce our stock
price.
The
market price of our common stock could decline following sales of substantial
amounts of our common stock in the public markets.
If a large
number of shares of our common stock is sold in the open market, the trading
price of our common stock could decrease. As of December 31, 2009, we had
an aggregate of 66,050,899 shares of our common stock authorized but unissued
and not reserved for specific purposes. In general, we may issue all of these
shares without any approval by our stockholders. We may issue shares of our
common stock, or securities convertible into shares of our common stock, to,
among other things, finance the cost of acquisitions, refinance existing
indebtedness, finance capital expenditures and capacity expansion, and/or
generate proceeds for general corporate purposes or working
capital.
We
may issue preferred stock whose terms could adversely affect the voting power or
value of our common stock.
Our
certificate of incorporation authorizes us to issue, without the approval of our
stockholders, one or more classes or series of preferred stock having such
designations, preferences, limitations and relative rights, including
preferences over our common stock respecting dividends and distributions, as our
board of directors may determine. The terms of one or more classes or series of
preferred stock could adversely impact the voting power or value of our common
stock. For example, we might grant holders of preferred stock the right to elect
some number of our directors in all events or on the happening of specified
events or the right to veto specified transactions. Similarly, the repurchase or
redemption rights or liquidation preferences we might assign to holders of
preferred stock could affect the residual value of the common
stock.
Provisions
in our organizational documents could delay or prevent a change in control of
our company, even if that change would be beneficial to our
stockholders.
The existence
of some provisions in our organizational documents could delay or prevent a
change in control of our company, even if that change would be beneficial to our
stockholders. Our certificate of incorporation and bylaws contain provisions
that may make acquiring control of our company difficult,
including:
|
•
|
provisions
regulating the ability of our stockholders to nominate directors for
election or to bring matters for action at annual meetings of our
stockholders;
|
|
•
|
announcements
of legislative or regulatory
change.
|
|
•
|
the
authorization given to our board of directors to issue and set the terms
of preferred stock;
and
|
|
•
|
limitations
on the ability of our stockholders from removing our directors without
cause.
|
We
do not intend to pay cash dividends on our common stock in the foreseeable
future, and therefore only appreciation of the price of our common stock, which
may not occur, will provide a return to our stockholders.
We currently
anticipate that we will retain all future earnings, if any, to finance the
growth and development of our business. We do not intend to pay cash dividends
in the foreseeable future. Any payment of cash dividends will depend upon our
financial condition, capital requirements, earnings and other factors deemed
relevant by our board of directors. In addition, the terms of our credit
facilities prohibit us from paying dividends and making other distributions. As
a result, only appreciation of the price of our common stock, which may not
occur, will provide a return to our stockholders.
None.
Our corporate
headquarters is located at 16217 North May Avenue, Edmond, Oklahoma in an office
building we purchased on January 2, 2007. The approximately 18,100
square foot building was purchased for a total purchase price of $3.0 million,
less an amount equal to one-half of the principal reduction on the seller’s loan
secured by the property between the effective date of the purchase agreement and
the closing. We paid $1.4 million in cash and assumed existing debt of
approximately $1.6 million.
Contract Land
Drilling Segment – Our contract land drilling segment is supported by
several offices and yard facilities located throughout this segment’s areas of
operations, including Oklahoma, Louisiana, Colorado, North Dakota and
Pennsylvania.
Well Servicing
Segment – Our well servicing segment is supported by several offices and
yard facilities located throughout this segment’s areas of operations, including
Oklahoma, Texas, Kansas and New Mexico.
We own our
office and yard in Duncan, Oklahoma and our office and yard in Scenery
Hill, Pennsylvania. We lease the remainder of our facilities, and do not believe
that any one of the leased facilities is individually material to our
operations. We believe that our existing facilities are suitable and adequate to
meet our needs.
Various
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.
|
Market For Registrant’s Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
|
|
|
Market
Information
|
Our common
stock has been quoted under the symbol “BRNC” on The Nasdaq Global Select Market
since January 1, 2009, and on The Nasdaq Global Market from August 16, 2005 to
December 31, 2008. The following table sets forth for the indicated periods the
high and low sale prices of our common stock as quoted on those
markets.
|
Year
Ending December 31, 2008:
|
High | Low | ||||||
|
First
Quarter
|
$ | 16.25 | $ | 11.21 | ||||
|
Second
Quarter
|
$ | 18.69 | $ | 16.04 | ||||
|
Third
Quarter
|
$ | 18.60 | $ | 9.80 | ||||
|
Fourth
Quarter
|
$ | 10.32 | $ | 3.63 | ||||
|
Year
Ending December 31, 2009:
|
||||||||
|
First
Quarter
|
$ | 6.68 | $ | 3.65 | ||||
|
Second
Quarter
|
$ | 6.68 | $ | 4.09 | ||||
|
Third
Quarter
|
$ | 7.54 | $ | 3.34 | ||||
|
Fourth
Quarter
|
$ | 8.64 | $ | 4.60 | ||||
|
Year
ending December 31, 2010:
|
||||||||
|
First
Quarter (through February 28,2010)
|
$ | 6.52 | $ | 4.60 | ||||
On February
26, 2010, the last reported sale price of our common stock on The Nasdaq Global
Select Market was $4.84 and we had approximately 37 holders of record of our
common stock.
Dividend
Policy
We have never
declared or paid dividends on our common stock, and we currently anticipate that
we will retain all future earnings, if any, to finance the growth and
development of our business. We do not intend to pay cash dividends in the
foreseeable future. Any payment of cash dividends will depend upon our financial
condition, capital requirements, earnings and other factors deemed relevant by
our board of directors. In addition, the terms of our credit facility prohibit
us from paying dividends and making other distributions.
Equity
Compensation Plan Information
The following
table provides information as of December 31, 2009 with respect to shares of our
common stock that may be issued under on our equity compensation
plan:
|
|
Number
of securities
|
|||||
|
remaining
available for
|
||||||
|
Number
of securities to be
|
Weighted-average
|
future
issuance under equity
|
||||
|
issued
upon exercise of
|
exercise
price per share
|
compensation
plans
|
||||
|
outstanding
options,
|
of
outstanding options,
|
(excluding
securities
|
||||
|
Plan
category
|
warrants
and rights
|
warrants
and rights
|
reflected
in column (a))
|
|||
|
(a)
|
(b)
|
(c)
|
||||
|
Equity
compensation plans approved
|
||||||
|
by
security holders
|
-
|
$ -
|
1,290,871
|
|||
|
Equity
compensation plans not approved
|
||||||
|
by
security holders
|
-
|
-
|
-
|
|||
|
Total
|
-
|
$ -
|
1,290,871
|
|||
(1) As of
December 31, 2009, we had no options to purchase shares of our common stock
outstanding. As of December 31, 2009, we had issued 549,559 shares of our
restricted stock under the 2006 Plan. The securities remaining available for
future issuance reflect securities that may be issued under the 2006 Plan, as no
more shares remain available for the grant of awards under the 2005
Plan.
The following
table sets forth our selected historical financial data as of and for each of
the years indicated. We derived the selected historical financial data as of and
for each of the years ended 2009, 2008, 2007, 2006 and 2005 from our historical
audited consolidated financial statements. You should review this information
together with “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” and consolidated historical financial statements and
related notes included elsewhere in this Form 10-K.
|
Years
Ended December 31,
|
||||||||||||||||||||
|
(in
thousands, except per share amounts)
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Consolidated
Statements of Operations Information:
|
||||||||||||||||||||
|
Contract
drilling revenues
|
$ |
106,738
|
$ |
247,829
|
$ |
276,088
|
$ |
285,828
|
$ |
77,885
|
||||||||||
|
Well
service
|
3,799
|
33,284
|
22,864
|
-
|
-
|
|||||||||||||||
|
110,537
|
281,113
|
298,952
|
285,828
|
77,885
|
||||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Contract
drilling
|
75,996
|
148,866
|
153,797
|
139,607
|
44,695
|
|||||||||||||||
|
Well
service
|
4,267
|
24,478
|
14,299
|
-
|
-
|
|||||||||||||||
|
Depreciation
and amortization
|
45,674
|
50,388
|
44,241
|
30,335
|
9,143
|
|||||||||||||||
|
General
and administrative
|
19,777
|
33,771
|
22,690
|
15,709
|
9,395
|
|||||||||||||||
|
Impairment
of goodwill
|
-
|
24,328
|
-
|
-
|
-
|
|||||||||||||||
|
Gain
on Challenger transactions
|
-
|
(3,138)
|
-
|
-
|
-
|
|||||||||||||||
|
Loss
on Bronco MX transaction
|
23,705
|
-
|
-
|
-
|
-
|
|||||||||||||||
|
Total
operating costs and expenses
|
169,419
|
278,693
|
235,027
|
185,651
|
63,233
|
|||||||||||||||
|
Income
(loss) from operations
|
(58,882)
|
2,420
|
63,925
|
100,177
|
14,652
|
|||||||||||||||
|
Other
income (expense):
|
||||||||||||||||||||
|
Interest
expense
|
(7,038)
|
(4,171)
|
(4,762)
|
(1,736)
|
(1,415)
|
|||||||||||||||
|
Loss
from early extinguishment of debt
|
(2,859)
|
(155)
|
-
|
(1,000)
|
(2,062)
|
|||||||||||||||
|
Interest
income
|
274
|
1,058
|
1,239
|
164
|
432
|
|||||||||||||||
|
Equity
in income (loss) of Challenger
|
(1,914)
|
2,186
|
-
|
-
|
-
|
|||||||||||||||
|
Equity
in income (loss) of Bronco MX
|
(588)
|
-
|
-
|
-
|
-
|
|||||||||||||||
|
Impairment
of investment in Challenger
|
(21,247)
|
(14,442)
|
-
|
-
|
-
|
|||||||||||||||
|
Other
income (expense)
|
(284)
|
(300)
|
294
|
284
|
53
|
|||||||||||||||
|
Change
in fair value of warrant
|
1,850
|
-
|
|
-
|
|
-
|
|
-
|
||||||||||||
|
Total
other income (expense)
|
(31,806)
|
(15,824)
|
(3,229)
|
(2,288)
|
(2,992)
|
|||||||||||||||
|
Income
(loss) before income taxes
|
(90,688)
|
(13,404)
|
60,696
|
97,889
|
11,660
|
|||||||||||||||
|
Income
tax expense (benefit)
|
(33,109)
|
(5,161)
|
23,104
|
38,056
|
6,529
|
|||||||||||||||
|
Net
income (loss)
|
$ |
(57,579)
|
|
$ |
(8,243)
|
|
$ |
37,592
|
$ |
59,833
|
$ |
5,131
|
||||||||
|
Income
(loss) per common share-Basic
|
$ |
(2.16)
|
|
$ |
(0.31)
|
|
$ |
1.45
|
$ |
2.43
|
$ |
0.32
|
||||||||
|
|
|
|
||||||||||||||||||
|
Income
(loss) per common share-Diluted
|
$ |
(2.16)
|
|
$ |
(0.31)
|
|
$ |
1.44
|
$ |
2.43
|
$ |
0.31
|
||||||||
|
Weighted
average number of shares outstanding-Basic
|
26,651
|
26,293
|
25,996
|
24,585
|
16,259
|
|||||||||||||||
|
Weighted
average number of shares outstanding-Diluted
|
26,651
|
26,293
|
26,101
|
24,623
|
16,306
|
|||||||||||||||
|
Pro
Forma C Corporation Data (Unaudited): (1)
|
||||||||||||||||||||
|
Historical
income
|
|
|
|
|||||||||||||||||
|
before
income taxes
|
|
$ |
11,660
|
|||||||||||||||||
|
Pro
forma provision for income
|
||||||||||||||||||||
|
taxes
|
|
4,396
|
||||||||||||||||||
|
Pro
forma income
|
|
|
|
|
$ |
7,264
|
||||||||||||||
|
Pro
forma income per common share basic and diluted
|
|
|
|
|
$ |
0.45
|
||||||||||||||
|
|
||||||||||||||||||||
|
Weighted
average pro forma shares outstanding-Basic
|
|
16,259
|
||||||||||||||||||
|
Weighted
average pro forma shares outstanding-Diluted
|
|
16,306
|
||||||||||||||||||
|
Other
Financial Data (Unaudited):
|
||||||||||||||||||||
|
Calculation
of Adjusted EBITDA (2):
|
||||||||||||||||||||
|
Net
income (loss)
|
$ |
(57,579)
|
$ |
(8,243)
|
$ |
37,592
|
$ |
59,833
|
$ |
5,131
|
||||||||||
|
Interest
expense
|
7,038
|
4,171
|
4,762
|
1,736
|
1,415
|
|||||||||||||||
|
Income
tax expense (benefit)
|
(33,109)
|
(5,161)
|
23,104
|
38,056
|
6,529
|
|||||||||||||||
|
Depreciation
and amortization
|
45,674
|
50,388
|
44,241
|
30,335
|
9,143
|
|||||||||||||||
|
Impairment
of goodwill
|
-
|
24,328
|
-
|
-
|
-
|
|||||||||||||||
|
Impairment
of investment in Challenger
|
21,247
|
14,442
|
-
|
-
|
-
|
|||||||||||||||
|
Adjusted
EBITDA (2)
|
(16,729)
|
|
79,925
|
|
109,699
|
|
129,960
|
|
22,218
|
|||||||||||
|
Consolidated
Cash Flow Information:
|
||||||||||||||||||||
|
Net
cash provided by (used in):
|
||||||||||||||||||||
|
Operating
activities
|
28,048
|
59,100
|
82,607
|
93,053
|
3,318
|
|||||||||||||||
|
Investing
activities
|
18,194
|
(82,795)
|
(79,984)
|
(143,199)
|
(190,326)
|
|||||||||||||||
|
Financing
activities
|
(63,421)
|
44,650
|
(7,510)
|
43,715
|
202,908
|
|||||||||||||||
|
As
of December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
Consolidated
Balance Sheet Information:
|
||||||||||||||||||||
|
Total
current assets
|
$ |
43,077
|
$ |
107,821
|
$ |
72,019
|
$ |
73,372
|
$ |
53,953
|
||||||||||
|
Total
assets
|
445,583
|
612,354
|
568,605
|
482,488
|
330,520
|
|||||||||||||||
|
Total
debt
|
51,903
|
117,547
|
68,118
|
64,727
|
51,825
|
|||||||||||||||
|
Total
liabilities
|
105,312
|
218,343
|
172,176
|
142,503
|
91,184
|
|||||||||||||||
|
Total
stockholders'/members' equity
|
340,271
|
394,011
|
396,429
|
339,985
|
239,336
|
|||||||||||||||
|
(1)
|
Prior
to the completion of our initial public offering in August 2005, we merged
with Bronco Drilling Company, L.L.C., our predecessor company. Bronco
Drilling Company, L.L.C. was a limited liability company treated as a
partnership for federal income tax purposes. As a result, essentially all
of its taxable earnings and losses were passed through to its members, and
it did not pay federal income taxes at the entity level. Historical income
taxes consist mainly of deferred income taxes on a taxable subsidiary, Elk
Hill. Since we are a C corporation, for comparative purposes we have
included a pro forma provision (benefit) for income taxes assuming we had
been taxed as a C corporation in all periods prior to the
merger.
|
|
(2)
|
Adjusted
EBITDA is a non-GAAP financial measure equal to net income (loss), the
most directly comparable Generally Accepted Accounting Principles, or
GAAP, financial measure, plus interest expense, income tax expense,
depreciation, amortization and impairment. We have presented Adjusted
EBITDA because we use Adjusted EBITDA as an integral part of our internal
reporting to measure our performance and to evaluate the performance of
our senior management. We consider Adjusted EBITDA to be an important
indicator of the operational strength of our business. Adjusted EBITDA
eliminates the uneven effect of considerable amounts of non-cash
depreciation and amortization. Limitations of this measure, however, are
that it does not reflect the periodic costs of certain capitalized
tangible and intangible assets used in generating revenues in our business
or changes in our working capital needs or the significant interest
expense and cash requirements necessary to service our debt. Management
evaluates the costs of tangible and intangible assets through other
financial measures, such as capital expenditures, investment spending and
return on capital. Therefore, we believe that Adjusted EBITDA provides
useful information to our investors regarding our performance and overall
results of operations. Adjusted EBITDA is not intended to be a performance
measure that should be regarded as an alternative to, or more meaningful
than, either net income as an indicator of operating performance or to
cash flows from operating activities as a measure of liquidity. In
addition, Adjusted EBITDA is not intended to represent funds available for
dividends, reinvestment or other discretionary uses, and should not be
considered in isolation or as a substitute for measures of performance
prepared in accordance with GAAP. The Adjusted EBITDA measure presented in
this Form 10-K may not be comparable to similarly titled measures
presented by other companies, and may not be identical to corresponding
measures used in our various
agreements.
|
The following
discussion and analysis should be read in conjunction with the “Selected
Historical Financial Data” and the consolidated financial statements and related
notes included elsewhere in this Form 10-K. This discussion contains
forward-looking statements reflecting our current expectations and estimates and
assumptions concerning events and financial trends that may affect our future
operating results or financial position. Actual results and the timing of events
may differ materially from those contained in these forward-looking statements
due to a number of factors, including those discussed in the sections entitled
“Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements”
appearing elsewhere in this Form 10-K.
Overview
We provide
contract land drilling and workover services to independent oil and gas
exploration and production companies throughout the United States. We commenced
operations in 2001 with the purchase of one stacked 650-horsepower drilling rig
that we reburbished 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 2009. 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 two 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. As of
February 28, 2010, we also owned a fleet of 60 trucks used to transport our
rigs.
We have a 40%
equity investment in Bronco MX, a company organized under the laws of
Mexico. Bronco MX provides contract land drilling services and leases land
drilling rigs to oil and natural gas companies in Mexico. We also
have a 25% equity investment in Challenger Limited, or Challenger, a company
organized under the laws of the Isle of Man. Challenger is an
international provider of contract land drilling and workover services to oil
and natural gas companies with its principal operations in Libya.
Operating
Segments
We currently
conduct our operations through two operating segments: contract land drilling
and well servicing. The following is a description of these two
operating segments. Financial information about our operating
segments is included in Note 9, Business Segments and
Concentrations, of the Notes to Consolidated Financial Statements,
included in Part II, Item 8, Financial Statements and
Supplementary Data, of this Annual Report on Form 10-K.
Contract Land
Drilling – Our contract land drilling segment provides contract land
drilling services. As of February 28, 2010, we owned a fleet of 37
marketed land drilling rigs. We currently operate our drilling rigs
in Oklahoma, Texas, Pennsylvania, West Virginia, North Dakota,
Utah and Louisiana. A majority of the wells we drill for
our customers are drilled in unconventional basins also known as resource
plays. These plays are generally characterized by complex geologic
formations that often require higher horsepower, premium rigs and experienced
crews to reach targeted depths. Our current fleet of 37 marketed drilling rigs
range from 950 to 2,000 horsepower. Accordingly, such rigs can, or in the case
of inventoried rigs upon refurbishment, will be able to, reach the depths
required and have the capability of drilling horizontal and directional 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.
We obtain our
contracts for drilling oil and natural gas wells either through competitive
bidding or through direct negotiations with customers. We typically enter into
drilling contracts that provide for compensation on a daywork basis.
Occasionally, we enter into drilling contracts that provide for compensation on
a footage basis. We have not historically entered into turnkey
contracts; however, we may decide to enter into such contracts in the future. It
is also 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 13 of our drilling rigs operating under term contracts, 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 that we use to evaluate this segment is operating rig
utilization. We compute operating drilling 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 receive a fixed amount of revenue
based on the mobilization rate stated in the contract. We begin earning our
contracted daywork rate and mobilization revenue 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 years
ended December 31, 2009, 2008, and 2007, our drilling rig utilization
rates, revenue days and average number of operating drilling rigs were as
follows:
|
Year
Ended December 31,
|
|||||||
|
2009
|
2008
|
2007
|
|||||
|
Average
number of operating drilling rigs
|
44
|
44
|
51
|
||||
|
Revenue
days
|
5,699
|
12,712
|
14,245
|
||||
|
Utilization
Rates
|
36%
|
79%
|
76%
|
||||
The decrease
in the number of revenue days in 2009 is primarily attributable to the sharp
decrease in oil and natural gas prices beginning in the third quarter of 2008
through 2009 as well as the inability of most customers to obtain financing
related to their drilling programs. Additionally, the average number of rigs
decreased in the third quarter due to the contribution of 9 rigs to Bronco
MX. The decrease in the number of revenue days in 2008 is attributable to the
decrease in the average number of operating rigs due to the rigs contributed and
sold to Challenger. We devote substantial resources to maintaining,
upgrading and expanding our rig fleet. We substantially completed the
refurbishment of three drilling rigs in 2007.
