Attached files
file | filename |
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EX-21.1 - EXHIBIT 21.1 - Bronco Drilling Company, Inc. | c14033exv21w1.htm |
EX-23.1 - EXHIBIT 23.1 - Bronco Drilling Company, Inc. | c14033exv23w1.htm |
EX-31.1 - EXHIBIT 31.1 - Bronco Drilling Company, Inc. | c14033exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - Bronco Drilling Company, Inc. | c14033exv32w1.htm |
EX-32.2 - EXHIBIT 32.2 - Bronco Drilling Company, Inc. | c14033exv32w2.htm |
EX-31.2 - EXHIBIT 31.2 - Bronco Drilling Company, Inc. | c14033exv31w2.htm |
Table of Contents
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
or
o | 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 (State or Other Jurisdiction of Incorporation or Organization) |
20-2902156 (I.R.S. Employer Identification No.) |
|
16217 North May Avenue, Edmond, OK (Address of Registrants Principal Executive Offices) |
73013 (Zip Code) |
(405) 242-4444
(Registrants telephone number, including area code)
(Registrants 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
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes o No þ
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 o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark 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 registrants 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. þ
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 o | Accelerated Filer þ | Non-Accelerated Filer o | Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
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, 2010) was approximately $89,317,224.
As of February 28, 2011, 28,800,059 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 2011 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, 2010.
BRONCO DRILLING COMPANY, INC.
INDEX
INDEX
Form | ||||||||
10-K | ||||||||
Item | Report | |||||||
No. | Page | |||||||
3 | ||||||||
PART I |
||||||||
1. | 3 | |||||||
1A. | 13 | |||||||
1B. | 22 | |||||||
2. | 22 | |||||||
3. | 22 | |||||||
4. | 22 | |||||||
PART II |
||||||||
5. | 23 | |||||||
6. | 24 | |||||||
7. | 26 | |||||||
7A. | 41 | |||||||
8. | 41 | |||||||
9. | 41 | |||||||
9A. | 41 | |||||||
9B. | 43 | |||||||
PART III |
||||||||
10. | 44 | |||||||
11. | 44 | |||||||
12. | 44 | |||||||
13. | 44 | |||||||
14. | 44 | |||||||
PART IV |
||||||||
15. | 45 | |||||||
Exhibit 21.1 | ||||||||
Exhibit 23.1 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
2
Table of Contents
Cautionary Note Regarding Forward-Looking Statements
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,
managements 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 Managements 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.
PART I
Item 1. | Business |
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 services to 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 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 building,
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 2010.
In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to build,
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 building and refurbishment programs.
Additionally, we have exposure to the international drilling market through a 20% equity
investment in Bronco Drilling MX S.A. de C.V., a company organized under the laws of Mexico, or
Bronco MX. Bronco MX provides contract land drilling services and leases land drilling rigs to
Petroleos Mexicanos, or PEMEX, and/or companies contracted with PEMEX. We also have a 25% equity
investment in Challenger Limited, a company organized under the laws of the Isle of Man, or
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.
We currently conduct our operations through one operating segment: contract land drilling. In
June of 2009 we made the decision to suspend operations in our well servicing segment because of
deteriorating market conditions resulting from the decrease in oil
and natural gas prices that began in the
third quarter of 2008, as well as the inability of many customers to obtain financing related to
their drilling and workover programs.
3
Table of Contents
Through the second quarter of 2010, we explored alternatives to restructure the well servicing
segment. During Q1 and Q2 2010 the market for workover services continued at depressed levels
within our primary geographic well servicing market (Oklahoma). Late in Q2 2010, we determined that
higher NPV projects were available within our drilling segment and chose to deploy capital in this
segment rather than commit the capital required to restructure operations in the well servicing
segment.
In late June 2010 we made a decision to market the assets constituting the well servicing
segment for sale and redeploy the proceeds to reduce debt and to support our drilling segment. We
have presented all well servicing operating results as discontinued operations in our Consolidated
Statements of Operations for all periods presented. In September 2010, substantially all of the
assets of the well servicing segment were sold at auction to multiple bidders. We used the
proceeds to pay down existing indebtedness under our revolving credit facility.
In September and November 2010, we sold at auction in separate lots to multiple bidders two
complete mechanical drilling rigs and components comprising six other drilling rigs (rigs 2, 9, 51,
52, 54, 70, 75 and 94), and ancillary equipment. The mechanical drilling rigs and equipment sold
at auction were not being utilized currently in our business. In an unrelated transaction on
September 23, 2010, we sold two mechanical drilling rigs (rigs 41 and 42) in a private sale to
Windsor Permian LLC, an unaffiliated third party. On November 29, 2010, the Company sold two
mechanical drilling rigs (rigs 5 and 7) in a private sale to Atlas Drilling, LLC, an unaffiliated
third party.
We made the decision in the third quarter to sell an additional mechanical drilling rig (rig
6). We anticipate closing this transaction in the second quarter of 2011.
In February 2011, we entered into a contract to sell two drilling rigs (rigs 56 and 62) to
Windsor Permian LLC, an unaffiliated third party. The drilling rigs and related equipment sold at
auction and held for sale are being sold as part of a broader strategy by management to divest of
older drilling rigs and use the proceeds to pay down existing indebtedness.
The drilling rigs and related equipment sold at auction and held for sale are being sold as part of our broader strategy
to divest of older mechanical drilling rigs and use the proceeds to pay down existing indebtedness
and invest in next generation drilling equipment.
The following is a description of our operating segment.