Well Servicing –
Our well servicing segment is capable of providing a broad range of
services to oil and natural gas exploration and prodution companies, including
well maintenance, well workover, new well completion and plugging and
abandonment. We are able to provide maintenance-related services as
part of the normal, periodic upkeep of producing oil and gas wells. Workover and
completion services typically generate more revenue per hour than maintenance
work due to the use of auxiliary equipment, but demand for workover and
completion services tend to be cyclical and highly correlated to the overall
activity level in the industry.
The Company
earns well servicing revenue based on purchase orders, contracts or other
persuasive evidence of an arrangement with the customer, such as a master
service agreement, that include fixed or determinable prices. We
generally charge our customers an hourly rate for these services, which varies
based on a number of considerations including market conditions in each region,
the type of rig and ancillary equipment required, and the necessary
personnel.
Our well
servicing rig fleet has increased from a weighted average number of 24 rigs in
the first quarter of 2007 to 61 in the fourth quarter of 2009 due to newbuild
purchases. We gauge activity levels in our well servicing rig
operations based on rig utilization rate. We compute operating
workover rig utilization rates by dividing revenue hours by total available
hours during a period. Total available hours are the number of hours during the
period that we have owned the operating workover rig based on a 50-hour work
week per rig.For the years ended December 31, 2009, 2008 and 2007, our
workover rig utilization rates, revenue hours and average number of operating
workover rigs were as follows:
|
Year
Ended December 31,
|
|||||||
|
2009
|
2008
|
2007
|
|||||
|
Average
number of operating workover rigs
|
52
|
52
|
33
|
||||
|
Revenue
hours
|
11,386
|
91,591
|
63,746
|
||||
|
Utilization
Rates
|
17%
|
68%
|
78%
|
||||
In June of
2009 management made the decision to temporarily suspend operations in the well
servicing division. Market conditions had sharply deteriorated due to
the rapid decrease in oil and natural gas prices which began in the third
quarter of 2008 as well as the inability of most customers to obtain financing
related to their drilling and workover programs.
Due to the
industry slowdown and subsequent suspension of operations revenue hours were
down 88% for 2009 as compared to 2008. Revenue hours by quarter in
2009 were as follows: Q1 8,012, Q2 3,374, Q3 0 and Q4 0.
Market
Conditions in Our Industry
The United
States contract land drilling and well servicing industry is highly cyclical.
Volatility in oil and natural gas prices can produce wide swings in the levels
of overall drilling and well servicing activity in the markets we serve and
affect the demand for our drilling and workover services and the revenue rates
we can charge for our drilling and workover 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 capital expenditure budgets of
exploration and production companies.
Our business
environment has been adversely affected by the decline in oil and natural gas
prices and the deteriorating global economic environment beginning in the third
quarter of 2008. As part of this deterioration, there has been
significant uncertainty in the capital markets and access to financing has been
reduced. As a result of these conditions, our customers have
curtailed their exploration budgets, which has resulted in a significant
decrease in demand for our services, a reduction in revenue rates and
utilization. During 2009 and 2008, the Company recorded $7.9 million
and $3.6 million of contract drilling revenue related to terminated contracts,
respectively. Due to the current economic environment, certain
customers may not be able to pay suppliers, including us, if they are not able
to access capital to fund their business operations.
On February
28, 2010, the closing prices for near month delivery contracts for crude oil and
natural gas as traded on the NYMEX were $79.66 per barrel and $4.81per MMbtu,
respectively. The Baker Hughes domestic land drilling rig count as of February
28, 2010 was1,313. Baker Hughes is a large oil field services firm
that has issued the rotary rig counts as a service to the petroleum industry
since 1944.
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
December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Crude
oil (Bbl)
|
$ | 79.36 | $ | 44.60 | $ | 95.98 | ||||||
|
Natural
gas (Mmbtu)
|
$ | 5.57 | $ | 5.62 | $ | 7.48 | ||||||
|
U.S.
Land Rig Count
|
1,150 | 1,653 | 1,719 | |||||||||
Increased
expenditures for exploration and production activities generally lead to
increased demand for our services. Until mid-2008, rising oil and
natural gas prices and the corresponding increase in onshore oil and natural gas
exploration and production spending led to expanded drilling and well service
activity as reflected by the increases in the U.S. land rig counts and U.S.
workover rig counts over the previous several years. Falling commodity
prices and the oversupply of rigs, similar to what we have experienced since the
beginning of the third quarter of 2008, generally leads to lower demand for our
services.
The decline
in oil and natural gas prices and the deteriorating global economic environment
resulted in reductions in our rig utilization and revenue rates in
2009. Our near-term strategy is to maintain a strong balance sheet
and ample liquidity. Management has initiated certain cost reduction measures
including workforce and wage rate reductions, optimization of purchasing
processes and the rationalization of real estate, overhead and operating
divisions. These actions should reduce operating expenses during the
current downturn in the industry. Budgeted capital expenditures for 2010
represent a reduction from average historical levels and consists of routine
capital expenditures necessary to maintain our equipment in safe and efficient
working order and discretionary capital expenditures for new equipment or
upgrades of existing equipment in order to make our rigs marketable
to customers in areas identified as strategically important by
management. Management benchmarks each discretionary capital project
against internal required rates of return on capital and/or strategic
objectives.
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—Our contract land drilling segment earns revenues by drilling
oil and natural gas wells for our customers typically under daywork contracts,
which usually provide for the drilling of a single well. We occasionnaly enter
into footage contracts, which also 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. During 2007, we did not experience a loss on the footage jobs we
completed. We had no footage contracts in progress at December 31,
2009 and 2008. When we enter into footage contracts, we are more
likely to encounter losses on them in years in which revenue rates are lower for
all types of contracts.
Revenues and
costs during a reporting period could be affected by jobs in progress at the end
of a reporting period that have not been completed before our financial
statements for that period are released. At December 31, 2009 and 2008, our
unbilled receivables totaled $828,000 and $2.9 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 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 $3.6 million and $3.8 million at December 31, 2009
and 2008, 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 one of our typical contracts, we
would need to rely on applicable law to enforce our lien rights, because our
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
applicable law. If we were unable to drill to the agreed on depth in breach of a
footage contract, we might also need to rely on equitable remedies to recover
the fair value of our work-in-progress under a footage contract.
Asset Impairment and
Depreciation— We evaluate for potential impairment of long-lived assets
and intangible assets subject to amortization when indicators of impairment are
present, as defined in ASC Topic 360, Accounting for the Impairment or
Disposal of Long-Lived Assets. Circumstances that could indicate a
potential impairment include significant adverse changes in industry trends,
economic climate, legal factors, and an adverse action or assessment by a
regulator. More specifically, significant adverse changes in industry trends
include significant declines in revenue rates, utilization rates, oil and
natural gas market prices and industry rig counts for drilling rigs and workover
rigs. In performing an impairment evaluation, we estimate the future
undiscounted net cash flows from the use and eventual disposition of long-lived
assets and intangible assets grouped at the lowest level that cash flows can be
identified. If the sum of the estimated future undiscounted net cash
flows is less than the carrying amount of the long-lived assets and intangible
assets for these asset grouping levels, then we would recognize an impairment
charge. The amount of an impairment charge would be measured as the difference
between the carrying amount and the fair value of these assets. We did not
record an impairment charge on any long-lived assets for our contract land
drilling or well servicing segments for the year ended December 31,
2009. The assumptions used in the impairment evaluation for
long-lived assets and intangible assets are inherently uncertain and require
management judgment.
Goodwill
impairment testing is performed at the level of our reporting units under the
provisions of ASC Topic 350, Goodwill and Other Intangible
Assets. Our reporting units have been determined to be the
same as our operating segments, contract land drilling and well
servicing. In our testing of possible impairment of goodwill, we
compare the fair value of the reporting units with their carrying
value. If the fair value exceeds the carrying value, no impairment is
indicated. If the carrying value exceeds the fair value, we measure
any impairment of goodwill in that reporting unit by allocating the fair value
to the identifiable assets and liabilities of the reporting unit based on their
respective fair values. Any excess un-allocated fair value would
equal the implied fair value of goodwill, and if that amount is below the
carrying value of goodwill, an impairment charge is recognized.
In completing
the first step of the goodwill impairment analysis during the fourth quarter of
2008, management used a five-year projection of discounted cash flows, plus a
terminal value determined using a constant growth method to estimate the fair
value of reporting units. In developing these fair value estimates,
certain key assumptions included an assumed discount rate of 11.0% and 14.0% for
our contract land drilling and well servicing segments, respectively, and an
assumed long-term growth rate of 2.0% for both reporting units.
Based on the
results of the first step of the goodwill impairment test, impairment was
indicated in both reporting units. Management performed the second
step of the analysis of its drilling and well servicing reporting units,
allocating the estimated fair value to the indentifiable tangible and intangible
assets and liabilities of these reporting units based on their respective
values. This allocation indicated no residual value for goodwill, and
accordingly we recorded an impairment charge of $24.3 million in our December
31, 2008 statement of operations. This impairment charge did
not have an impact on our liquidity or debt covenants; however, it was a
reflection of the overall downturn in our industry and decline in our projected
cash flows. The Company has no goodwill after this
impairment.
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 years ended December 31, 2009 and 2008, we capitalized
approximately $0 and $1.3 million, respectively.
We reviewed
our investment in Challenger at September 30, 2009 for impairment based on the
guidance of ASC Topic 323, Investments-Equity Method and Joint
Venture, which states that a loss in value of an investment which is
other than a temporary decline should be recognized. Evidence of a
loss in value might include the absence of an ability to recover the carrying
amount of the investment or inability of the investee to sustain an earnings
capacity which would justify the carrying amount of the investment. A
current fair value of an investment that is less than its carrying amount may
indicate a loss in value of the investment. Due to the recent
volatility and decline in oil and natural gas prices, a deteriorating global
economic environment and the anticipated future earnings of Challenger, we
deemed it necessary to test the investment for impairment.
Fair value of
the investment was estimated using a combination of income, or discounted cash
flows approach and the market approach, which utilizes comparable companies’
data. In developing these fair value estimates, certain key
assumptions included an assumed discount rate of 14.5%, a control premium of
25.0% and a long-term growth rate of 4.0%. The analysis resulted in a
fair value of $39.8 million related to our investment in Challenger, which was
below the carrying value of the investment and resulted in a non-cash impairment
charge in the amount of $21.2 million.
Stock Based
Compensation--- We have adopted ASC Topic 718, Stock Compensation, upon
granting our first stock options on August 16, 2005. ASC Topic 718 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 $3.3 million, $5.8 million and
$3.7 million for 2009, 2008 and 2007, respectively.
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. Deferred tax assets are reduced by a valuation
allowance if, based on available evidence, it is more likely than not that some
portion or all of the deferred tax assets will not be realized.
Equity Method
Investments—Investee companies that are not consolidated, but over which
we exercise significant influence, are accounted for under the equity method of
accounting. Whether or not we exercise significant influence with respect to an
Investee depends on an evaluation of several factors including, among others,
representation on the Investee company’s board of directors and ownership level,
which is generally a 20% to 50% interest in the voting securities of the
Investee company. Under the equity method of accounting, an Investee company’s
accounts are not reflected within our Consolidated Balance Sheets and Statements
of Operations; however, our share of the earnings or losses of the Investee
company is reflected in the captions “Equity in income of Bronco MX” and “Equity
in income of Challenger” in the Consolidated Statements of Operations. Our
carrying value in an equity method Investee company is reflected in the captions
“Investment in Bronco MX” and “Investment in Challenger” in our Consolidated
Balance Sheets.
Other Accounting
Estimates—Our other accrued expenses as of December 31, 2009 and
December 31, 2008 included accruals of approximately $2.5 million and $4.3
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
$11.6 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. 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.
Year
in Review Highlights
The following
are recent highlights that have impacted our results of operations for the year
ended December 31, 2009.
Well
Servicing Segment
In June of
2009 management made the decision to temporarily suspend operations in the well
servicing segment. As previously discussed, market conditions had
sharply deteriorated. The dramatic decline in activity was evident as
revenue hours decreased 87% from a peak of 25,533 hours in the third quarter of
2008 to 3,374 hours in the second quarter of 2009. This represents a utilization
rate of 75% and 10% for the respective quarters. The decrease in
activity was coupled with similar erosions in pricing and margin. As
such, the segment was unable to generate adequate rates of return on capital in
the near future. Because the core drilling business is very capital
intensive and was at the same time experiencing a similar slowdown, management
felt it prudent to temporarily suspend operations in the well service
segment. We intend to strategically refocus this business segment and
deploy assets in the future with a more efficient operational and cost
structure. Currently, Bronco senior management is rebuilding the management
team within Bronco Energy Services. Several candidates have been identified to
lead this division going forward. The plan for potential redeployment includes
new geographic markets, a greater focus on completion services as well as the
exploration of potential expansion into international markets where we feel we
have a competitive advantage.
Bronco
MX Joint Venture
On September
18, 2009, the Company and Saddleback Properties LLC, a wholly-owned subsidiary
of the Company, entered into a Membership Interest Purchase Agreement (the
“Purchase Agreement”) with CICSA, pursuant to which CICSA purchased 60% of the
outstanding membership interests of Bronco MX. The Company owns the
remaining 40% of the outstanding membership interests of Bronco
MX. Immediately prior to the sale of the membership interests in
Bronco MX to CICSA, the Company contributed six drilling rigs (Nos. 4, 43,
53, 58, 60 and 72), and the future net profit from rig leases relating
to three additional drilling rigs (Nos. 55, 76 and 78), which the Company
contributed to Bronco MX upon the expiration of the leases relating to such
rigs.
The Company
received $31.7 million from CICSA in exchange for the 60% membership interest in
Bronco MX. CICSA also reimbursed the Company for 60% of the value
added taxes previously paid by, or on behalf of, Bronco MX as a result
of the importation of six drilling rigs that were contributed by the
Company to Bronco MX to Mexico. The description of the Purchase
Agreement set forth herein is a summary, is not complete and is qualified in its
entirety by reference to the full text of such agreement, which was filed as
exhibit 2.1 to the Company’s Current Report on Form 8-K with the SEC on
September 23, 2009.
Bronco MX is
jointly managed, with CICSA having three representatives on its board of
managers and the Company having two representatives on its board of
managers. The Company and CICSA, and their respective affiliates,
agreed to conduct all future land drilling and workover rig services, rental,
construction, refurbishment, transportation, trucking and mobilization in Mexico
and Latin America exclusively through Bronco MX, subject to Bronco MX’s ability
to perform.
Senior
Secured Revolving Credit Facility with Banco Inbursa
On September
18, 2009, the Company entered into a new senior secured revolving credit
facility with Banco Inbursa, as lender and as the issuing bank. The
Company utilized (i) borrowings under this credit facility, (ii) proceeds from
the sale of the membership interests of Bronco MX and (iii) cash-on-hand to
repay all amounts outstanding under the Company’s prior revolving credit
agreement with Fortis Bank SA/NV, New York Branch, which has been replaced by
this credit facility.
The credit
facility provides for revolving advances of up to $75.0 million and matures
on September 17, 2014. The borrowing base under the credit
facility has been initially set at $75.0 million, subject to borrowing base
limitations. Outstanding borrowings under the credit facility bear
interest at the Eurodollar rate plus 5.80% per annum, subject to adjustment
under certain circumstances.
The Company
will pay a quarterly commitment fee of 0.5% per annum on the unused portion of
the credit facility and a fee of 1.50% for each letter of credit issued under
the facility. In addition, an upfront fee equal to 1.50% of the aggregate
commitments under the credit facility was paid by the Company at closing. The
Company’s domestic subsidiaries guaranteed the loans and other obligations under
the credit facility. The obligations under the credit facility and the related
guarantees are secured by a first priority security interest in substantially
all of the assets of the Company and its domestic subsidiaries, including the
equity interests of the Company’s direct and indirect subsidiaries.
The credit
facility contains customary representations and warranties and various
affirmative and negative covenants, including, but not limited to, covenants
that restrict the Company’s ability to make capital expenditures, incur
indebtedness, incur liens, dispose of property, repay debt, pay dividends,
repurchase shares and make certain acquisitions, and a financial covenant
requiring that the Company maintain a ratio of consolidated debt to consolidated
earnings before interest, taxes, depreciation and amortization for any four
consecutive fiscal quarters of not more than 3.5 to 1.0. On
February 9, 2010, we received a waiver from Banco Inbursa for the ratio of
consolidated debt to consolidated earnings before interest, taxes, depreciation
and amortization through the second quarter of 2010. A violation of
these covenants or any other covenant in the credit facility could result in a
default under the credit facility which would permit the lender to restrict the
Company’s ability to access the credit facility and require the immediate
repayment of any outstanding advances under the credit facility.
Warrant
Issuance
In
conjunction with its entry into the credit facility, the Company entered into a
Warrant Agreement with Banco Inbursa and, pursuant thereto, issued a
three-year warrant (the "Warrant") to Banco Inbursa evidencing the
right to purchase up to 5,440,770 shares of the Company’s common stock,
$0.01 par value per share (the "Common Stock") subject to the terms and
conditions set forth in the Warrant, including the limitations on exercise
set forth below, at an exercise price of $6.50 per share of Common Stock
from the date of issuance of the Warrant (the "Issue Date") through the
first anniversary of the Issue Date, $7.00 per share following the first
anniversary of the Issue Date through the second anniversary of the Issue Date,
and $7.50 per share following the second anniversary of the Issue Date through
the third anniversary of the Issue Date. The Warrant may be exercised by
the payment of the exercise price in cash or through a cashless exercise
whereby the Company withholds shares issuable under the Warrant having a value
equal to the aggregate exercise price.
The exercise
price per share and the number of shares of Common Stock for which the Warrant
may be exercised are subject to adjustment in the event of any split,
subdivision, reclassification, combination or similar transactions affecting the
Common Stock. Additionally, in the event that the Warrant is sold and
the proceeds per share received by the holder are less than the positive
difference of the current market price per share of the Common Stock less the
exercise price then in effect, the Company will be required to pay the seller of
the Warrant a make-whole payment equal to such difference. However, the
obligations of the Company in respect of the make-whole payment only inure to
the benefit of Banco Inbursa and other members of the Investor Group (as defined
in the Warrant), and not other holders of the Warrant.
The Warrant
contains limitations on the number of shares of Common Stock that may be
acquired by the holder of the Warrant upon any exercise of the Warrant.
Pursuant to the terms of the Warrant, the holder of the Warrant may not exercise
the Warrant for a number of shares of Common Stock which will exceed 19.99%
of the shares of the Common Stock that are issued and outstanding on the Issue
Date (subject to adjustment for stock splits, combinations and similar
events). In addition, the number of shares that may be acquired by
the holder of the Warrant and its Affiliates (as defined in the Warrant)
and any other Person (as defined in the Warrant) whose ownership of Common Stock
would be aggregated with the ownership of the holder of the
Warrant for purposes of Section 13(d) of the Securities Exchange Act
of 1934, as amended, does not exceed 19.99% of the total number of shares
of Common Stock that are outstanding immediately after giving effect to
such exercise of the Warrant.
In
conjunction with the issuance of the Warrant, the Company entered into a
Registration Rights Agreement for the benefit of Banco Inbursa and its
permitted assignees and transferees. The Registration Rights
Agreement provides for up to three demand registration rights and unlimited
piggyback registration rights covering the Warrant, the shares of Common Stock
for which the Warrant is exercisable and all other shares of Common Stock held
by Banco Inbursa and its permitted assignees and transferees. The
Registration Rights Agreement provides that the Company shall pay all fees and
expenses incident to the performance of its obligations under the Registration
Rights Agreement, including the payment of all filing, registration and
qualification fees, printers’ and accounting fees, and expenses and
disbursements of counsel and contains other customary terms, provisions and
covenants for agreements of this type, including, without limitation, provisions
requiring the Company to provide indemnification arising out of or relating to
any untrue or alleged untrue statement of a material fact, or relating to any
omission or alleged omission of a material fact required to be stated therein to
make the statements therein not misleading, contained in a registration
statement, prospectus, free writing prospectus or certain other
documents.
The
descriptions of the Credit Facility set forth herein is a summary, is
not complete and is qualified in its entirety by reference to the full text
of such agreements, which was filed as exhibit 10.1 to the Company’s Current
Report on Form 8-K filed with the SEC on September 23, 2009.
Global
Financial Markets
Events, both
within the United States and the world, have brought about significant and
immediate changes in the global financial markets which in turn are affecting
the United States economy, our industry and us. In the United States,
these events and others have had a significant impact on the prices for oil and
natural gas as reflected in the following table:
|
Natural
Gas Price
|
||||||||||||||||
|
per
Mcf
|
Oil
Price per Bbl
|
|||||||||||||||
|
Quarter
|
High
|
Low
|
High
|
Low
|
||||||||||||
|
2010:
|
||||||||||||||||
|
First
(through March 1, 2010)
|
$ | 6.01 | $ | 4.68 | $ | 83.18 | $ | 71.19 | ||||||||
|
2009:
|
||||||||||||||||
|
Fourth
|
$ | 5.99 | $ | 4.25 | $ | 81.37 | $ | 69.57 | ||||||||
|
Third
|
$ | 4.88 | $ | 2.51 | $ | 74.37 | $ | 59.52 | ||||||||
|
Second
|
$ | 4.45 | $ | 3.25 | $ | 72.68 | $ | 45.88 | ||||||||
|
First
|
$ | 6.07 | $ | 3.63 | $ | 54.34 | $ | 33.98 | ||||||||
|
2008:
|
||||||||||||||||
|
Fourth
|
$ | 7.73 | $ | 5.29 | $ | 98.53 | $ | 33.87 | ||||||||
|
Third
|
$ | 13.58 | $ | 7.22 | $ | 145.29 | $ | 95.71 | ||||||||
|
Second
|
$ | 13.35 | $ | 9.32 | $ | 140.21 | $ | 100.98 | ||||||||
|
First
|
$ | 10.23 | $ | 7.62 | $ | 110.33 | $ | 86.99 | ||||||||
As noted in
the table, oil and natural gas prices declined significantly in late calendar
2008 and there was a deteriorating national and global economic
environment. During 2009, the economic recession, including the
decline in oil and natural gas prices and deterioration in the credit markets,
had a significant effect on customer spending and drilling
activity. When drilling activity and spending decline for any
sustained period of time our dayrates and utilization rates also tend to
decline. In addition, lower commodity prices for any sustained period
of time could impact the liquidity condition of some of our customers, which, in
turn, might limit their ability to meet their financial obligations to
us.
The impact on
our business and financial results as a consequence of the volatility in oil and
natural gas prices and the global economic crisis is uncertain in the long term,
but in the short term, it has had a number of consequences for us, including the
following:
|
•
|
In
December 2008, we incurred goodwill impairment of our contract land
drilling and well servicing segments of $24.3 million due to the fair
value of the segments being less than their carrying
value;
|
|
•
|
In June
2009, we temporarily suspended operations in our well servicing
segment;
|
|
•
|
In
September 2009, we incurred an impairment charge to our investment in
Challenger of $21.2 million due to the fair value of the investment being
less than its carrying
value;
|
|
•
|
Due
to declining commodity prices of oil and natural gas, several of our
customers have significantly reduced their drilling budgets for 2010,
resulting in a significant reduction in the average utilization of our
drilling and workover rig fleet. Our average utilization was
approximately 36% for 2009 and 79% for
2008.
|
Results
of Operations
Year
Ended December 31, 2009 Compared to Year Ended December 31,
2008
Contract Drilling
Revenue. For the year ended December 31, 2009, we reported contract
drilling revenues of approximately $106.7 million, a 57% decrease from revenues
of $247.8 million for 2008. The decrease is primarily due to a decrease in total
revenue days and a decrease in average dayrates. Revenue days decreased 55% to
5,699 days for the year ended December 31, 2009 from 12,712 days during
2008. Average dayrates for our drilling services decreased
$1,565, or 9%, to $16,072 for the year ended December 31, 2009 from $17,637
in 2008. The decrease in the number of revenue days for the year ended
December 31, 2009 as compared to 2008 is attributable to the decrease in
our utilization rate. Utilization decreased to 36% from 79% for the year ended
December 31, 2009 as compared to 2008. The 54% decrease in
utilization was primarily due to decrease in demand for our services related to
a decline in drilling activity as a result of lower oil and natural gas prices
and a more competitive market resulting from an increase in the supply of
drilling rigs. For the year ended December 31, 2009, the Company recorded $7.9
million of contract drilling revenue related to terminated contracts compared to
$3.6 million for 2008.
Well Service
Revenue. For the year ended December 31, 2009, we
reported well service revenues of approximately $3.8 million, an 89% decrease
from revenues of $33.3 million for 2008. The decrease is primarily
due to a decrease in total revenue hours and a decrease in the average hourly
rate. Revenue hours decreased 88% to 11,386 for the year ended
December 31, 2009 from 91,591 during 2008. The average hourly rate
decreased $29, or 8%, to $334 for the year ended December 31, 2009 from $363
during 2008. We temporarily suspended operations of our workover
segment in June of 2009.
Equity in Income
(Loss) of Challenger. Our equity in the loss of Challenger was
$1.9 million for the year ended December 31, 2009 compared to Equity in income
of $2.2 million for the year ended December 31, 2008. The equity in
income (loss) of Challenger represents our 25% share of Challenger’s income
(loss) for 2009 and 2008. For the year ended December 31, 2009,
Challenger had operating revenues of $56.5 million and operating costs of $47.6
million. For the year ended December 31, 2008, Challenger had
operating revenues of $71.8 million and operating costs of $38.5
million. We reviewed our investment in Challenger at September 30,
2009 for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint
Venture, which states that a loss in value of an investment which is
other than temporary decline should be recognized. Evidence of a loss in value
might include the absence of an ability to recover the carrying amount of the
investment or inability of the investee to sustain an earnings capacity which
would justify the carrying amount of the investment. A current fair value of an
investment that is less than its carrying amount may indicate a loss in value of
the investment. Due to the recent volatility and decline in oil and natural gas
prices, a deteriorating global economic environment and the anticipated future
earnings of Challenger, we deemed it necessary to test the investment for
impairment. Fair value of the investment was estimated using a combination of
income, or discounted cash flows approach, and the market approach, which
utilizes comparable companies’ data. The analysis resulted in a fair value of
$39.8 million for our investment in Challenger, which was below the carrying
value of the investment and resulted in a non-cash impairment charge in the
amount of $21.2 million.
Equity in Income
(Loss) of Bronco MX. Equity in loss of Bronco MX was $588 for
the period September 18 through December 31, 2009. The equity in loss
of Bronco MX represents our 40% share of Bronco MX’s loss for
2009. For the period September 18, 2009 through December 31, 2009,
Bronco MX had operating revenues of $7.2 million and operating costs of $9.2
million.
Contract Drilling
Expense. Contract drilling expense decreased $72.9 million to $76.0
million for the year ended December 31, 2009 from $148.9 million in 2008.
This 49% decrease is primarily due to the decrease in the number of revenue days
from 12,712 for the year ended December 31, 2008 to 5,699 for
2009. As a percentage of contract drilling revenue, drilling expense
increased to 71% for the year ended December 31, 2009 from 60% in 2008 due
primarily to fixed costs on idle drilling rigs.
Well Service
Expense. For the year ended December 31, 2009, we reported well
service expense of approximately $4.3 million, an 82% decrease from expense of
$24.5 million for 2008. The decrease is primarily due to a decrease
in total revenue hours. Revenue hours decreased 88% to 11,386 for the
year ended December 31, 2009 from 91,591 during 2008. As a percentage
of well service revenue, expenses increased to 112% for the year ended December
31, 2009 from 74% in 2008. We temporarily suspended operations of our workover
segment in June of 2009.
Depreciation and
Amortization Expense. Depreciation and amortization expense decreased
$4.7 million to $45.7 million for the year ended December 31, 2009 from
$50.4 million in 2008. The decrease is due to the contribution
of nine drilling rigs to Bronco MX in the third quarter of 2009.
General and
Administrative Expense. General and administrative expense decreased
$14.0 million, or 41%, to $19.8 million for the year ended December 31,
2009 from $33.8 million in 2008. This primarily resulted from a $4.5 million
termination fee paid in 2008 related to our terminated merger with
Allis-Chalmers Energy, Inc. The remainder of the decrease is due to a
$2.5 million decrease in stock compensation expense, a $1.8 million decrease in
payroll costs, a $1.6 million decrease in accounts receivable write-offs, a $1.3
million decrease in yard expense, and a $997,000 decrease in professional
fees. The decrease in stock compensation expense is primarily due to
stock grants with higher grant date fair values becoming fully
amortized. The other decreases are due to the overall decrease in
activity for the company in the current year.
Interest
Expense. Interest expense increased $2.8 million to $7.0 million for the
year ended December 31, 2009 from $4.2 million in 2008. The increase is due
to a decrease in the capitalization of interest expense related to our rig
refurbishment program and an increase in the average outstanding balance under
our credit facilities. We did not capitalize any interest in 2009 compared to
$1.3 million of interest for the year ended December 31, 2008.
Income Tax
Expense. We recorded an income tax benefit of $33.1 million for the year
ended December 31, 2009. This compares to an income tax benefit of $5.2
million in 2008. This increase is primarily due to a $77.3 million increase in
pre-tax loss to $90.7 million for the year ended December 31, 2009 from $13.4
million in 2008.
Year
Ended December 31, 2008 Compared to Year Ended December 31,
2007
Contract Drilling
Revenue. For the year ended December 31, 2008, we reported contract
drilling revenues of approximately $247.8 million, a 10% decrease from revenues
of $276.1 million for 2007. The decrease is primarily due to decreases in total
revenue days, average operating rigs, and average dayrates for the year ended
December 31, 2008 as compared to 2007. Revenue days decreased 11% to 12,712
days for the year ended December 31, 2008 from 14,245 days during
2007. Our average number of operating drilling rigs decreased
to 44 from 51, or 14%, for the year ended December 31, 2008, as compared to
2007. Average dayrates for our drilling services decreased $239, or
1%, to $17,637 for the year ended December 31, 2008 from $17,876 in 2007.
The decrease in the number of revenue days for the year ended December 31,
2008 as compared to 2007 is attributable to the decrease in the size of our
drilling fleet due to the contribution and sale of 10 rigs to Challenger during
2008. During the fourth quarter of 2008, the Company recorded $3.6
million of contract drilling revenue related to terminated
contracts.
Well Service
Revenue. For the year ended December 31, 2008, we
reported well service revenues of approximately $33.3 million, a 46% increase
from revenues of $22.9 million for 2007. This increase is primarily
due to an increase in revenue hours and average revenue per hour for the year
ended December 31, 2008 as compared to 2007. Revenue hours increased
44% to 91,591 hours for the year ended December 31, 2008 from 63,746 for
2007. Our average revenue per hour increased 1% to $363 from $359,
for the year ended December 31, 2008 as compared to 2007. The
increase in revenue hours and the size of our operating workover rig fleet is
due to additional workover rigs purchased during 2008 and 2007.
Equity in Income of
Challenger. Equity in income of Challenger was $2.2 million
for the year ended December 31, 2008. The equity in income of
Challenger represents our 25% share of Challenger’s income for
2008. For the year ended December 31, 2008, Challenger had operating
revenues of $71.8 million and operating costs of $38.5 million.
Contract Drilling
Expense. Contract drilling expense decreased $4.9 million to $148.9
million for the year ended December 31, 2008 from $153.8 million in 2007.
This 3% decrease is primarily due to the decrease in the average number of
operating drilling rigs in our fleet to 44 for the year ended December 31,
2008 as compared to 51 in 2007. As a percentage of contract drilling revenue,
drilling expense increased to 60% for the year ended December 31, 2008 from
56% in 2007 due primarily to a wage increase for field personnel and general
increase in the cost of supplies and materials.
Well Service
Expense. Well service expense increased $10.2 million to $24.5 million
for the year ended December 31, 2008 from $14.3 million for the same period in
2007. This 71% increase is primarily due to the increase in revenue
hours and the average hourly operating expense for the year ended December 31,
2008 as compared to the same period in 2007.
Depreciation and
Amortization Expense. Depreciation and amortization expense increased
$6.2 million to $50.4 million for the year ended December 31, 2008 from
$44.2 million in 2007. This increase is primarily due to the 1%
increase in fixed assets and an entry to credit depreciation expense in the
third quarter of 2007 for $2.1 million related to a change in the depreciable
life of certain rig components that moved between working rigs and the
yard.
General and
Administrative Expense. General and administrative expense increased
$11.1 million, or 50%, to $33.8 million for the year ended December 31,
2008 from $22.7 million in 2007. This increase is primarily attributed to the
termination fee of $4.5 million paid to Allis-Chalmers Energy, Inc. upon
termination of the proposed merger. Professional fees increased $1.4
million and consulting fees expense increased $749,000 primarily due to the
terminated merger. The remaining increase is due to an increase in
administrative salaries of $2.2 million and stock compensation expense of $2.1
million. The increases in administrative salaries and stock
compensation expense are partially due to the grant of additional shares of
restricted stock in 2008 and due to the termination of our employment agreement
with Larry Bartlett, our former Senior Vice President of Rig Operations, during
the third quarter of 2008.
Impairments. In
connection with our annual goodwill impairment assessment performed as of
December 31, 2008, we performed an impairment test of our contract drilling and
well servicing reporting units under the provisions of ASC Topic 350, Goodwill and Other Intangible
Assets. Based on the results of the first step on the
impairment test, impairment was indicated in both reporting
units. Management performed the second step of the analysis of our
drilling and well servicing reporting units, allocating the estimated fair value
to the identifiable tangible and intangible assets and liabilities of these
reporting units based on their respective values. This allocation
indicated no residual value for goodwill, and accordingly we recorded an
impairment charge of $24.3 million in our December 31, 2008 statement of
operations. This impairment charge is not expected to have an
impact on our liquidity or debt covenants; however, it is a reflection of the
overall downturn in our industry and decline in our projected cash
flows.
We reviewed
our investment in Challenger at December 31, 2008 for impairment based on the
guidance of ASC Topic 323, Investments-Equity Method and Joint
Venture, which states that a loss in value of an investment which is
other than a temporary decline should be recognized. Fair value of
the investment was estimated using a combination of income, or discounted cash
flows approach and the market approach, which utilizes comparable companies’
data. The analysis resulted in a fair value of $62.9 million related
to our investment in Challenger, which was below the carrying value of the
investment and resulted in a non-cash impairment charge in the amount of $14.4
million.
Interest
Expense. Interest expense decreased $591,000 to $4.2 million for the year
ended December 31, 2008 from $4.8 million in 2007. The decrease is due to
the waiver of interest in the amount of $1.0 million related to our use tax
liability recorded in 2007 and a decrease in the average interest rate on our
revolving credit facility partially offset by a higher outstanding balance on
our revolving credit facility and a decrease in the capitalization of interest
expense related to our rig refurbishment program. We capitalized $1.3 million of
interest for the year ended December 31, 2008 as compared to $1.7 million for
the same period in 2007 as part of our rig refurbishment program.
Income Tax
Expense. We recorded an income tax benefit of $5.2 million for the year
ended December 31, 2008. This compares to an income tax expense of $23.1
million in 2007. This decrease is primarily due to a $74.1 million decrease in
pre-tax income to a pre-tax loss of $13.4 million for the year ended December
31, 2008 from pre-tax income of $60.7 million in 2007.
Liquidity
and Capital Resources
Operating
Activities. Net
cash provided by operating activities was $28.1 million for 2009, $59.1 million
in 2008 and $82.6 million in 2007. The decrease of $31.0 million from 2008 to
2009 and $23.5 million from 2007 to 2008 was primarily due to a decrease in cash
receipts from customers and higher cash payments to employees and
suppliers.
Investing
Activities. We
use a significant portion of our cash flows from operations and financing
activities for acquisitions and for the refurbishment of our rigs. Net cash
provided by investing activities was $18.2 million for 2009 compared to cash
used of $82.8 million for 2008 and $80.0 million for 2007. In 2009,
we received $31.7 million from the sale of 60% of the outstanding membership
interests in Bronco MX, proceeds of $953,000 from the sale of assets and
principal payments on note receivable of $3.1 million, partially offset by $17.6
million used to purchase property and equipment. In 2008,
approximately $5.1 million was used to obtain a 25% interest in Challenger,
$87.3 million was used to purchase property and equipment, which amounts were
partially offset by $6.6 million received from the sale of assets and $2.9
million received from a restricted cash account. In 2007,
approximately $2.4 million was used for an acquisition made during 2007 and
$82.8 million was used to purchase property and equipment, which amounts were
partially offset by $5.1 million received from the sale of assets.
Financing
Activities. We
used cash for financing activities of $63.4 million for 2009 as compared to cash
provided of $44.7 million for 2008 and $7.5 million used in financing activities
for 2007. Our net cash used for financing activities for 2009 related
to us repaying in full our revolving credit facility with Fortis Bank SA/NV on
September 18, 2009 in the amount of $111.1 million, $5.1 million paid to various
lenders and debt issue costs of $2.2 million, partially offset by borrowings of
$55.0 million under our revolving credit facility with Banco
Inbursa. Our net cash provided by financing for 2008 related to
borrowings of $51.1 million under our credit facility with Fortis, partially
offset by $2.9 million paid to other finance companies and $3.5 million in debt
issuance costs. Our net cash used for financing activities for 2007
related to principal payments on borrowings of $17.0 million to Fortis, $5.5
million to Bank of Beaver City and $2.0 million to other finance companies,
partially offset by borrowings of $17.0 million under our credit agreement with
Fortis.
Sources of
Liquidity. Our
primary sources of liquidity are cash from operations and borrowings under our
credit facilities and equity financing.
Debt
Financing. On September 18, 2009, we entered into a new senior
secured revolving credit facility (the “Credit Facility”) with Banco Inbursa, as
lender and as the issuing bank (“Banco Inbursa”). We utilized (i)
borrowings under the Credit Facility, (ii) proceeds from the sale of the
membership interests of Bronco MX, and (iii) cash-on-hand to repay all amounts
outstanding under our prior revolving credit agreement with Fortis Bank SA/NV,
which has been replaced by the Credit Facility.
The Credit
Facility provides for revolving advances of up to $75.0 million and matures
on September 17, 2014. The borrowing base under the Credit
Facility has been initially set at $75.0 million, subject to borrowing base
limitations. Outstanding borrowings under the Credit Facility bear
interest at the Eurodollar rate plus 5.80% per annum, subject to adjustment
under certain circumstances.
We will pay a
quarterly commitment fee of 0.5% per annum on the unused portion of the Credit
Facility and a fee of 1.50% for each letter of credit issued under the facility.
In addition, an upfront fee equal to 1.50% of the aggregate commitments under
the Credit Facility was paid by us at closing. Our domestic subsidiaries have
guaranteed the loans and other obligations under the Credit Facility. The
obligations under the Credit Facility and the related guarantees are secured by
a first priority security interest in substantially all of our assets and our
domestic subsidiaries, including the equity interests of our direct and indirect
subsidiaries.
The Credit
Facility contains customary representations and warranties and various
affirmative and negative covenants, including, but not limited to, 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, and a financial covenant requiring that we
maintain a ratio of consolidated debt to consolidated earnings before interest,
taxes, depreciation and amortization for any four consecutive fiscal quarters of
not more than 3.5 to 1.0. On February 9, 2010, the Company
received a waiver from Banco Inbursa for the ratio of consolidated debt to
consolidated earnings before interest, taxes, depreciation and amortization
through the second quarter of 2010. A violation of these covenants or any other
covenant in the Credit Facility could result in a default under the Credit
Facility which would permit the lender to restrict our ability to access the
Credit Facility and require the immediate repayment of any outstanding advances
under the Credit Facility. The Credit Facility also provides for mandatory
prepayments in certain circumstances.
In
conjunction with our entry into the Credit Facility, we entered into a Warrant
Agreement, pursuant to which we, issued a three-year warrant (the “Warrant”)
to Banco Inbursa evidencing the right to purchase up to 5,440,770
shares of our common stock, $0.01 par value per share (the “Common Stock”),
subject to the terms and conditions set forth in the Warrant, including
the limitations on exercise set forth below, at an exercise price of
$6.50 per share of Common Stock from the date of issuance of the Warrant
(the "Issue Date") through the first anniversary of the Issue Date, $7.00
per share following the first anniversary of the Issue Date through the second
anniversary of the Issue Date, and $7.50 per share following the second
anniversary of the Issue Date through the third anniversary of the Issue Date.
The Warrant may be exercised by the payment of the exercise price in
cash or through a cashless exercise whereby we withhold shares issuable
under the Warrant having a value equal to the aggregate exercise
price.
The exercise
price per share and the number of shares of Common Stock for which the Warrant
may be exercised are subject to adjustment in the event of any split,
subdivision, reclassification, combination or similar transactions affecting the
Common Stock. Additionally, in the event that the Warrant is sold and
the proceeds per share received by the holder are less than the positive
difference of the current market price per share of the Common Stock less the
exercise price then in effect, we will be required to pay the seller of the
Warrant a make-whole payment equal to such difference. However, our
obligations in respect of the make-whole payment only inure to the benefit of
Banco Inbursa and other members of the Investor Group (as defined in the
Warrant), and not other holders of the Warrant.
The Warrant
contains limitations on the number of shares of Common Stock that may be
acquired by the holder of the Warrant upon any exercise of the Warrant.
Pursuant to the terms of the Warrant, the holder of the Warrant may not exercise
the Warrant for a number of shares of Common Stock which will exceed 19.99%
of the shares of the Common Stock that are issued and outstanding on the Issue
Date (subject to adjustment for stock splits, combinations and similar
events). In addition, the number of shares that may be acquired by
the holder of the Warrant and its Affiliates (as defined in the Warrant)
and any other Person (as defined in the Warrant) whose ownership of Common Stock
would be aggregated with the ownership of the holder of the
Warrant for purposes of Section 13(d) of the Securities Exchange Act
of 1934, as amended, does not exceed 19.99% of the total number of shares
of Common Stock that are outstanding immediately after giving effect to
such exercise of the Warrant.
In accordance
with accounting standards, the proceeds from the revolving credit facility were
allocated to the credit facility and Warrant based on their respective fair
values. Based on this allocation, $50.3 million and $4.7 million of
the net proceeds were allocated to the credit facility and Warrant,
respectively. The Warrant has been classified as a liability on the
consolidated balance sheet due to our obligation to pay the seller of the
Warrant a make-whole payment, in cash, under certain
circumstances. The fair value of the Warrant was determined using a
pricing model based on a version of the Black Scholes model, which is adjusted
to account for the dilution resulting from the additional shares issued for the
Warrant. The valuation was determined by computing the value of the
Warrant if exercised in Year 1 – 3 with the values weighted by the probability
that the Warrant would actually be exercised in that year. Some of
the assumptions used in the model were a volatility of 45% and a risk free
interest rate that ranged from 0.41% to 1.57%.
The resulting
discount to the revolving credit facility will be amortized to interest expense
over the term of the revolving credit facility such that, in the absence of any
conversions, the carrying value of the revolving credit facility at maturity
would be equal to $55.0 million. Accordingly, we will recognize
annual interest expense on the debt at an effective interest rate of Eurodollar
rate plus 6.25%.
In accordance
with accounting standards, we revalued the Warrant as of December 31, 2009 and
recorded the change in the fair value of the Warrant on the consolidated
statement of operations. The fair value of the Warrant was determined
using a pricing model based on a version of the Black Scholes model, which is
adjusted to account for the dilution resulting from the additional shares issued
for the Warrant. The valuation was determined by computing the value
of the Warrant if exercised in Year 1 – 3 with the values weighted by the
probability that the warrant would actually be exercised in that
year. Some of the assumptions used in the model were a volatility of
45% and a risk free interest rate that ranged from 0.40% to
1.45%. The fair value of the Warrant was $2.8 million at December 31,
2009. We recorded a change in the fair value of the Warrant on the
consolidated statement of operations in the amount of $1.9 million for the year
ended December 31, 2009.
In
conjunction with the issuance of the Warrant, we entered into a Registration
Rights Agreement for the benefit of Banco Inbursa and its permitted
assignees and transferees. The Registration Rights Agreement provides
for up to three demand registration rights and unlimited piggyback registration
rights covering the Warrant, the shares of Common Stock for which the Warrant is
exercisable and all other shares of Common Stock held by Banco Inbursa and its
permitted assignees and transferees. The Registration Rights
Agreement provides that we shall pay all fees and expenses incident to the
performance of our obligations under the Registration Rights Agreement,
including the payment of all filing, registration and qualification fees,
printers’ and accounting fees, and expenses and disbursements of counsel and
contains other customary terms, provisions and covenants for agreements of this
type, including, without limitation, provisions requiring us to provide
indemnification arising out of or relating to any untrue or alleged untrue
statement of a material fact, or relating to any omission or alleged omission of
a material fact required to be stated therein to make the statements therein not
misleading, contained in a registration statement, prospectus, free writing
prospectus or certain other documents.
The
description of the Credit Facility, set forth herein is a summary, is
not complete and is qualified in its entirety by reference to the full text
of such agreements, which were filed as exhibit 10.1 to the Company’s Current
Report on Form 8-K filed with the SEC on September 23,
2009.
On January
13, 2006, we entered into our prior $150.0 million revolving credit facility
with Fortis Capital Corp., as administrative agent, lead arranger and sole book
runner, and a syndicate of lenders. On September 29, 2008, we amended
and restated this revolving credit facility. This $150.0 million
amended and restated credit facility was with Fortis Bank SA/NV, New York
Branch, as administrative agent, joint lead arranger and sole bookrunner, and a
syndicate of lenders, which included The Royal Bank of Scotland plc, The CIT
Group/Business Credit, Inc., The Prudential Insurance Company of America, Legacy
Bank, Natixis and Caterpillar Financial Services Corporation. Loans
under the revolving credit facility bore interest at LIBOR plus a 4.0% margin
or, at our option, the prime rate plus a 3.0% margin. We
incurred $3.5 million in debt issue costs related to the amended and restated
credit facility.
The revolving
credit facility provided 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 years ended
December 31, 2009 and 2008 were $447,000 and $406,000,
respectively.
The revolving
credit facility was repaid in full on September 18, 2009. We incurred
a loss from early extinguishment of debt of approximately $2.9
million.
At December
31, 2008 we were 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 2015 and have a weighted average annual
interest rate of 6.93%. The proceeds from these term loans were used to purchase
cranes. These loans were paid in full in March of 2009.
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 Eagle Well Service, Inc. in January 2007, we issued
1,070,390 shares of our common stock. See “—Capital Expenditures”
below. In conjunction with our entry into our senior
secured revolving credit facility with Banco Inbursa, we issued a three-year
warrant (the “Warrant”) to Banco Inbursa evidencing the right to
purchase up to 5,440,770 shares of our common stock, $0.01 par value per
share (the “Common Stock”), subject to the terms and conditions set forth in the
Warrant. Banco Inbursa subsequently transferred the Warrant to
CICSA. Pursuant to the terms of the Warrant, we cancelled the Warrant
issued to Banco Inbursa and issued a warrant containing the same terms and
provisions to CICSA evidencing such transfer.
Capital
Expenditures.
During 2009,
we incurred aggregate refurbishment costs of $13.4 million related to
enhancements and refurbishments of rigs related to international expansion in
Mexico and new opportunities domestically and incurred $2.7 million for the
purchase of top drives to upgrade our rig fleet. We also incurred $859,000 in
costs related to the refurbishment of workover rigs.
During 2008,
we incurred aggregate refurbishment costs of $54.4 million related to newbuilds,
enhancements and refurbishments of rigs related to international expansion in
Libya and Mexico and new plays domestically. We also incurred $5.1
million in costs related to the purchase and refurbishment of workover
rigs.
During 2007
we substantially completed the refurbishment of three rigs, ranging from 1,200
to 1,500 horsepower. We incurred aggregate refurbishment costs of $23.5 million,
ranging from $7.0 million to $8.5 million per rig, which were funded with
borrowings under our revolving credit facility with Fortis Capital Corp. and
cash flow from operations.
On January 2,
2007, we purchased an approximately 18,100 square foot building located in
Edmond, Oklahoma for cash of $1.4 million and the assumption of existing debt of
approximately $1.6 million, less one-half of the principal reduction on the
sellers’ loan secured by the property between the effective date and
closing. Prior to closing on the building we subleased a total of
9,050 square feet of the building from its current tenants for a monthly rental
of $8,341.
On January 9,
2007, we completed the acquisition of 31workover rigs, 24 of which were
operating, from Eagle Well and related subsidiaries for $2.6 million in cash,
1,070,390 shares of our common stock and the assumption of debt of $6.5 million,
liabilities of $678,000 and additional deferred income taxes of $7.2
million. We subsequently deployed the remaining rigs periodically
during the first nine months of 2007.
Working
Capital. Our working capital was $25.3 million at December 31,
2009, compared to $71.6 million at December 31, 2008. Our current
ratio, which we calculate by dividing our current assets by our current
liabilites, was 2.4 at December 31, 2009 compared to 3.0 at December 31,
2008.
We believe
that the liquidity shown on our balance sheet as of December 31, 2009, which
includes approximately $25.3 million in working capital (including $9.5 million
in cash) and availability under our $75.0 million credit facility of $8.5
million at December 31, 2009 (net of outstanding letters of credit of $11.5
million), together with cash expected to be generated from operations, provides
us with sufficient ability to fund our operations for at least the next twelve
months. However, additional capital may be required for future rig
requirements. 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. The changes in the components of our
working capital were as follows (amounts in thousands):
|
December
31,
|
||||||||||||
|
2009
|
2008
|
Change
|
||||||||||
|
Cash
and cash equivalents
|
$ | 9,497 | $ | 26,676 | $ | (17,179 | ) | |||||
|
Trade
and other receivables
|
15,306 | 62,430 | (47,124 | ) | ||||||||
|
Affiliate
receivables
|
9,620 | 3,387 | 6,233 | |||||||||
|
Unbilled
receivables
|
828 | 2,940 | (2,112 | ) | ||||||||
|
Income
tax receivable
|
3,800 | 2,072 | 1,728 | |||||||||
|
Current
deferred income taxes
|
1,360 | 2,844 | (1,484 | ) | ||||||||
|
Current
maturities of note receivable
|
2,000 | 6,900 | (4,900 | ) | ||||||||
|
Prepaid
expenses
|
666 | 572 | 94 | |||||||||
|
Current
assets
|
43,077 | 107,821 | (64,744 | ) | ||||||||
|
Current
debt
|
89 | 1,464 | (1,375 | ) | ||||||||
|
Accounts
Payable
|
9,756 | 18,473 | (8,717 | ) | ||||||||
|
Accrued
liabilities and deferred revenues
|
7,952 | 16,249 | (8,297 | ) | ||||||||
|
Current
liabilities
|
17,797 | 36,186 | (18,389 | ) | ||||||||
|
Working
capital
|
$ | 25,280 | $ | 71,635 | $ | (46,355 | ) | |||||
The decrease
in cash and cash equivalents was primarily due to the repayment of our revolving
credit facility with Fortis Bank SA/NV, in the amount of $111.1 million, capital
expenditures during 2009 in the amount of $17.6 million, $5.1 million paid to
various lenders, an increase in affiliate receivables of $6.2 million and a
decrease in accounts payable of $8.7 million, partially offset by the reduction
in trade and other receivables of $47.1 million, the receipt of $31.7 million in
proceeds from CICSA related to the sale of a 60% membership interest in Bronco
MX and a $55.0 million draw on our new revolving credit facility with Banco
Inbursa.
The decrease
in trade receivables and other receivables as well as accounts payable at
December 31, 2009 as compared to December 31, 2008 was due to a continued
reduction in revenue days and utilization rates during 2009 compared to
2008. Utilization for the year ended December 31, 2009 was 36%
compared to 79% for 2008.
The decrease
in accrued liabilities was due to a $2.5 million decrease in accrued salaries
and related, a decrease in deferred revenue of approximately $2.8 million due to
the reduction in the deferral of mobilization revenue, a $1.3 million reduction
in accrued interest and a $1.8 million reduction in our workers compensation
accrual. The decrease in our deferral of mobilization revenue is due
to the reduction in revenue days and utilization rates for the year ended 2009
compared to the year ended 2008.
Contractual
and Commercial Commitments
The following
table summarizes our contractual obligations and commercial commitments at
December 31, 2009 (in thousands):
|
Payments
Due by Period
|
||||||||||||||||||||
|
Contractual
Obligations
|
Total
|
Less
than 1
|
1-3
years
|
4-5
years
|
More
than 5
|
|||||||||||||||
|
year
|
years
|
|||||||||||||||||||
|
Short
and long-term debt
|
51,903 | $ | 89 | $ | 301 | $ | 50,778 | $ | 735 | |||||||||||
|
Interest
on long-term debt
|
16,218 | 3,407 | 10,185 | 2,506 | 120 | |||||||||||||||
|
Operating
lease obligations
|
2,895 | 913 | 1,681 | 301 | - | |||||||||||||||
|
Total
|
$ | 71,016 | $ | 4,409 | $ | 12,167 | $ | 53,585 | $ | 855 | ||||||||||
Off
Balance Sheet Arrangements
We do not
have any off balance sheet arrangements.
Recent
Accounting Pronouncements
The FASB Accounting
Standards Codification. FASB Accounting Standards Codification
(ASC) became effective for this quarterly report. ASC Topic 105,
Generally Accepted Accounting
Principles establishes the ASC as the single source of authoritative U.S.
generally accepted accounting principles (U.S. GAAP) recognized by the FASB to
be applied by nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative U.S. GAAP for SEC registrants. The ASC supersedes
all existing non-SEC accounting and reporting standards. All other
nongrandfathered non-SEC accounting literature not included in the ASC will
become nonauthoritative. Following ASC Topic 105, the FASB will not
issue new standards in the form of Statements, FASB Staff Positions, or Emerging
Issues Task Force Abstracts. Instead, the FASB will issue Accounting
Standards Updates, which will serve only to: (a) update the ASC, (b) provide
background information about the guidance; and (c) provide the basis for
conclusions on the change(s) in the ASC. The adoption of this
standard has changed how we reference various elements of U.S. GAAP in our
financial statement disclosures, but has no impact on our financial position,
results of operation or cash flows.
In September
2006, the FASB issued an accounting standard that defines fair value,
establishes a framework for measuring fair value in generally accepted
accounting principles (“GAAP”), and expands disclosures about fair value
measurements. The initial application of this standard was limited to financial
assets and liabilities and became effective on January 1, 2008. On
January 1, 2009 we adopted this standard on a prospective basis for
non-financial assets and liabilities not measured at fair value on a recurring
basis. The application of this standard to our non-financial assets
and liabilities is primarily limited to assets acquired and liabilities assumed
in a business combination, asset retirement obligations and asset impairments,
including goodwill and long lived assets and has not had a material impact on
our financial position, results of operations or cash flows.
In December
2007, the FASB issued a new accounting standard that calls for significant
changes from then current practice in accounting for business
combinations. The standard 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. The standard 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. The standard 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. The adoption of this
standard did not have an immediate impact on our financial position, results of
operations or cash flows.
In December
2007, the FASB issued a new accounting standard which 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. The standard
requires retroactive adoption of the presentation and disclosure requirements
for existing minority interests. All other requirements of this standard shall
be applied prospectively. The standard is effective for fiscal years, and
interim periods within those fiscal years, beginning on or after December 15,
2008. The provisions of this standard were applied to the Company’s
accounting for the sale of 60% of the membership interests in Bronco
MX. See Note 2, Equity Method Investments,
regarding the $23,705 loss on the Bronco MX transaction.
In June 2008,
the FASB issued a new accounting standard which provides that unvested
share-based payment awards that contain nonforfeitable rights to dividends are
participating securities and shall be included in the computation of earnings
per share pursuant to the two class method. This standard is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years. The
adoption of this standard did not have a material impact on our consolidated
financial statements s.
In
April 2009, the FASB issued a staff position which increases the frequency
of fair value disclosures for financial instruments from annual only to
quarterly reporting periods. The provisions of this staff position
are effective for financial statements issued for interim and annual periods
ending after June 15, 2009 and became effective for us in the quarter ended June
30, 2009. The adoption of this staff position did not have a material
impact on our consolidated financial statements.
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 of 5.80%. An
increase or decrease of 1% in the interest rate would have a corresponding
decrease or increase in our net income (loss) of approximately $337,000
annually, based on the $55.0 million outstanding in the aggregate under our
credit facility as of December 31, 2009.
Our Financial
Statements begin on page 32 of this Form 10-K, Index to Consolidated Financial
Statements, and are incorporated herein by this reference.
None.
Evaluation of Disclosure Control and
Procedures.
As of the end
of the period covered by this Annual Report on Form 10−K, 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 December 31, 2009 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 Annual
Report on Form 10−K was prepared, as appropriate to allow timely decision
regarding the required disclosure.
Management's
Report on Internal Control over Financial Reporting.
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting as defined in Rules 13a−15(f) and 15d−15(f)
under the Securities Exchange Act of 1934. Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external
purposes in accordance with GAAP. Our internal control over financial reporting
includes those policies and procedures that:
|
(i)
|
pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of our
company;
|
|
(ii)
|
provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with GAAP, and that
receipts and expenditures are being made only in accordance with
authorizations of management and our Board of Directors;
and
|
|
(iii)
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have
a material effect on the financial
statements.
|
Because of
its inherent limitations, internal controls over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree of compliance
with the policies or procedures may deteriorate.
Management,
with the participation of our Chief Executive Officer and Chief Financial
Officer, conducted its evaluation of the effectiveness of internal control over
financial reporting based on the framework in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. This evaluation included review of the documentation of
controls, evaluation of the design effectiveness of controls, testing of the
operating effectiveness of controls and a conclusion on this
evaluation. Although there are inherent limitations in the
effectiveness of any system of internal controls over financial reporting, based
on our evaluation, management has concluded that our internal control over
financial reporting was effective as of December 31, 2009.
The
independent registered public accounting firm that audited the Company's
financial statements, Grant Thornton LLP, has issued an attestation report on
the effectiveness of the Company’s internal control over financial reporting.
This report appears below.
Changes
in Internal Controls over Financial Reporting.
There were no
changes in internal control over financial reporting during the fourth quarter
that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting
Report of Independent
Registered Public Accounting Firm
Board of
Directors
Bronco
Drilling Company, Inc.
We have
audited the internal control over financial reporting of Bronco Drilling
Company, Inc. and Subsidiaries (the "Company") as of December 31, 2009,
based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission ("COSO"). The Company’s management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the
Company's internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, based on criteria
established in Internal
Control - Integrated Framework issued by COSO.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of the Company
as of December 31, 2009 and 2008, and the related consolidated statements of
operations, stockholders’equity and comprehensive income (loss) and cash flows
for each of the three years in the period ended December 31, 2009 and our report
dated March 12, 2010 expressed an unqualified opinion.
/s/ GRANT
THORNTON LLP
Oklahoma
City, Oklahoma
March 12,
2010
On November
13, 2009, our annual meeting of stockholders was held in Duncan,
Oklahoma. A total of 24,147,646 of our shares of common stock were
present or represented by proxy at the annual meeting. This
represented more than 88% of our shares outstanding on the record
date. At the meeting, our stockholders voted on the election of five
persons to serve as our directors. Each of the five nominees, D.
Frank Harrison, Dr. Gary C. Hill, David W. House, David L. Houston and William
R. Snipes, was elected as a director to serve until our next annual meeting of
stockholders and until his successor is duly elected and
qualified. The results of the tabulation of the votes cast at our
annual meeting are as follows:
|
Proposal
– Election of Directors
Name
|
For
(#)
|
Withheld
(#)
|
||
|
D.
Frank Harrison
|
23,777,495
|
370,151
|
||
|
Dr.
Gary C. Hill
|
20,794,227
|
3,353,419
|
||
|
David
W. House
|
20,803,676
|
3,343,970
|
||
|
David
L. Houston
|
23,622,936
|
524,710
|
||
|
William
R. Snipes
|
21,057,047
|
3,090,599
|
The
information relating to this Item 10 is incorporated by reference to either
the Proxy Statement for our 2010 Annual Meeting of Stockholders or an amendment
to this Form 10-K, which will be filed with the SEC no later than 120 days after
December 31, 2009.
The
information relating to this Item 11 is incorporated by reference to
either the Proxy Statement for our 2010 Annual Meeting of Stockholders or
an amendment to this Form 10-K, which will be filed with the SEC no later than
120 days after December 31, 2009.
The
information relating to this Item 12 is incorporated by reference to either
the Proxy Statement for our 2010 Annual Meeting of Stockholders or an amendment
to this Form 10-K, which will be filed with the SEC no later than 120 days after
December 31, 2009.
The
information relating to this Item 13 is incorporated by reference to either
the Proxy Statement for our 2010 Annual Meeting of Stockholders, or an amendment
to this Form 10-K, which will be filed with the SEC no later than 120 days
after December 31, 2009.
The
information relating to this Item 14 is incorporated by reference to either
the Proxy Statement for our 2010 Annual Meeting of Stockholders, or an amendment
to this Form 10-K, which will be filed with the SEC no later than 120 days after
December 31, 2009.
(a) The
following documents are filed as part of this report:
|
|
1.
|
Financial
Statements
|
See Index to
Consolidated Financial Statements on page 30 of this Form 10-K.
|
|
2.
|
Financial Statement
Schedules
|
Schedule
II
|
|
3.
|
Exhibits:
|
The following
exhibits are filed as part of this report or, where indicated, were previously
filed and are hereby incorporated by reference.
| Exhibit No. |
|
Description
|
|
2.1
|
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).
|
|
|
2.2
|
Agreement
and Plan of Merger by and among the Company, BDC Acquisition Company,
Eagle Well Service, Inc. (“Eagle”), and the stockholders of Eagle dated as
of January 9, 2007 (incorporated by reference to Exhibit 2.1 to the
Company’s Current Report on Form 8-K, File No. 000-51571, filed by the
Company with the SEC on January 16,
2007).
|
|
2.3
|
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).
|
|
2.4
|
Agreement
and Plan of Merger by and among the Company, BDC Acquisition Company,
Eagle Well Service, Inc. (“Eagle”), and the stockholders of Eagle dated as
of January 9, 2007 (incorporated by reference to Exhibit 2.1 to the
Company’s Current Report on Form 8-K, File No. 000-51571, filed by the
Company with the SEC on January 16,
2007).
|
|
2.5
|
Membership
Interest Purchase Agreement, dated September 18, 2009, by and among Bronco
Drilling Company, Inc., Saddleback Properties LLC and Carso
Infraestructura y Construccion, S.A.B. de C.V. (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 September 23,
2009).
|
|
3.1
|
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).
|
|
3.2
|
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).
|
|
4.1
|
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).
|
|
10.1
|
Credit
Agreement, dated September 18, 2009, by and among Bronco Drilling Company,
Inc., certain subsidiaries of Bronco Drilling Company, Inc., as
guarantors, and Banco Inbursa S.A., Institución de Banca Múltiple, Grupo
Financiero Inbursa, as lender and as the issuing bank (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K, File No.
000-51471, filed by the Company with the SEC on September 23,
2009).
|
|
10.2
|
Warrant
Agreement, dated September 18, 2009, by and among Bronco Drilling Company,
Inc. and Banco Inbursa S.A., Institución de Banca Múltiple, Grupo
Financiero Inbursa (incorporated by reference to Exhibit 10.2 to the
Current Report on Form 8-K, File No. 000-51471, filed by the Company with
the SEC on September 23,
2009).
|
|
10.3
|
Warrant
No. W-1, dated September 18, 2009, by and among Bronco Drilling Company,
Inc. and Banco Inbursa S.A., Institución de Banca Múltiple, Grupo
Financiero Inbursa (incorporated by reference to Exhibit 10.3 to the
Current Report on Form 8-K, File No. 000-51471, filed by the Company with
the SEC on September 23,
2009).
|
|
10.4
|
Registration
Rights Agreement, dated September 18, 2009, by and among Bronco Drilling
Company, Inc., Banco Inbursa S.A., Institución de Banca Múltiple, Grupo
Financiero Inbursa (incorporated by reference to Exhibit 10.4 to the
Current Report on Form 8-K, File No. 000-51471, filed by the Company with
the SEC on September 23,
2009).
|
|
+*10.5
|
Amended
and Restated Employment Agreement, dated January 6, 2010, by and between
the Company and Matthew S.
Porter.
|
|
*10.6
|
Warrant
No. W-2, dated September 18, 2009, by and among Bronco Drilling Company,
Inc. and Carso Infraestructura y Construcción, S.A.B. de
C.V.
|
|
10.7
|
Waiver
Letter, dated February 9, 2010, by and between Bronco Drilling Company,
Inc. and Banco Inbursa S.A., Institución de Banca Múltiple, Grupo
Financiero Inbursa (incorporated by reference to Exhibit 10.1 to the
Current Report on Form 8-K, File No. 000-51471, filed by the Company with
the SEC on February 16,
2010)
|
|
+10.8
|
Bronco
Drilling Company, Inc. 2008 Stock Incentive Plan (incorporated by
reference to Appendix B to the Company’s Proxy Statement, filed by the
Company with the SEC on April 28,
2008).
|
|
+10.9
|
Form
of Restricted Stock Award Agreement (incorporated by reference to Exhibit
10.2 to the Company’s Current Report on Form 8-K, File No. 000-51571,
filed by the Company with the SEC on June 15,
2008).
|
|
+10.10
|
Form
of Stock Option Agreement (incorporated by reference to Exhibit 10.3 to
the Company’s Current Report on Form 8-K, File No. 000-51571, filed by the
Company with the SEC on June 15,
2008).
|
|
*21.1
|
List
of the Company’s
Subsidiaries.
|
|
*23.1
|
Consent
of Grant Thornton
LLP
|
|
*24.1
|
Power
of Attorney (included on signature
page).
|
|
*31.1
|
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.
|
|
*31.2
|
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
|
|
*32.1
|
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.
|
|
*32.2
|
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.
|
|
|
+
Management contract, compensatory plan or
arrangement
|
|
|
*Filed
herewith.
|
INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
BRONCO
DRILLING COMPANY, INC. AND SUBSIDIARIES
|
Page
|
|
|
Bronco
Drilling Company, Inc. and Subsidiaries
|
|
| 31 | |
| 32 | |
| 33 | |
| 34 | |
| 35 | |
| 36 |
Board of
Directors
Bronco
Drilling Company, Inc.
We have
audited the accompanying consolidated balance sheets of Bronco Drilling Company,
Inc. and Subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the
related consolidated statements of operations, stockholders’equity and
comprehensive income (loss) and cash flows for each of the three years in the
period ended December 31, 2009. These financial statements are the
responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Bronco Drilling Company,
Inc. and Subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2009, in conformity with accounting principles generally accepted
in the United States of America.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) and our report dated March 12, 2010 expressed an
unqualified opinion.
/s/ GRANT
THORNTON LLP
Oklahoma
City, Oklahoma
March 12,
2010
|
(Amounts
in thousands, except share par value)
|
||||||||
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
|
|
||||||
|
CURRENT
ASSETS
|
||||||||
|
Cash
and cash equivalents
|
$ | 9,497 | $ | 26,676 | ||||
|
Receivables
|
||||||||
|
Trade
and other, net of allowance for doubtful accounts of
|
||||||||
|
$3,576
and $3,830 in 2009 and 2008, respectively
|
15,306 | 62,430 | ||||||
|
Affiliate
receivables
|
9,620 | 3,387 | ||||||
|
Unbilled
receivables
|
828 | 2,940 | ||||||
|
Income
tax receivable
|
3,800 | 2,072 | ||||||
|
Current
deferred income taxes
|
1,360 | 2,844 | ||||||
|
Current
maturities of note receivable from affiliate
|
2,000 | 6,900 | ||||||
|
Prepaid
expenses
|
666 | 572 | ||||||
|
Total
current assets
|
43,077 | 107,821 | ||||||
|
PROPERTY
AND EQUIPMENT - AT COST
|
||||||||
|
Drilling
rigs and related equipment
|
440,760 | 512,158 | ||||||
|
Transportation,
office and other equipment
|
42,354 | 43,912 | ||||||
|
|
483,114 | 556,070 | ||||||
|
Less
accumulated depreciation
|
145,918 | 123,915 | ||||||
| 337,196 | 432,155 | |||||||
|
OTHER
ASSETS
|
||||||||
|
Note
receivable from affiliate, less current maturities
|
517 | 3,451 | ||||||
|
Investment
in Challenger
|
39,714 | 62,875 | ||||||
|
Investment
in Bronco MX
|
21,407 | - | ||||||
|
Intangibles,
net, and other
|
3,672 | 6,052 | ||||||
| 65,310 | 72,378 | |||||||
| $ | 445,583 | $ | 612,354 | |||||
|
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||
|
CURRENT
LIABILITIES
|
||||||||
|
Accounts
payable
|
$ | 9,756 | $ | 18,473 | ||||
|
Accrued
liabilities
|
7,952 | 16,249 | ||||||
|
Current
maturities of long-term debt
|
89 | 1,464 | ||||||
|
|
||||||||
|
Total
current liabilities
|
17,797 | 36,186 | ||||||
|
LONG-TERM
DEBT, less current maturities and discount
|
51,814 | 116,083 | ||||||
|
WARRANT
|
2,829 | - | ||||||
|
DEFERRED
INCOME TAXES
|
32,872 | 66,074 | ||||||
|
COMMITMENTS
AND CONTINGENCIES (Note 8)
|
||||||||
|
STOCKHOLDERS'
EQUITY
|
||||||||
|
Common
stock, $.01 par value, 100,000
|
||||||||
|
shares
authorized; 26,713 and 26,346 shares
|
||||||||
|
issued
and outstanding at December 31, 2009 and 2008
|
270 | 267 | ||||||
|
|
||||||||
|
Additional
paid-in capital
|
307,313 | 304,015 | ||||||
|
Accumulated
other comprehensive income
|
538 | - | ||||||
|
Retained
earnings
|
32,150 | 89,729 | ||||||
|
Total
stockholders' equity
|
340,271 | 394,011 | ||||||
| $ | 445,583 | $ | 612,354 | |||||
|
The
accompanying notes are an integral part of these
statements.
|
||||||||
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
||||||||||||
|
(Amounts
in thousands, except per share amounts)
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
|
|
|
||||||||||
|
REVENUES
|
||||||||||||
|
Contract
drilling revenues, including 0%, 2% and 1%
|
||||||||||||
|
to
related parties
|
$ | 106,738 | $ | 247,829 | $ | 276,088 | ||||||
|
Well
service, including 0%, 2% and 0%
|
||||||||||||
|
to
related parties
|
3,799 | 33,284 | 22,864 | |||||||||
| 110,537 | 281,113 | 298,952 | ||||||||||
|
EXPENSES
|
||||||||||||
|
Contract
drilling
|
75,996 | 148,866 | 153,797 | |||||||||
|
Well
service
|
4,267 | 24,478 | 14,299 | |||||||||
|
Depreciation
and amortization
|
45,674 | 50,388 | 44,241 | |||||||||
|
General
and administrative
|
19,777 | 33,771 | 22,690 | |||||||||
|
Impairment
of goodwill
|
- | 24,328 | - | |||||||||
|
Gain
on Challenger transactions
|
- | (3,138 | ) | - | ||||||||
|
Loss
on Bronco MX transaction
|
23,705 | - | - | |||||||||
| 169,419 | 278,693 | 235,027 | ||||||||||
|
Income
(loss) from operations
|
(58,882 | ) | 2,420 | 63,925 | ||||||||
|
OTHER
INCOME (EXPENSE)
|
||||||||||||
|
Interest
expense
|
(7,038 | ) | (4,171 | ) | (4,762 | ) | ||||||
|
Loss
from early extinguishment of debt
|
(2,859 | ) | (155 | ) | - | |||||||
|
Interest
income
|
274 | 1,058 | 1,239 | |||||||||
|
Equity
in income (loss) of Challenger
|
(1,914 | ) | 2,186 | - | ||||||||
|
Equity
in income (loss) of Bronco MX
|
(588 | ) | - | - | ||||||||
|
Impairment
of investment in Challenger
|
(21,247 | ) | (14,442 | ) | - | |||||||
|
Other
|
(284 | ) | (300 | ) | 294 | |||||||
|
Change
in fair value of warrant
|
1,850 | - | - | |||||||||
| (31,806 | ) | (15,824 | ) | (3,229 | ) | |||||||
|
Income
(loss) before income taxes
|
(90,688 | ) | (13,404 | ) | 60,696 | |||||||
|
Income
tax expense (benefit)
|
(33,109 | ) | (5,161 | ) | 23,104 | |||||||
|
NET
INCOME (LOSS)
|
$ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
|
Income
(loss) per common share-Basic
|
$ | (2.16 | ) | $ | (0.31 | ) | $ | 1.45 | ||||
|
Income
(loss) per common share-Diluted
|
$ | (2.16 | ) | $ | (0.31 | ) | $ | 1.44 | ||||
|
Weighted
average number of shares outstanding-Basic
|
26,651 | 26,293 | 25,996 | |||||||||
|
Weighted
average number of shares outstanding-Diluted
|
26,651 | 26,293 | 26,101 | |||||||||
|
The
accompanying notes are an integral part of these
statements.
|
||||||||||||
|
CONSOLIDATED
STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(LOSS)
|
||||||||||||||||||||||||
|
(Amounts
in thousands)
|
||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||
|
Additional
|
Other
|
Total
|
||||||||||||||||||||||
|
Common
|
Common
|
Paid
In
|
Comprehensive
|
Retained
|
Stockholders'
|
|||||||||||||||||||
|
Shares
|
Amount
|
Capital
|
Income
|
Earnings
|
Equity
|
|||||||||||||||||||
|
Balance
as of December 31, 2006
|
24,938 | 250 | 279,355 | - | 60,380 | 339,985 | ||||||||||||||||||
|
Stock
issued in acquisition
|
1,070 | 10 | 15,114 | - | - | 15,124 | ||||||||||||||||||
|
Net
income
|
- | - | - | - | 37,592 | 37,592 | ||||||||||||||||||
|
Stock
compensation
|
23 | 2 | 3,726 | - | - | 3,728 | ||||||||||||||||||
|
Balance
as of December 31, 2007
|
26,031 | 262 | 298,195 | - | 97,972 | 396,429 | ||||||||||||||||||
|
Net
loss
|
- | - | - | - | (8,243 | ) | (8,243 | ) | ||||||||||||||||
|
Stock
compensation
|
315 | 5 | 5,820 | - | - | 5,825 | ||||||||||||||||||
|
Balance
as of December 31, 2008
|
26,346 | 267 | 304,015 | - | 89,729 | 394,011 | ||||||||||||||||||
|
Net
loss
|
- | - | - | - | (57,579 | ) | (57,579 | ) | ||||||||||||||||
|
Other
Comprehensive Income:
|
||||||||||||||||||||||||
|
Foreign
currency translation adjustment
|
- | - | - | 538 | - | 538 | ||||||||||||||||||
|
Total
Comprehensive Income (Loss)
|
(57,041 | ) | ||||||||||||||||||||||
|
Stock
compensation
|
367 | 3 | 3,298 | - | - | 3,301 | ||||||||||||||||||
|
Balance
as of December 31, 2009
|
26,713 | $ | 270 | $ | 307,313 | $ | 538 | $ | 32,150 | $ | 340,271 | |||||||||||||
|
The
accompanying notes are an integral part of these
statements.
|
||||||||||||||||||||||||
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
||||||||||||
|
(Amounts
in thousands)
|
||||||||||||
|
Years
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
|
|
|
||||||||||
|
Cash
flows from operating activities:
|
|
|
|
|||||||||
|
Net
income (loss)
|
$ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
|
Adjustments
to reconcile net income (loss) to net cash
|
||||||||||||
|
provided
by operating activities:
|
||||||||||||
|
Depreciation
and amortization
|
46,436 | 51,044 | 44,826 | |||||||||
|
Bad
debt expense
|
2,134 | 3,745 | 4,370 | |||||||||
|
Loss
(gain) on sale of assets
|
412 | 426 | (1,589 | ) | ||||||||
|
Gain
on Challenger transactions
|
- | (3,138 | ) | - | ||||||||
|
Equity
in loss (income) of Challenger
|
1,914 | (2,186 | ) | - | ||||||||
|
Equity
in loss (income) of Bronco MX
|
588 | - | - | |||||||||
|
Change
in fair value of warrant
|
(1,850 | ) | - | - | ||||||||
|
Loss
on Bronco MX transaction
|
23,705 | - | - | |||||||||
|
Write
off of debt issue costs
|
2,859 | 155 | - | |||||||||
|
Imputed
interest expense
|
224 | - | - | |||||||||
|
Stock
compensation
|
3,301 | 5,825 | 3,728 | |||||||||
|
Impairment
of goodwill
|
- | 24,328 | - | |||||||||
|
Impairment
of investment in Challenger
|
21,247 | 14,442 | - | |||||||||
|
Provision
for deferred income taxes
|
(31,717 | ) | (4,122 | ) | 17,648 | |||||||
|
Changes
in current assets and liabilities, net of assets and liabilities of
business acquired:
|
||||||||||||
|
Receivables
|
43,517 | (9,274 | ) | (3,920 | ) | |||||||
|
Affiliate
receivables
|
(6,233 | ) | - | - | ||||||||
|
Unbilled
receivables
|
2,112 | (813 | ) | (139 | ) | |||||||
|
Prepaid
expenses
|
(94 | ) | 131 | (176 | ) | |||||||
|
Other
assets
|
241 | 720 | (417 | ) | ||||||||
|
Accounts
payable
|
(13,142 | ) | (9,673 | ) | (15,831 | ) | ||||||
|
Accrued
expenses
|
(8,297 | ) | (3,030 | ) | 1,430 | |||||||
|
Income
taxes receivable
|
(1,730 | ) | (1,237 | ) | (4,915 | ) | ||||||
|
Net
cash provided by operating activities
|
28,048 | 59,100 | 82,607 | |||||||||
|
Cash
flows from investing activities:
|
||||||||||||
|
Restricted
cash account
|
- | 2,899 | 145 | |||||||||
|
Business
acquisitions, net of cash acquired
|
- | (5,063 | ) | (2,431 | ) | |||||||
|
Principal
payments received on note receivable
|
3,065 | - | - | |||||||||
|
Proceeds
from sale of assets
|
32,688 | 6,643 | 5,084 | |||||||||
|
Purchase
of property and equipment
|
(17,559 | ) | (87,274 | ) | (82,782 | ) | ||||||
|
Net
cash provided by (used in) investing activities
|
18,194 | (82,795 | ) | (79,984 | ) | |||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Proceeds
from borrowings and warrant
|
55,000 | 51,100 | 17,000 | |||||||||
|
Payments
of debt
|
(116,189 | ) | (2,949 | ) | (24,510 | ) | ||||||
|
Debt
issue costs
|
(2,232 | ) | (3,501 | ) | - | |||||||
|
Net
cash provided by (used in) financing activities
|
(63,421 | ) | 44,650 | (7,510 | ) | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
(17,179 | ) | 20,955 | (4,887 | ) | |||||||
|
|
||||||||||||
|
Beginning
cash and cash equivalents
|
26,676 | 5,721 | 10,608 | |||||||||
|
Ending
cash and cash equivalents
|
$ | 9,497 | $ | 26,676 | $ | 5,721 | ||||||
|
Supplmentary
disclosure of cash flow information
|
||||||||||||
|
Interest
paid, net of amount capitalized
|
$ | 11,549 | $ | 2,704 | $ | 3,250 | ||||||
|
Income
taxes paid
|
337 | 198 | 10,373 | |||||||||
|
Supplementary
disclosure of non-cash investing and financing:
|
||||||||||||
|
Liabilities
assumed in acquisition
|
$ | - | $ | - | $ | 7,867 | ||||||
|
Common
stock issued for acquisition
|
- | - | 15,124 | |||||||||
|
Debt
assumed in acquisition
|
- | - | 6,527 | |||||||||
|
Note
issued for acquisition of property and equipment
|
- | 1,277 | 4,386 | |||||||||
|
Assets
exchanged/sold for equity interest and note receivable
|
- | 72,503 | - | |||||||||
|
Common
stock received for payment of receivable
|
- | 1,900 | - | |||||||||
|
Purchase
of property and equipment in accounts payable
|
4,425 | 11,430 | - | |||||||||
|
Reduction
of receivable for property and equipment
|
5,040 | - | - | |||||||||
|
Reduction
of debt for warrants issued
|
4,679 | - | - | |||||||||
|
Assets
contributed to Bronco MX
|
77,194 | - | - | |||||||||
|
The
accompanying notes are an integral part of these
statements.
|
||||||||||||
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
($
Amounts in thousands, except per share amounts)
1.
Organization and Summary of Significant Accounting Policies
Business
and Principles of Consolidation
Bronco
Drilling Company, Inc. (the “Company”) provides contract land drilling and
workover services to oil and natural gas exploration and production companies.
The accompanying consolidated financial statements include the Company’s
accounts and the accounts of its wholly owned subsidiaries. All intercompany
accounts and transactions have been eliminated in consolidation.
The Company
has prepared the consolidated financial statements and related notes in
accordance with accounting principles generally accepted in the United States of
America. In preparing the financial statements, the Company made various
estimates and assumptions that affect the amounts of assets and liabilities the
Company reports as of the dates of the balance sheets and amounts the Company
reports for the periods shown in the consolidated statements of operations,
stockholders’ equity and cash flows. The Company’s actual results could differ
significantly from those estimates. Material estimates that are particularly
susceptible to significant changes in the near term relate to the Company’s
recognition of revenues and accrued expenses, estimate of the allowance for
doubtful accounts, estimate of asset impairments, estimate of deferred taxes and
determination of depreciation and amortization expense.
A summary of
the significant accounting policies consistently applied in the preparation of
the accompanying consolidated financial statements follows.
Cash
and Cash Equivalents
The Company
considers all highly liquid debt instruments purchased with a maturity of three
months or less when acquired and money market mutual funds to be cash
equivalents.
The Company
maintains its cash and cash equivalents in accounts and instruments that may not
be federally insured beyond certain limits. The Company has not experienced any
losses in such accounts and believes it is not exposed to any significant credit
risks on cash and cash equivalents.
Foreign
Currency
The U.S.
dollar is the functional currency for the Company’s consolidated operations.
However, the Company has an equity investment in a Mexican entity whose
functional currency is the peso. The assets and liabilities of the Mexican
investment are translated into U.S. dollars based on the current exchange rate
in effect at the balance sheet dates. Mexican income and expenses are translated
at average rates for the periods presented. Translation adjustments have no
effect on net income and are included in accumulated other comprehensive income
in stockholders’ equity.
Revenue
Recognition
Contract Land
Drilling Segment - The Company earns contract drilling revenue under
daywork and footage contracts.
Revenues on
daywork contracts are recognized based on the days completed at the dayrate each
contract specifies. Mobilization revenues and costs for daywork contracts are
deferred and recognized over the days of actual drilling.
The Company
follows 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 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.
Revenue
arising from claims for amounts billed in excess of the contract price or for
amounts not included in the original contract are recognized when billed less
any allowance for uncollectibility. Revenue from such claims is only recognized
if it is probable that the claim will result in additional revenue, the costs
for the additional services have been incurred, management believes there is a
legal basis for the claim and the amount can be reliably estimated. Revenue from
such claims are recorded only to the extent that contract costs relating to the
claim have been incurred. Historically we have not billed any
customers for amounts not included in the original contract.
Well Servicing
Segment – The Company earns well servicing revenue based on purchase
orders, contracts or other persuasive evidence of an arrangement with the
customer, such as a master service agreement, that include fixed or determinable
prices. The well servicing revenues are recognized when the services
have been rendered and collectability is reasonably assured.
The asset
“unbilled receivables” represents revenues we have recognized in excess of
amounts billed on drilling contracts and well servicing in
progress.
Accounts
Receivable
The Company
records trade accounts receivable at the amount invoiced to customers.
Substantially all of the Company’s accounts receivable are due from companies in
the oil and gas industry. Credit is extended based on evaluation of a customer’s
financial condition and, generally, collateral is not required. Accounts
receivable are due within 30 days and are stated at amounts due from customers,
net of an allowance for doubtful accounts when the Company believes collection
is doubtful. Accounts outstanding longer than the contractual payment terms are
considered past due. The Company determines its allowance by considering a
number of factors, including the length of time trade accounts receivable are
past due, the Company’s previous loss history, the customer’s current ability to
pay its obligation to the Company and the condition of the general economy and
the industry as a whole. The Company writes off specific accounts receivable
when they become uncollectible and payments subsequently received on such
receivables reduce the allowance for doubtful accounts. At December 31,
2009 and 2008, our allowance for doubtful accounts was $3,576 and $3,830,
respectively.
Prepaid
Expenses
Prepaid
expenses include items such as insurance and fees. The Company routinely
expenses these items in the normal course of business over the periods these
expenses benefit.
Property
and Equipment
Property and
equipment, including renewals and betterments, are capitalized and stated at
cost, while maintenance and repairs are expensed currently. Assets are
depreciated on a straight-line basis. The depreciable lives of drilling and
workover rigs and related equipment are three to 15 years. The
depreciable life of other equipment is three years. Depreciation is not
commenced until acquired rigs are placed in service. Once placed in service,
depreciation continues when rigs are being repaired, refurbished or between
periods of deployment. Assets not placed in service and not being depreciated
were $26,038 and $34,293 as of December 31, 2009 and 2008,
respectively. Due to immateriality, gains and losses on dispositions,
with the exception of the Challenger and Bronco MX transactions are included in
contract drilling and well service revenues.
The Company
capitalizes interest as a component of the cost of drilling and workover rigs
constructed for its own use. For the years ended December 31, 2009 and
2008, the Company capitalized $0 and $1,256, respectively, of interest costs
incurred during the construction periods of certain drilling and workover
rigs.
The Company evaluates
for potential impairment of long-lived assets and intangible assets subject to
amortization when indicators of impairment are present, as defined in ASC Topic
360, Accounting for the
Impairment or Disposal of Long-Lived Assets. Circumstances that could indicate a
potential impairment include significant adverse changes in industry trends,
economic climate, legal factors, and an adverse action or assessment by a
regulator. More specifically, significant adverse changes in industry trends
include significant declines in revenue rates, utilization rates, oil and
natural gas market prices and industry rig counts for drilling rigs and workover
rigs. In performing an impairment evaluation, the Company estimated the future
undiscounted net cash flows from the use and eventual disposition of long-lived
assets and intangible assets grouped at the lowest level that cash flows can be
identified. If the sum of the estimated future undiscounted net cash
flows is less than the carrying amount of the long-lived assets and intangible
assets for these asset grouping levels, then the Company would recognize an
impairment charge. The amount of an impairment charge would be measured as the
difference between the carrying amount and the fair value of these assets. The
Company did not record an impairment charge on any long-lived assets for our
contract land drilling or well servicing segments for the year ended
December 31, 2009. The assumptions used in the impairment
evaluation for long-lived assets and intangible assets are inherently uncertain
and require management judgment.
Goodwill
The Company
evaluates 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. Such
circumstances could include, but are not limited to: (1) a significant
adverse change in legal factors or in business climate, (2) unanticipated
competition, or (3) an adverse action or assessment by a regulator. When
evaluating whether goodwill is impaired, the Company compares its fair value to
its carrying amount, including goodwill. Fair value is estimated using a
combination of income, or discounted cash flows approach and the market
approach, which utilizes comparable companies’ data. If the carrying amount
exceeds its fair value, then the amount of the impairment loss must be measured.
The impairment loss would be calculated by comparing the implied fair value of
reporting unit goodwill to its carrying amount. In calculating the implied fair
value of goodwill, the fair value of the Company is allocated to all of its
other assets and liabilities based on their fair values. The excess of the fair
value of the Company over the amount assigned to its other assets and
liabilities is the implied fair value of goodwill. An impairment loss would be
recognized when the carrying amount of goodwill exceeds its implied fair
value.
Goodwill
impairment testing is performed at the level of the Company’s reporting units
under the provisions of ASC Topic 350, Goodwill and Other Intangible
Assets. The Company’s reporting units have been determined to
be the same as our operating segments, contract land drilling and well
servicing. In the Company’s testing of possible impairment of
goodwill, we compared the fair value of the reporting units with their carrying
value. If the fair value exceeds the carrying value, no impairment is
indicated. If the carrying value exceeds the fair value, we measure
any impairment of goodwill in that reporting unit by allocating the fair value
to the identifiable assets and liabilities of the reporting unit based on their
respective fair values. Any excess un-allocated fair value would
equal the implied fair value of goodwill, and if that amount is below the
carrying value of goodwill, an impairment charge is recognized.
In completing
the first step of the goodwill impairment analysis during the fourth quarter of
2008, management used a five-year projection of discounted cash flows, plus a
terminal value determined using a constant growth method to estimate the fair
value of reporting units. In developing these fair value estimates,
certain key assumptions included an assumed discount rate of 11.0% and 14.0% for
our contract land drilling and well servicing segments, respectively, and an
assumed long-term growth rate of 2.0% for both reporting
units.
Based on the
results of the first step of the goodwill impairment test, impairment was
indicated in both reporting units. Management performed the second
step of the analysis of its drilling and well servicing reporting units,
allocating the estimated fair value to the indentifiable tangible and intangible
assets and liabilities of these reporting units based on their respective
values. This allocation indicated no residual value for goodwill, and
accordingly we recorded an impairment charge of $24,328 million in our December
31, 2008 statement of operations. This impairment charge did
not have an impact on the Company’s liquidity or debt covenants; however, it was
a reflection of the overall downturn in our industry and decline in the
Company’s projected cash flows.
Intangibles,
Net and Other
Intangibles,
restricted cash and other assets consist of intangibles related to acquisitions,
net of amortization, cash deposits related to the deductibles on the Company’s
workers compensation insurance policies and debt issue costs, net of
amortization. The Company follows Statement ASC Topic 323, “Intangibles – Goodwill and
Other” to account for amortizable intangibles. Intangible assets that are
acquired either individually or with a group of other assets are recognized
based on its fair value and amortized over its useful life. The Company’s
amortizable intangibles consist entirely of customer lists and relationships
obtained through acquisitions. Customer lists and relationships are amortized
over their estimated benefit period of four years. Depreciation and amortization
expense includes amortization of intangibles of $751, $974, and $919 for the
years ended December 31, 2009, 2008, and 2007, respectively. Total cost and
accumulated amortization of intangibles at December 31, 2009 and 2008 was $3,705
and $3,403 and $3,705 and $2,652, respectively.
The Company
evaluates for potential impairment of long-lived assets and intangible assets
subject to amortization when indicators of impairment are present, as defined in
ASC Topic 360, Property, Plant
and Equipment. In light of adverse market conditions affecting
the Company, including a substantial decrease in the operating levels of its
business segments, a significant decline in oil and natural gas commodity
prices, management deemed it necessary to assess the recoverability of
long-lived assets and intangibles within its contract land drilling and well
servicing segments.
Management
performed its impairment assessment under the provisions of ASC Topic 360 using
the undiscounted cash flows for each segment. Based on the results of
these impairment tests, the carrying amounts of intangible assets were
determined to be recoverable.
Estimated
amortization expense for each year subsequent to December 31, 2009 is as
follows:
|
2010…………………..
|
$ 249
|
|
2011…………………..
|
53
|
|
2012…………………..
|
-
|
|
2013…………………..
|
-
|
|
2014…………………..
|
-
|
Legal fees
and other debt issue costs incurred in obtaining financing are amortized over
the term of the debt using a method which approximates the effective interest
method. Gross debt issue costs were $2,232 and $3,501 at December 31, 2009
and 2008, respectively. Amortization expense related to debt issue costs was
$592, $571, and $564 for years ended December 31, 2009, 2008, and 2007,
respectively, and is included in interest expense in the consolidated statements
of operations. Accumulated amortization related to loan fees was $126 and $175
as of December 31, 2009 and 2008, respectively. On September 18,
2009 and September 29, 2008 the Company refinanced its revolving debt facility
and incurred $2,232 and $3,501 of debt issuance costs,
respectively. The Company wrote-off debt issue costs of $2,859, which
is included in loss from early extinguishment of debt on the consolidated
statement of operations for the year ended December 31, 2009.
Income
Taxes
Pursuant to
Statement ASC Topic 740, Income Taxes, the Company
follows the asset and liability method of accounting for income taxes, under
which the Company recognizes deferred tax assets and liabilities for the future
tax consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities were measured using enacted tax rates
expected to apply to taxable income in the years in which the Company expects to
recover or settle those temporary differences. A statutory Federal tax rate of
35% and effective state tax rate of 3.7% (net of Federal income tax effects)
were used for the enacted tax rates for all periods.
As changes in
tax laws or rates are enacted, deferred income tax assets and liabilities are
adjusted through the provision for income taxes. Deferred tax assets are reduced
by a valuation allowance if, based on available evidence, it is more likely than
not that some portion or all of the deferred tax assets will not be realized.
The classification of current and noncurrent deferred tax assets and liabilities
is based primarily on the classification of the assets and liabilities
generating the difference.
The Company
applies the provisions of ASC Topic 740 which addresses the accounting for
uncertainty in income taxes recognized in an enterprise’s financial statements
and prescribes a recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. The Company recognizes interest and/or
penalties related to income tax matters as income tax expense. As of December
31, 2009, the tax years ended December 31, 2005 through December 31, 2008 are
open for examination by U.S. taxing authorities.
Comprehensive
Income (Loss)
Comprehensive
income (loss) is comprised of net income (loss) and other comprehensive
income. Other comprehensive income includes the translation
adjustments of the financial statements of Bronco MX at December 31,
2009. The following table sets forth the components of comprehensive
income (loss):
|
Years
ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
income (loss)
|
$ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
|
Other
comprehensive income - translation adjustment
|
538 | - | - | |||||||||
|
Comprehensive
income (loss)
|
$ | (57,041 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
Net
income (Loss) Per Common Share
The Company computes
and presents net income (loss) per common share in accordance with ASC Topic 260, Earnings per
Share. This standard requires dual
presentation of basic and diluted net income (loss) per share on the face of the
Company’s statement of operations. Basic net income (loss) per common share is
computed by dividing net income or loss attributable to common stock by the
weighted average number of common shares outstanding for the period. Diluted net
income (loss) per common share reflects the potential dilution that could occur
if options or other contracts to issue common stock were exercised or converted
into common stock.
Stock-based
Compensation
The Company
has adopted ASC Topic 718, Stock Compensation upon
granting its first stock options on August 16, 2005. ASC Topic
718 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.
Equity
Method Investments
Investee
companies that are not consolidated, but over which the Company exercises
significant influence, are accounted for under the equity method of accounting.
Whether or not the Company exercises significant influence with respect to an
Investee depends on an evaluation of several factors including, among others,
representation on the Investee company’s board of directors and ownership level,
which is generally a 20% to 50% interest in the voting securities of the
Investee company. Under the equity method of accounting, an Investee company’s
accounts are not reflected within the Company’s Consolidated Balance Sheets and
Statements of Operations; however, the Company’s share of the earnings or losses
of the Investee company is reflected in the caption “Equity in income of
Challenger” and “Equity in income of Bronco MX” in the Consolidated Statements
of Operations. The Company’s carrying value in an equity method Investee company
is reflected in the caption “Investment in Challenger” and “Investment in Bronco
MX” in the Company’s Consolidated Balance Sheets.
Recent
Accounting Pronouncements
The FASB Accounting
Standards Codification. FASB Accounting Standards Codification
(ASC) became effective for this quarterly report. ASC Topic 105,
Generally Accepted Accounting
Principles establishes the ASC as the single source of authoritative U.S.
generally accepted accounting principles (U.S. GAAP) recognized by the FASB to
be applied by nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources
of authoritative U.S. GAAP for SEC registrants. The ASC supersedes
all existing non-SEC accounting and reporting standards. All other
nongrandfathered non-SEC accounting literature not included in the ASC will
become nonauthoritative. Following ASC Topic 105, the FASB will not
issue new standards in the form of Statements, FASB Staff Positions, or Emerging
Issues Task Force Abstracts. Instead, the FASB will issue Accounting
Standards Updates, which will serve only to: (a) update the ASC; (b) provide
background information about the guidance; and (c) provide the basis for
conclusions on the change(s) in the ASC. The adoption of this
standard has changed how we reference various elements of U.S. GAAP in the
Company’s financial statement disclosures, but has no impact on the Company’s
financial position, results of operation or cash flows.
In September
2006, the FASB issued an accounting standard that defines fair value,
establishes a framework for measuring fair value in generally accepted
accounting principles (“GAAP”), and expands disclosures about fair value
measurements. The initial application of this standard was limited to financial
assets and liabilities and became effective on January 1, 2008 for the
Company. On January 1, 2009 the Company adopted this standard on a
prospective basis for non-financial assets and liabilities not measured at fair
value on a recurring basis. The application of this standard to the
Company’s non-financial assets and liabilities is primarily limited to assets
acquired and liabilities assumed in a business combination, asset retirement
obligations and asset impairments, including goodwill and long lived assets and
has not had a material impact on the Company’s consolidated financial
statements.
In December
2007, the FASB issued a new accounting standard that calls for significant
changes from then current practice in accounting for business
combinations. The standard 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. The standard 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. The standard 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. The adoption of this
standard did not have an immediate impact on the Company’s consolidated
financial statements.
In December
2007, the FASB issued a new accounting standard which 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. The standard
requires retroactive adoption of the presentation and disclosure requirements
for existing minority interests. All other requirements of this standard shall
be applied prospectively. The standard is effective for fiscal years, and
interim periods within those fiscal years, beginning on or after December 15,
2008. The provisions of this standard were applied to the Company’s
accounting for its sale of 60% of its membership interests in Bronco
MX. See Note 2 Equity Method Investments,
regarding the $23,705 loss on the Bronco MX transaction.
In June 2008,
the FASB issued a new accounting standard which provides that unvested
share-based payment awards that contain nonforfeitable rights to dividends are
participating securities and shall be included in the computation of earnings
per share pursuant to the two class method. This standard is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years. The
adoption of this standard did not have a material impact on the Company’s
consolidated financial statements.
In
April 2009, the FASB issued a staff position which increases the frequency
of fair value disclosures for financial instruments from annual only to
quarterly reporting periods. The provisions of this staff position
are effective for financial statements issued for interim and annual periods
ending after June 15, 2009 and became effective for the Company in the quarter
ended June 30, 2009. The adoption of this staff position did not have
a material impact on the Company’s consolidated financial
statements.
In June 2009,
the FASB issued a new accounting standard that amends the accounting and
disclosure requirements for the consolidation of variable interest entities.
This new standard removes the previously existing exception from applying
consolidation guidance to qualifying special-purpose entities and requires
ongoing reassessments of whether an enterprise is the primary beneficiary of a
variable interest entity. Before this new standard, generally accepted
accounting principles required reconsideration of whether an enterprise is the
primary beneficiary of a variable interest entity only when specific events
occurred. This new standard is effective as of the beginning of each reporting
entity’s first annual reporting period that begins after November 15, 2009,
for interim periods within that first annual reporting period, and for interim
and annual reporting periods thereafter. This new standard became effective for
us on January 1, 2010. The adoption of this standard did not impact our
consolidated financial statements.
Reclassifications
Certain
amounts in the financial statements for the prior years have been reclassified
to conform to the current year’s presentation.
2.
Equity Method Investments
On
January 4, 2008, we acquired a 25% equity interest in Challenger Limited,
in exchange for six drilling rigs valued at $72,937 and $5,063 in
cash. The Company’s 25% interest at December 31, 2009 was based on
64,957,265 shares outstanding. The Company recorded equity in income
(loss) of investment of $(1,914) and $2,186 for the years ended December 31,
2009 and 2008, respectively, related to its equity investment in
Challenger. Challenger is an international provider of contract land
drilling and workover services to oil and natural gas companies with its
principal operations in Libya. Five of the contributed drilling rigs
were from our existing marketed fleet and one was a newly constructed
rig. The general specifications of the contributed rigs are as
follows:
|
Approximate
|
|||||
|
Drilling
|
|||||
|
Rig
|
Design
|
Depth
(ft)
|
Type
|
Horsepower
|
|
|
3
|
Cabot
900
|
10,000
|
Mechanical
|
950
|
|
|
18
|
Gardner
Denver 1500E
|
25,000
|
Electric
|
2,000
|
|
|
19
|
Mid
Continent U-1220 EB
|
25,000
|
Electric
|
2,000
|
|
|
38
|
National
1320
|
25,000
|
Electric
|
2,000
|
|
|
93
|
National
T-32
|
8,000
|
Mechanical
|
500
|
|
|
96
|
Ideco
H-35
|
8,000
|
Mechanical
|
400
|
|
The Company
also sold to Challenger four drilling rigs and ancillary
equipment. The sales price of $12,990 consisted of $1,950 in cash,
installment receivable of $1,500 and a term note of $9,540. During
the second quarter of 2009, the Company and Challenger agreed to reduce the
installment receivable and term note by approximately $5,040 and the Company
assumed ownership of two drilling rigs that were originally sold to
Challenger. The term note bears interest at 8.5%. Interest
and principal payments of $529 on the note are due quarterly until maturity at
February 2, 2011. The note receivable is collateralized by the assets
sold to Challenger. The note receivable from Challenger at December
31, 2009 was $2,517, of which $2,000 was classified as current and $517 was
classified as long-term.
The Company
recorded a net gain of $3,138 for the year ended December 31, 2008 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.
On February
20, 2008, the Company entered into a Management Services Agreement and Master
Services Agreement with Challenger. The Company agreed to make
available to Challenger certain employees of the Company for the purpose of
providing land drilling services, certain business consulting services and
managerial support to Challenger. The Company invoices Challenger
monthly for the services provided. The Company had accounts
receivable from Challenger of $2,499 and $3,387 at December 31, 2009 and
December 31, 2008, respectively, related to these services
provided.
At December
31, 2009, the book value of the Company’s ordinary share investment in
Challenger was $39,714. The Company’s 25% interest of the net assets of
Challenger was estimated to be $36,149. The basis difference between the
Company’s ordinary equity investment in Challenger and the Company’s 25%
interest of the net assets of Challenger primarily consists of certain property,
plant and equipment and accumulated depreciation in the amount of $3,626 and $61
respectively, at December 31, 2009. These amounts are being amortized
against the Company’s 25% interest of Challenger’s net income over the estimated
useful lives of 15 years for the property, plant and
equipment. Amortization recorded during years ended December 31, 2009
and 2008 was $1,026 and $322, respectively, which is included in the equity in
income (loss) of Challenger on the consolidated statements of
operations.
The Company
reviewed its investment in Challenger at September 30, 2009 for impairment based
on the guidance of ASC Topic 323, Investments-Equity Method and Joint
Venture, which states that a loss in value of an investment which is
other than a temporary decline should be recognized. Evidence of a loss in value
might include the absence of an ability to recover the carrying amount of the
investment or inability of the investee to sustain an earnings capacity which
would justify the carrying amount of the investment. A current fair value of an
investment that is less than its carrying amount may indicate a loss in value of
the investment. Due to the recent volatility and decline in oil and natural gas
prices, a deteriorating global economic environment and the anticipated future
earnings of Challenger, the Company deemed it necessary to test the investment
for impairment. Fair value of the investment was estimated using a combination
of income, or discounted cash flows approach, and the market approach, which
utilizes comparable companies’ data. The analysis resulted in a fair value of
$39,800 related to our investment in Challenger, which was below the carrying
value of the investment and resulted in a non-cash impairment charge in the
amount of $21,247.
On February
16, 2009, Challenger entered into a financing agreement with Natixis
SA. The Company’s 25% interest in Challenger was pledged as
collateral as part of this agreement.
Summarized
financial information of Challenger is presented below:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Condensed
statement of operations:
|
||||||||
|
Revenues
|
$ | 56,509 | $ | 71,840 | ||||
|
Gross
margin
|
$ | 21,076 | $ | 33,372 | ||||
|
Net
Income (loss)
|
$ | (3,552 | ) | $ | 10,076 | |||
|
Condensed
balance sheet:
|
||||||||
|
Current
assets
|
$ | 59,971 | $ | 50,837 | ||||
|
Noncurrent
assets
|
130,667 | 141,558 | ||||||
|
Total
assets
|
$ | 190,638 | $ | 192,395 | ||||
|
Current
liabilities
|
$ | 25,511 | $ | 26,944 | ||||
|
Noncurrent
liabilities
|
20,531 | 17,304 | ||||||
|
Equity
|
144,596 | 148,147 | ||||||
|
Total
liabilities and equity
|
$ | 190,638 | $ | 192,395 | ||||
On September
18, 2009, the Company and Saddleback Properties LLC, a wholly-owned subsidiary
of the Company, entered into a Membership Interest Purchase Agreement with Carso
Infraestructura y Construccion, S.A.B. de C.V., or CICSA, pursuant to which
CICSA purchased 60% of the outstanding membership interests of Bronco MX.
The Company owns the remaining 40% of the outstanding membership interests of
Bronco MX. Immediately prior to the sale of the membership interests
in Bronco MX to CICSA, the Company contributed six drilling rigs (Nos. 4,
43, 53, 58, 60 and 72), and the future net profit from rig leases
relating to three additional drilling rigs (Nos. 55, 76 and 78), which
the Company has contributed to Bronco MX upon the expiration of the
leases relating to such rigs. The general specifications of the contributed rigs
are as follows:
|
Rig
|
Design
|
Approximate
Drilling Depth (ft)
|
Type
|
Horsepower
|
|
|
43
|
Gardner
Denver 800
|
15,000
|
Mechanical
|
1,000
|
|
|
4
|
Skytop
Brewster N46
|
14,000
|
Mechanical
|
950
|
|
|
53
|
Skytop
Brewster N42
|
12,000
|
Mechanical
|
850
|
|
|
55
|
Oilwell
660
|
12,000
|
Mechanical
|
1,000
|
|
|
58
|
National
N55
|
12,000
|
Mechanical
|
800
|
|
|
60
|
Skytop
Brewster N46
|
14,000
|
Mechanical
|
850
|
|
|
72
|
Skytop
Brewster N42
|
10,000
|
Mechanical
|
750
|
|
|
76
|
National
N55
|
12,000
|
Mechanical
|
700
|
|
|
78
|
Seaco
1200
|
12,000
|
Mechanical
|
1,200
|
|
Bronco MX is
jointly managed, with CICSA having three representatives on its board of
managers and the Company having two representatives on its board of
managers. The Company and CICSA, and their respective affiliates,
have agreed to conduct all future land drilling and workover rig services,
rental, construction, refurbishment, transportation, trucking and mobilization
in Mexico and Latin America exclusively through Bronco MX, subject to Bronco
MX’s ability to perform.
According to
a Schedule 13D/A filed with the SEC on March 8, 2010 by Carlos Slim Helú,
certain members of his family and affiliated entities, collectively these
individuals and entities owned approximately 19.99% of our common stock. CICSA
is also a Slim affiliate.
Summarized
financial information of Bronco MX is presented below:
|
December
31,
|
||||
|
2009
|
||||
|
Condensed
statement of operations:
|
||||
|
Revenues
|
$ | 7,171 | ||
|
Gross
margin
|
$ | (2,582 | ) | |
|
Net
Income (loss)
|
$ | (1,472 | ) | |
|
Condensed
balance sheet:
|
||||
|
Current
assets
|
$ | 8,931 | ||
|
Noncurrent
assets
|
57,746 | |||
|
Total
assets
|
$ | 66,677 | ||
|
Current
liabilities
|
$ | 13,162 | ||
|
Noncurrent
liabilities
|
- | |||
|
Equity
|
53,515 | |||
|
Total
liabilities and equity
|
$ | 66,677 | ||
3.
Accrued liabilities
Accrued
liabilities consisted of the following at December 31, 2009 and
2008:
|
2009
|
2008
|
|||||||
|
Salaries,
wages, payroll taxes and benefits
|
$ | 623 | $ | 3,122 | ||||
|
Workers'
compensation liability
|
2,458 | 4,288 | ||||||
|
Sales,
use and other taxes
|
2,211 | 1,566 | ||||||
|
Health
insurance
|
784 | 1,773 | ||||||
|
Deferred
revenue
|
1,251 | 4,048 | ||||||
|
General
liability insurance
|
500 | - | ||||||
|
Accrued
interest
|
125 | 1,452 | ||||||
| $ | 7,952 | $ | 16,249 | |||||
4.
Long-term Debt and Warrant
Long-term
debt consists of the following:
|
December
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Notes
payable to De Lage Landen Financial Services, collateralized by
cranes,
|
||||||||
|
payable
in ninety-six monthly principal and interest installments of
$61
|
||||||||
|
Interest
on the notes ranges from 6.74% - 7.07%, repaid in March, 2009.
(1)
|
$ | - | $ | 3,234 | ||||
|
Revolving
credit facility with Fortis Capital Corp., collateralized by the Company's
assets,
|
||||||||
|
and
matures on September 29, 2013. Loans under the revolving credit
facility
|
||||||||
|
bore
interest at variable rates as defined in the credit agreement, repaid
September, 2009. (2)
|
- | 111,100 | ||||||
|
Revolving
credit facility with Banco Inbursa S.A., collateralized by the Company's
assets,
|
||||||||
|
and
matures on September 17, 2014. Loans under the revolving credit
facility
|
||||||||
|
bear
interest at variable rates as defined in the credit agreement.
(3)
|
50,545 | - | ||||||
|
Note
payable to Ameritas Life Insurance Corp., collateralized by a building,
payable
in
principal and interest installments of $14, interest on the note is 6.0%,
maturity
date
of January 1, 2021. (4)
|
1,358 | 1,442 | ||||||
|
Notes
payable to General Motors Acceptance Corporation, collateralized by
trucks,
payable
in monthly principal and interest installments of $65, repaid in March,
2009. (5)
|
- | 1,623 | ||||||
|
|
||||||||
|
Note
payable to John Deere Construction & Forestry Company, collaterized by
forklifts,
payable
in thirty-six monthly installments of $11, repaid in March, 2009
(6)
|
- | 124 | ||||||
|
Note
payable to Ford Motor Credit, collateralized by a truck, payable in
principal and interest
|
||||||||
|
installments
of $1. Interest on the note is 2.9%, repaid in March, 2009.
(7)
|
- | 24 | ||||||
| 51,903 | 117,547 | |||||||
|
Less
current installments
|
89 | 1,464 | ||||||
| $ | 51,814 | $ | 116,083 | |||||
|
(1)
|
On
December 7, 2005, January 4, 2006, and June 12, 2006, the
Company entered into Term Loan and Security Agreements with De Lage Landen
Financial Services, Inc. The loans provide for term installments in an
aggregate amount not to exceed $4,512. The proceeds of the term loans were
used to purchase four cranes. The term loans were repaid in
full on March 30, 2009.
|
|
(2)
|
On
January 13, 2006, the Company entered into a $150,000 revolving credit
facility with Fortis Capital Corp., as administrative agent, lead arranger
and sole book runner, and a syndicate of lenders. On September
29, 2008, the Company amended and restated this revolving credit
facility. This $150,000 amended and restated credit facility
was with Fortis Bank SA/NV, New York Branch, as administrative agent,
joint lead arranger and sole bookrunner, and a syndicate of lenders, which
included The Royal Bank of Scotland plc, The CIT Group/Business Credit,
Inc., The Prudential Insurance Company of America, Legacy Bank, Natixis
and Caterpillar Financial Services Corporation. Loans under the
revolving credit facility bore interest at LIBOR plus a 4.0% margin or, at
our option, the prime rate plus a 3.0% margin. The
Company incurred $3,501 in debt issue costs related to the amended and
restated credit facility.
The revolving credit facility also provided 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 years ended
December 31, 2009 and 2008 were $447 and $405, respectively.
The revolving credit facility was repaid in full on
September 18, 2009. The Company incurred a loss from early
extinguishment of debt of approximately
$2,859.
|
|
(3)
|
On
September 18, 2009, the Company entered into a new senior secured
revolving credit facility with Banco Inbursa, as lender and as the issuing
bank. The Company utilized (i) borrowings under the credit
facility, (ii) proceeds from the sale of the membership interest of Bronco
MX and (iii) cash-on-hand to repay all amounts outstanding under the
Company's prior revolving credit agreement with Fortis Bank SA/NV, New
York Branch which has been replaced by this credit
facility.
|
|
|
The
credit facility provides for revolving advances of up to $75,000 and
matures on September 17, 2014. The borrowing base under
the credit facility has been initially set at $75,000, subject to
borrowing base limitations. Our availability under the credit
facility is reduced by outstanding letters of credit which were
approximately $11.5 million at December 31, 2009. Outstanding borrowings
under the credit facility bear interest at the Eurodollar rate plus 5.80%
per annum, subject to adjustment under certain
circumstances. The effective interest rate was 6.50% at
December 31, 2009. The Company incurred $2,232 in debt issue costs related
to this credit facility.
|
|
|
The
Company will pay a quarterly commitment fee of 0.5% per annum on the
unused portion of the credit facility and a fee of 1.50% for each letter
of credit issued under the facility. In addition, an upfront fee equal to
1.50% of the aggregate commitments under the credit facility was paid by
the Company at closing. The Company’s domestic subsidiaries have
guaranteed the loans and other obligations under the credit facility. The
obligations under the credit facility and the related guarantees are
secured by a first priority security interest in substantially all of the
assets of the Company and its domestic subsidiaries, including the equity
interests of the Company’s direct and indirect subsidiaries. Commitment
fees expense for the year ended December 31, 2009 was
$15.
|
|
|
The
credit facility contains customary representations and warranties and
various affirmative and negative covenants, including, but not limited to,
covenants that restrict the Company’s ability to make capital
expenditures, incur indebtedness, incur liens, dispose of property, repay
debt, pay dividends, repurchase shares and make certain acquisitions, and
a financial covenant requiring that the Company maintain a ratio of
consolidated debt to consolidated earnings before interest, taxes,
depreciation and amortization as defined in the credit agreement for
any four consecutive fiscal quarters of not more than 3.5 to
1.0. On February 9, 2010, the Company received a waiver from
Banco Inbursa for the ratio of consolidated debt to consolidated earnings
before interest, taxes, depreciation and amortization through the second
quarter of 2010. A violation of these covenants or any other
covenant in the credit facility could result in a default under the credit
facility which would permit the lender to restrict the Company’s ability
to access the credit facility and require the immediate repayment of any
outstanding advances under the credit facility.
|
|
|
In
conjunction with its entry into the credit facility, the Company entered
into a Warrant Agreement with Banco Inbursa and, pursuant
thereto, issued a three-year warrant (the “Warrant”) to Banco
Inbursa evidencing the right to purchase up to 5,440,770
shares of the Company’s common stock, $0.01 par value per share (the
“Common Stock”) subject to the terms and conditions set forth in the
Warrant, including the limitations on exercise set forth
below, at an exercise price of $6.50 per share of Common Stock from
the date of issuance of the Warrant (the “Issue Date”) through the
first anniversary of the Issue Date, $7.00 per share following the
first anniversary of the Issue Date through the second anniversary of the
Issue Date, and $7.50 per share following the second anniversary of the
Issue Date through the third anniversary of the Issue Date. The Warrant
may be exercised by the payment of the exercise price in cash or
through a cashless exercise whereby the Company withholds shares issuable
under the Warrant having a value equal to the aggregate exercise
price.
|
|
|
The
exercise price per share and the number of shares of Common Stock for
which the Warrant may be exercised are subject to adjustment in the event
of any split, subdivision, reclassification, combination or similar
transactions affecting the Common Stock. Additionally, in the
event that the Warrant is sold and the proceeds per share received by the
holder are less than the positive difference of the current market price
per share of the Common Stock less the exercise price then in effect, the
Company will be required to pay the seller of the Warrant a make-whole
payment equal to such difference. However, the obligations of the
Company in respect of the make-whole payment only inure to the benefit of
Banco Inbursa and other members of the Investor Group (as defined in the
Warrant), and not other holders of the
Warrant.
|
|
|
The
Warrant contains limitations on the number of shares of Common Stock that
may be acquired by the holder of the Warrant upon any exercise of the
Warrant. Pursuant to the terms of the Warrant, the holder of the
Warrant may not exercise the Warrant for a number of shares of Common
Stock which will exceed 19.99% of the shares of the Common Stock that
are issued and outstanding on the Issue Date (subject to adjustment for
stock splits, combinations and similar events). In addition, the
number of shares that may be acquired by the holder of the Warrant
and its Affiliates (as defined in the Warrant) and any other Person (as
defined in the Warrant) whose ownership of Common Stock would be
aggregated with the ownership of the holder of the
Warrant for purposes of Section 13(d) of the Securities Exchange
Act of 1934, as amended, does not exceed 19.99% of the total number
of shares of Common Stock that are outstanding immediately after
giving effect to such exercise of the
Warrant.
|
|
|
In
accordance with accounting standards, the proceeds from the revolving
credit facility were allocated to the credit facility and Warrant based on
their respective fair values. Based on this allocation, $50,321
and $4,679 of the net proceeds were allocated to the credit facility and
Warrant, respectively. The Warrant has been classified as a
liability on the consolidated balance sheet due to the Company’s
obligation to pay the seller of the Warrant a make-whole payment, in cash,
under certain circumstances. The fair value of the Warrant was
determined using a pricing model based on a version of the Black Scholes
model, which is adjusted to account for the dilution resulting from the
additional shares issued for the Warrant. The valuation was
determined by computing the value of the Warrant if exercised in Year 1 –
3 with the values weighted by the probability that the warrant would
actually be exercised in that year. Some of the assumptions
used in the model were a volatility of 45% and a risk free interest rate
that ranged from 0.41% to 1.57%.
|
|
|
The
resulting discount to the revolving credit facility will be amortized to
interest expense over the term of the revolving credit facility such that,
in the absence of any conversions, the carrying value of the revolving
credit facility at maturity would be equal to
$55,000. Accordingly, the Company will recognize annual
interest expense on the debt at an effective interest rate of Eurodollar
rate plus 6.25%. Imputed interest expense recognized for the
year ended December 31, 2009 was
$224.
|
|
|
In
accordance with accounting standards, the Company revalued the Warrant as
of December 31, 2009 and recorded the change in the fair value of the
Warrant on the consolidated statement of operations. The fair
value of the Warrant was determined using a pricing model based on a
version of the Black Scholes model, which is adjusted to account for the
dilution resulting from the additional shares issued for the
Warrant. The valuation was determined by computing the value of
the Warrant if exercised in Year 1 – 3 with the values weighted by the
probability that the Warrant would actually be exercised in that
year. Some of the assumptions used in the model were a
volatility of 45% and a risk free interest rate that ranged from 0.40% to
1.45%. The fair value of the warrant was $2,829 at December 31,
2009. The Company recorded a change in the fair value of the
Warrant on the consolidated statement of operations in the amount of
$1,850 for the year ended December 31,
2009.
|
|
|
In
conjunction with the issuance of the Warrant, the Company entered into a
Registration Rights Agreement for the benefit of Banco Inbursa and
its permitted assignees and transferees. The Registration
Rights Agreement provides for up to three demand registration rights and
unlimited piggyback registration rights covering the Warrant, the shares
of Common Stock for which the Warrant is exercisable and all other shares
of Common Stock held by Banco Inbursa and its permitted assignees and
transferees. The Registration Rights Agreement provides that
the Company shall pay all fees and expenses incident to the performance of
its obligations under the Registration Rights Agreement, including the
payment of all filing, registration and qualification fees, printers’ and
accounting fees, and expenses and disbursements of counsel and contains
other customary terms, provisions and covenants for agreements of this
type, including, without limitation, provisions requiring the Company to
provide indemnification arising out of or relating to any untrue or
alleged untrue statement of a material fact, or relating to any omission
or alleged omission of a material fact required to be stated therein to
make the statements therein not misleading, contained in a registration
statement, prospectus, free writing prospectus or certain other
documents.
|
|
|
Banco
Inbursa subsequently transferred the Warrant to CICSA. Pursuant
to the terms of the Warrant, we cancelled the Warrant issued to Banco
Inbursa and issued a warrant containing the same terms and provisions to
CICSA evidencing such transfer.
|
|
(4)
|
On
January 2, 2007, the Company assumed a term loan agreement with Ameritas
Life Insurance Corp. related to the acquisition of a
building. The loan provides for term installments in an
aggregate not to exceed
$1,590.
|
|
(5)
|
On
various dates during 2007 and 2008, the Company entered into term loan
agreements with General Motors Acceptance Corporation. The
loans provide for term installments in an aggregate not to exceed
$2,282. The proceeds of the term loans were used to purchase 57
trucks. The term loans were repaid in full on March 16,
2009.
|
|
(6)
|
On
November 21, 2006, the Company entered into term loan agreements with John
Deere Credit. The loans provide for term installments in an
aggregate not to exceed $403. The proceeds of the term loans
were used to purchase two forklifts. The term loans were repaid
in full on March 19, 2009.
|
|
(7)
|
On
November 9, 2007, the Company entered into a term loan agreement with Ford
Credit. The loan provides for a term installment in an
aggregate not to exceed $36. The proceeds of the term loan were
used to purchase a truck. The term loan was repaid in full on
March 24, 2009.
|
-41-
Long-term
debt maturing each year subsequent to December 31, 2009 is as
follows:
|
2010
|
$ | 89 | ||
|
2011
|
94 | |||
|
2012
|
100 | |||
|
2013
|
107 | |||
|
2014
|
50,658 | |||
|
2015
and thereafter
|
855 | |||
| $ | 51,903 | |||
5. Income Taxes
The Company
adopted ASC Topic 740 on January 1, 2007. ASC Topic 740 clarifies the
accounting for uncertainty in income taxes recognized in an enterprise’s
financial statements and prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. As of December 31, 2009,
the Company had no unrecognized tax benefits. The Company is
continuing its practice of recognizing interest and/or penalties related to
income tax matters as income tax expense. As of December 31, 2009,
the tax years ended December 31, 2005 through December 31, 2008 are open for
examination by U.S. taxing authorities.
Income tax
expense (benefit) consists of the following:
|
|
Years
Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
|
|
|
|
|||||||||
|
Current:
|
||||||||||||
|
State
|
$ | 28 | $ | (165 | ) | $ | 541 | |||||
|
Federal
|
(1,420 | ) | (874 | ) | 4,915 | |||||||
|
Deferred:
|
||||||||||||
|
State
|
(2,229 | ) | (415 | ) | 1,878 | |||||||
|
Federal
|
(29,488 | ) | (3,707 | ) | 15,770 | |||||||
|
Income
tax expense (benefit)
|
$ | (33,109 | ) | $ | (5,161 | ) | $ | 23,104 | ||||
Deferred
income tax assets and liabilities are as follows:
|
|
Years
Ended December 31,
|
|||||||
|
|
2009
|
2008
|
||||||
|
Deferred
tax assets:
|
|
|
||||||
|
Stock
option expense
|
$ | 2,607 | $ | 3,170 | ||||
|
Alternative
minimum tax credit carryforward
|
2,225 | 2,225 | ||||||
|
Net
operating loss carryforwards
|
37,905 | 3,441 | ||||||
|
Accounts
receivable allowance
|
1,383 | 1,481 | ||||||
|
Tax
credits
|
- | 875 | ||||||
|
Employee
benefits and insurance accruals
|
303 | 488 | ||||||
|
Other
|
1,093 | 484 | ||||||
|
Total
deferred tax assets
|
45,516 | 12,164 | ||||||
|
Deferred
tax liabilities:
|
||||||||
|
Property
and equipment, principally due
|
||||||||
|
to
differences in depreciation and impairments
|
76,964 | 75,330 | ||||||
|
Other
|
64 | 64 | ||||||
|
Total
deferred tax liabilities
|
77,028 | 75,394 | ||||||
|
Net
deferred tax liabilities
|
$ | 31,512 | $ | 63,230 | ||||
The provision
for income taxes on continuing operations differs from the amounts computed by
applying the federal income tax rate of 35% to net income. The differences are
summarized as follows:
|
|
Years
Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
|
|
|
|
|||||||||
|
Expected
tax expense (benefit)
|
$ | (31,741 | ) | $ | (4,692 | ) | $ | 21,244 | ||||
|
State
income taxes (benefit)
|
(2,201 | ) | (345 | ) | 2,246 | |||||||
|
Nondeductible
officer compensation
|
121 | 330 | 98 | |||||||||
|
Nondeductible
meals and entertainment
|
19 | 68 | 45 | |||||||||
|
Stock
compensation FAS123R adjustment
|
783 | - | - | |||||||||
|
Domestic
production activities
|
- | - | (83 | ) | ||||||||
|
Goodwill
impairment
|
- | 1,125 | - | |||||||||
|
Foreign
tax credit
|
(660 | ) | (832 | ) | - | |||||||
|
Prior
year estimate adjustment
|
356 | (295 | ) | - | ||||||||
|
Other
|
214 | (520 | ) | (446 | ) | |||||||
|
|
$ | (33,109 | ) | $ | (5,161 | ) | $ | 23,104 | ||||
6. 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 $11,560 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.
Accrued expenses at December 31, 2009 and 2008 included approximately $2,458 and
$4,288, 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 $125 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
December 31, 2009 and 2008 included approximately $784 and $1,773,
respectively, for our estimate of incurred but not reported costs related to the
self-insurance portion of our health insurance.
7.
Transactions with Affiliates
The Company
has 6 operating leases with affiliated entities. Related rent expense
was approximately $520 and $572 for the years ended December 31, 2009 and
2008.
The Company
provided contract drilling services totaling $0, $4,571, and $2,617 to
affiliated entities for the years ended December 31, 2009, 2008, and
2007. The Company provided workover services to affiliated
entities totaling $0 and $765 for the years ended December 31, 2009 and 2008,
respectively. The Company had receivables from affiliates of $9,620
and $3,387 at December 31, 2009 and 2008, respectively. Additional
information about our transactions with affiliates is included in Note 2, Equity Method
Investments.
8.
Commitments and Contingencies
The Company
leases fifteen service locations under noncancelable operating leases that have
various expirations from 2010 to 2015. Related rent expense was $1,194, $1,064,
and $790 for the years ended December 31, 2009, 2008, and 2007,
respectively.
Aggregate
future minimum lease payments under the noncancelable operating leases for years
subsequent to December 31, 2009 are as follows:
|
2010
|
$ | 913 | |
|
2011
|
757 | ||
|
2012
|
535 | ||
|
2013
|
389 | ||
|
2014
|
226 | ||
|
2015
and thereafter
|
75 | ||
| $ | 2,895 | ||
Various
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.
9.
Business Segments and Concentrations
The Company’s
reportable business segments are contract land drilling and well
servicing. The contract land drilling segment utilizes a fleet of
land drilling rigs to provide contract drilling services to oil and natural gas
exploration and production companies. During 2009 our rigs operated
in Oklahoma, Texas, Colorado, Montana, Utah, North Dakota, Louisiana, Wyoming,
Pennsylvania, West Virginia and Mexico. The well servicing segment
encompasses a full range of services performed with mobile well servicing rigs,
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 2009
our workover rigs operated in Oklahoma, Texas, Kansas, Colorado, Louisiana,
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
land drilling
|
Well
servicing
|
Total
|
||||||||||
|
Year
ended December 31, 2009
|
||||||||||||
|
Operating
revenues
|
$ | 106,738 | $ | 3,799 | $ | 110,537 | ||||||
|
Direct
operating costs
|
(75,996 | ) | (4,267 | ) | (80,263 | ) | ||||||
|
Segment
profits
|
$ | 30,742 | $ | (468 | ) | $ | 30,274 | |||||
|
Depreciation
and amortization
|
$ | 39,054 | $ | 6,620 | $ | 45,674 | ||||||
|
Capital
expenditures
|
$ | 16,532 | $ | 1,027 | $ | 17,559 | ||||||
|
Identifiable
assets
|
$ | 395,891 | $ | 49,692 | $ | 445,583 | ||||||
|
Year
ended December 31, 2008
|
||||||||||||
|
Operating
revenues
|
$ | 247,829 | $ | 33,284 | $ | 281,113 | ||||||
|
Direct
operating costs
|
(148,866 | ) | (24,478 | ) | (173,344 | ) | ||||||
|
Impairments
of goodwill
|
$ | (21,115 | ) | $ | (3,213 | ) | $ | (24,328 | ) | |||
|
Segment
profits
|
$ | 77,848 | $ | 5,593 | $ | 83,441 | ||||||
|
Depreciation
and amortization
|
$ | 44,419 | $ | 5,969 | $ | 50,388 | ||||||
|
Capital
expenditures
|
$ | 79,136 | $ | 8,138 | $ | 87,274 | ||||||
|
Identifiable
assets
|
$ | 551,575 | $ | 60,779 | $ | 612,354 | ||||||
The following
table reconciles the segment profits above to the operating income as reported
in the consolidated statements of operations:
|
Year
Ended
|
||||||||
|
|
December
31, 2009
|
December
31, 2008
|
||||||
|
Segment
profits
|
$ | 30,274 | $ | 83,441 | ||||
|
General
and administrative expenses
|
(19,777 | ) | (33,771 | ) | ||||
|
Depreciation
and amortization
|
(45,674 | ) | (50,388 | ) | ||||
|
Gain
on Challenger transactions
|
- | 3,138 | ||||||
|
Loss
on Mexico transactions
|
(23,705 | ) | - | |||||
|
Operating
income (loss)
|
$ | (58,882 | ) | $ | 2,420 | |||
|
|
||||||||
For the year
ended December 31, 2009, revenue from one customer was approximately 12% of
total revenue, for 2008 revenue from one customer was approximately 11% of total
revenue, and for 2007 revenue from one customer was approximately 11% of total
revenue. At December 31, 2009, seven customers accounted for
approximately 16%, 10%, 10%, 6%, 6%, 5%, and 5% of accounts
receivable. At December 31, 2008, six customers accounted for
approximately 8%, 7%, 5%, 5%, 5%, and 5% of accounts receivable.
Financial
instruments, which potentially subject the Company to concentrations of credit
risk, consist primarily of demand deposits, temporary cash investments and trade
receivables.
The Company
believes it has placed its deposits and temporary cash investments with high
credit-quality financial institutions. At December 31, 2009 and 2008,
the Company’s demand deposits and temporary cash investments consisted of the
following (in thousands):
|
2009
|
2008
|
|||||||
|
Deposits
in FDIC-insured institutions under insurance limits
|
$ | 1,084 | $ | 905 | ||||
|
Deposits
in FDIC-insured institutions over insurance limits
|
9,576 | 30,082 | ||||||
|
Deposits
in foreign banks
|
47 | 281 | ||||||
| 10,707 | 31,268 | |||||||
|
Less
outstanding checks and other reconciling items
|
(1,210 | ) | (4,592 | ) | ||||
|
Cash
and cash equivalents
|
$ | 9,497 | $ | 26,676 | ||||
10.
Net Income (Loss) 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 ASC Topic 260:
|
Year
Ended
|
||||||||||||
|
December
31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Basic:
|
||||||||||||
|
Net
income (loss)
|
$ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
|
Weighted
average shares (thousands)
|
26,651 | 26,293 | 25,996 | |||||||||
|
Income
(loss) per share
|
$ | (2.16 | ) | $ | (0.31 | ) | $ | 1.45 | ||||
|
Diluted:
|
||||||||||||
|
Net
income (loss)
|
$ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | ||||
|
Weighted
average shares:
|
||||||||||||
|
Outstanding
(thousands)
|
26,651 | 26,293 | 25,996 | |||||||||
|
Restricted
Stock and Options (thousands)
|
- | - | 105 | |||||||||
| 26,651 | 26,293 | 26,101 | ||||||||||
|
Income
(loss) per share
|
$ | (2.16 | ) | $ | (0.31 | ) | $ | 1.44 | ||||
11.
Fair Value Measurements
Fair
Value Measurements
As defined in
ASC 820, Fair value is defined as the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (referred to as an "exit price").
Authoritative guidance on fair value measurements and disclosures clarifies that
a fair value measurement for a liability should reflect the entity's
non-performance risk. In addition, a fair value hierarchy is established that
prioritizes the inputs to valuation techniques used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted market prices in
active markets for identical assets and liabilities (Level 1 measurements) and
the lowest priority to unobservable inputs (Level 3 measurements). The three
levels of the fair value hierarchy are:
Level
1: Unadjusted
quoted prices in active markets that are accessible at the measurement date for
identical, unrestricted assets or liabilities.
Level
2: Quoted prices
in markets that are not active, or inputs which are observable, either directly
or indirectly, for substantially the full term of the asset or liability. This
category includes quoted prices for similar assets or liabilities in active
markets; quoted prices for identical or similar assets or liabilities in markets
that are not active; inputs other than quoted prices that are observable for the
asset or liability; and inputs that are derived principally from or corroborated
by observable market data by correlation or other means.
Level
3: Measured based
on prices or valuation models that require inputs that are both significant to
the fair value measurement and less observable from objective
sources.
Fair
Value on Recurring Basis
The Company
issued a Warrant in conjunction with its revolving credit facility with Banco
Inbursa. In accordance with accounting standards, the Company
revalued the Warrant as of December 31, 2009 and recorded the change in the fair
value of the Warrant on the consolidated statement of operations. The
fair value of the Warrant was determined using level 3 inputs. The
Company used a pricing model based on a version of the Black Scholes model,
which is adjusted to account for the dilution resulting from the additional
shares issued for the Warrant. The valuation was determined by
computing the value of the Warrant if exercised in Year 1 – 3 with the values
weighted by the probability that the Warrant would actually be exercised in that
year. Some of the assumptions used in the model were a volatility of
45% and a risk free interest rate that ranged from 0.36% to
1.38%. The fair value of the Warrant was $2,829 at December 31,
2009. The Company recorded a change in the fair value of the Warrant
on the consolidated statement of operations in the amount of $1,850 for the year
ended December 31, 2009.
Fair
Value on Non-Recurring Basis
On January 1,
2009, the Company adopted the provisions of ASC 820 for nonfinancial assets and
liabilities measured at fair value on a non-recurring basis. Certain
assets and liabilities are reported at fair value on a nonrecurring basis in the
Company’s consolidated balance sheets. The Company reviews its long-lived assets
to be held and used, including property plant and equipment and its investments
in Challenger and Bronco MX, whenever events or circumstances indicate that the
carrying value of those assets may not be recoverable.
Due to the
recent volatility and decline in oil and natural gas prices, a deteriorating
global economic environment and the anticipated future earnings of Challenger,
the Company deemed it necessary to test the investment for impairment. Fair
value of the investment was estimated using level three inputs based on a
combination of income, or discounted cash flows approach, and the market
approach, which utilizes comparable companies’ data. The analysis resulted in a
fair value of $39,800 related to our investment in Challenger as stated in other
assets on the Company’s consolidated balance sheet, which was below the carrying
value of the investment and resulted in a non-cash impairment charge in the
amount of $21,247.
The fair
value of the Company’s 40% investment in Bronco MX as of September 18, 2009, was
estimated using level three inputs based upon a combination of income, or
discounted cash flows approach, the market approach, which utilizes pricing of
third-party transactions of comparable businesses or assets and the cost
approach which considers replacement cost as the primary indicator of value. The
analysis resulted in a fair value of $21,495 related to the Company’s 40%
retained interest in Bronco MX as stated in other assets on the Company’s
consolidated balance sheet.
12.
Restricted Stock
The Company’s
board of directors and a majority of our stockholders approved our 2006 Stock
Incentive Plan, which the Company refers to as the 2006 Plan, effective
April 20, 2006. 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 our 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 purpose
of the plan is 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 our long range success and to provide incentives that are
linked directly to increases in share value that will inure to the benefit of
our stockholders.
Eligible
award recipients are employees, consultants and directors of the Company and its
affiliates. Incentive stock options may be granted only to our employees. Awards
other than incentive stock options may be granted to employees, consultants and
directors. The shares that may be issued pursuant to awards consist of our
authorized but unissued common stock, and the maximum aggregate amount of such
common stock that may be issued upon exercise of all awards under the plan,
including incentive stock options, may not exceed 2,500,000 shares, subject
to adjustment to reflect certain corporate transactions or changes in our
capital structure.
Under all
restricted stock awards to date, nonvested shares are subject to forfeiture for
failure to fulfill service conditions. Restricted stock awards
consist of our common stock that vest over a two year period. Total
shares available for future stock option grants and restricted stock grants to
employees and directors under existing plans were
1,290,871. 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 years ended December 31, 2009, 2008 and 2007 related to shares of
restricted stock was $3,301, $5,825 and $2,699, respectively. On
April 20, 2007, the Company filed a tender Offer Statement on Schedule TO
relating to the Company's offer to 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 stock. 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. Compensation
expense for the year ended December 31, 2007 related to stock options was
$1,029. Restricted stock activity for the years ended December 31, 2009, 2008
and 2007 was as follows:
|
Weighted
Average
|
||||||||
|
Grant
Date
|
||||||||
|
Shares
|
Fair
Value
|
|||||||
|
Outstanding
at December 31, 2006
|
66,667 | $ | 20.25 | |||||
|
Granted
|
125,000 | 15.47 | ||||||
|
Converted
|
384,500 | 16.58 | ||||||
|
Vested
|
(22,222 | ) | 20.25 | |||||
|
Forfeited/expired
|
(500 | ) | 16.69 | |||||
|
Outstanding
at December 31, 2007
|
553,445 | $ | 16.64 | |||||
|
Granted
|
232,874 | 13.98 | ||||||
|
Vested
|
(321,889 | ) | 16.36 | |||||
|
Forfeited/expired
|
(750 | ) | 16.69 | |||||
|
Outstanding
at December 31, 2008
|
463,680 | $ | 15.22 | |||||
|
Granted
|
415,955 | 5.28 | ||||||
|
Vested
|
(375,037 | ) | 13.86 | |||||
|
Outstanding
at December 31, 2009
|
504,598 | $ | 7.67 | |||||
13.
Fair Value of Financial Instruments
Cash
and cash equivalents, trade receivables and payables and short-term
debt:
The carrying
amounts of our cash and cash equivalents, trade receivables, payables and
short-term debt approximate their fair values due to the short-term nature of
these instruments.
Long-term
debt
The carrying
amount of our long-term debt approximates its fair value, as supported by the
recent issuance of the debt and because the rates and terms currently available
to us approximate the rates and terms of the existing debt.
14.
Employee Benefit Plans
The Company
implemented a 401(k) retirement plan for its eligible employees during 2008.
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 years ended December
31, 2009, 2008 and 2007 were $628, $1,093 and $1,030, respectively.
15.
Quarterly Results of Operations (unaudited)
The following
table summarizes quarterly financial data for our years ended December 31,
2009 and 2008;
|
Bronco
Drilling Company Inc.
|
||||||||||||||||
|
Quarterly
Results
|
||||||||||||||||
|
Year
Ended December 31, 2009
|
||||||||||||||||
|
(Amounts
in thousands except per share amounts)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Quarter
|
Quarter
|
Quarter
(1)
|
Quarter
|
|||||||||||||
|
2009
|
||||||||||||||||
|
Revenues
|
$ | 50,605 | $ | 27,518 | $ | 16,233 | $ | 16,181 | ||||||||
|
Income
(loss) from operations
|
732 | (8,865 | ) | (39,248 | ) | (11,501 | ) | |||||||||
|
Income
tax expense (benefit)
|
(11 | ) | (4,108 | ) | (25,115 | ) | (3,875 | ) | ||||||||
|
Net
income (loss)
|
(1,709 | ) | (7,158 | ) | (42,654 | ) | (6,058 | ) | ||||||||
|
Income
(loss) per share:
|
||||||||||||||||
|
Basic
|
(0.06 | ) | (0.27 | ) | (1.60 | ) | (0.23 | ) | ||||||||
|
Diluted
|
(0.06 | ) | (0.27 | ) | (1.60 | ) | (0.23 | ) | ||||||||
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Quarter
|
Quarter
|
Quarter
(2)
|
Quarter
(3)
|
|||||||||||||
|
2008
|
||||||||||||||||
|
Revenues
|
$ | 67,003 | $ | 68,307 | $ | 72,920 | $ | 76,021 | ||||||||
|
Income
(loss) from operations
|
11,206 | 7,642 | (609 | ) | (15,819 | ) | ||||||||||
|
Income
tax expense (benefit)
|
4,552 | 2,655 | (60 | ) | (12,308 | ) | ||||||||||
|
Net
income (loss)
|
8,148 | 4,339 | (917 | ) | (19,813 | ) | ||||||||||
|
Income
(loss) per share:
|
||||||||||||||||
|
Basic
|
0.31 | 0.17 | (0.03 | ) | (0.75 | ) | ||||||||||
|
Diluted
|
0.31 | 0.16 | (0.03 | ) | (0.75 | ) | ||||||||||
|
(1)
Includes $21, 247 of impairment to our Challenger Investment and
$23,964 loss on Bronco MX transaction
|
||||||||||||||||
| (2) Includes $6,000 of failed merger costs. | ||||||||||||||||
|
(3)
Includes $24,328 and $14,442 of impairments of goodwill and Challenger
investment.
|
||||||||||||||||
16.
Valuation and Qualifying Accounts
The Company’s
valuation and qualifying accounts for the years ended December 31, 2009,
2008 and 2007 are as follows:
|
Valuation
and Qualifying Accounts
|
||||||||||||||||
|
Balance
|
Charged
|
|||||||||||||||
|
at
|
to
Costs
|
Deductions
|
Balance
|
|||||||||||||
|
Beginning
|
and
|
from
|
at
|
|||||||||||||
|
of
Year
|
Expenses
|
Accounts
|
Year
End
|
|||||||||||||
|
Year
ended December 31, 2007
|
||||||||||||||||
|
Allowance
for doubtful receivables
|
$ | 400 | $ | 4,370 | $ | (2,936 | ) | $ | 1,834 | |||||||
|
Year
ended December 31, 2008
|
||||||||||||||||
|
Allowance
for doubtful receivables
|
$ | 1,834 | $ | 3,745 | $ | (1,749 | ) | $ | 3,830 | |||||||
|
Year
ended December 31, 2009
|
||||||||||||||||
|
Allowance
for doubtful receivables
|
$ | 3,830 | $ | 2,134 | $ | (2,388 | ) | $ | 3,576 | |||||||
SIGNATURES
Pursuant to
the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, Bronco Drilling Company, Inc. has duly caused this Annual Report on Form
10-K to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
BRONCO DRILLING COMPANY, INC.
|
||
|
Date:
March 12, 2010
|
By:
|
/S/ D. FRANK HARRISON
|
|
D. Frank Harrison
Chief
Executive Officer
|
||
Power
of Attorney
Each of the
persons whose signature appears below hereby constitutes and appoints D. Frank
Harrison, Matthew S. Porter and Mark Dubberstein, and each of them, his true and
lawful attorneys-in-fact and agents, with full power of substitution and
resubstitution, from such person and in each person’s name, place and stead, in
any and all capacities, to sign the Form 10-K filed herewith and any and all
amendments to said Form 10-K, with all exhibits thereto and all documents in
connection therewith, with the SEC, granting unto said attorneys-in-fact and
agents, and each of them, full power and authority to do and perform each and
every act and thing requisite and necessary to be done as fully to all said
attorneys-in-fact and agents, or any of them, may lawfully do or cause to be
done by virtue thereof.
Pursuant to
the requirements of the Securities and Exchange Act of 1934, this report has
been signed below by the following persons on behalf of Bronco Drilling Company,
Inc. and in the capacities and on the dates indicated.
|
Name
|
Title
|
Date
|
|
/S/ D.
FRANK HARRISON
D.
Frank Harrison
|
Chief
Executive, President and Director
(Principal
Executive Officer)
|
March
12, 2010
|
|
/S/ Matthew S. Porter
Matthew
S. Porter
|
Chief
Financial Officer
(Principal
Accounting and Financial Officer)
|
March
12, 2010
|
|
/S/ David
House
David
House
|
Director
|
March
12, 2010
|
|
/S/ DAVID L. HOUSTON
David
L. Houston
|
Director
|
March
12, 2010
|
|
/S/ GARY
HILL
Gary
Hill
|
Director
|
March
12, 2010
|
|
/S/ WILLIAM R. SNIPES
William
R. Snipes
|
Director
|
March
12, 2010
|