Contract Land Drilling Our contract land drilling segment provides contract land drilling
services. As of February 28, 2011, we owned a fleet of 25 operating land drilling rigs. We
currently operate our drilling rigs in Oklahoma, Texas, Pennsylvania, West Virginia and North
Dakota. 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 25 operating drilling rigs range from 650 to 2,000
horsepower. Accordingly, such rigs can 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 and are frequently utilized in unconventional resource plays. We believe
our premium rig fleet, inventory and experienced crews position us to benefit from the oil and
natural gas drilling activity in our core operating areas.
Our Acquisitions
The following table summarizes completed acquisitions in which we acquired rigs and rig
related equipment since June 2001:
Purchase | Number of Land Drilling | |||||||||||
Date | Acquisition | Price | /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 |
4
Table of Contents
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 deployed
seventeen of the rigs beginning in 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., 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., 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 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 |
5
Table of Contents
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:
Approximate | ||||||||||||||||
Drilling Depth | ||||||||||||||||
Rig | Design | (ft) | Type | Horsepower | ||||||||||||
91 |
Ideco H-35 | 8,000 | Mechanical | 450 | ||||||||||||
95 |
Emsco GB800 | 12,000 | Mechanical | 1,000 |
We review our investment in Challenger 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 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 during 2008,
2009 and 2010. 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 non-cash impairment
charge in the amount of $14.4 million in 2008. The analysis resulted
in a fair value of $39.8 million related to our investment in
Challenger at September 30, 2009, which was below the
carrying value of the investment and resulted in a non-cash impairment charge in the amount of
$21.2 million. The analysis resulted in no impairment charge at
December 31, 2010
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 owned 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 for three additional
drilling rigs, which the Company contributed to Bronco MX upon the expiration of the leases for
such rigs. The general specifications of the 9 nine contributed rigs are as follows:
Approximate | ||||||||||||||||
Drilling Depth | ||||||||||||||||
Rig | Design | (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 |
In July, 2010, CICSA contributed cash of approximately $45.1 million in exchange for
735,356,219 shares of Bronco MX.
The cash contributed was used to purchase five drilling rigs.
As a result of the contribution, our membership interest in
Bronco MX was decreased to approximately 20%.
Bronco MX is managed by CICSA having four representatives on its board of managers and the
Company having one representative 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 MXs ability to perform.
6
Table of Contents
Overview of Our Operating Segment
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 rigs 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, 2011, our drilling rig fleet consisted of 25 operating drilling rigs, 20 of
which were operating on term contracts with a term of more than one well or a stated period of
time. Eighteen 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, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Average number of operating drilling rigs |
33 | 44 | 44 | |||||||||
Revenue days |
7,450 | 5,699 | 12,712 | |||||||||
Utilization Rates |
62 | % | 36 | % | 79 | % |
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.
7
Table of Contents
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. We have not historically entered into turnkey
contracts; however, we may decided 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 20 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, usually upon payment of an agreed fee. During 2009, we recorded $7.9 million of contract
drilling revenue related to terminated contracts. During 2010, we recorded no 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, 2010, 2009 and 2008.
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Daywork Contracts |
163 | 152 | 378 | |||||||||
Footage Contracts |
| | | |||||||||
Turnkey Contracts |
| | | |||||||||
Total |
163 | 152 | 378 | |||||||||
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.
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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.
Customers and Marketing
We market our drilling 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.
Total Revenue | ||||
Customer | Percentage | |||
2010 |
||||
Petro-Hunt LLC |
11 | % | ||
EOG Resources Inc |
10 | % | ||
Whiting Petroleum |
9 | % | ||
Antero Resources |
8 | % | ||
Anschutz Exploration |
7 | % | ||
Zenergy Inc |
7 | % | ||
Beusa Energy Inc |
7 | % | ||
Comstock Oil and Gas |
6 | % | ||
Hunt Oil Company |
5 | % | ||
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 | % |
We primarily market our drilling 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.
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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, Cactus Drilling Company, L.L.C. 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. |
Raw Materials
The materials and
supplies we use in our drilling operations include fuels to
operate our drilling, 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. |
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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 $1.0 million deductible on stacked drilling
rigs and the greater of 3.0% of total insured value or $500,000 for
operating 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, 2011, we had 686 employees. Approximately, 100 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. 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.
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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 expanded 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 FCPAs 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.
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Item 1A. | Risk Factors |
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 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 customers 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 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 rigs and adversely affect our operating results.
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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 was 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 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: |
||||||||||||||||
Fourth |
$ | 4.61 | $ | 3.29 | $ | 91.51 | $ | 79.49 | ||||||||
Third |
$ | 4.92 | $ | 3.65 | $ | 82.55 | $ | 71.63 | ||||||||
Second |
$ | 5.19 | $ | 3.91 | $ | 86.79 | $ | 68.01 | ||||||||
First |
$ | 6.01 | $ | 3.84 | $ | 83.76 | $ | 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.
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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 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 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, 2010, our total borrowings under our credit facility were approximately
$9.1 million and we had the ability to incur an additional $54.4 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.
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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 lenders 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.
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 19.99% 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 80% of the equity of Bronco MX, which is a joint venture in Mexico in which
we own the other 20%. 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 20% 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. We have also pledged our equity investment in Challenger to secure the
indebtedness under Challengers revolving credit facility with Natixis. In the event of default by
Challenger under its facility, Natixis could enforce the pledge of our equity investment, which
could result in the loss of our rights as an equity holder in Challenger.
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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 one 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 20% 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 MXs 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. |
Early
in 2010, there began to develop civil and political disturbances in
Libya. There continues to be political unrest in Libya and the
Middles East. We are unsure what
effects the current political instability in Libya north Africa, and the Middle East will
have on our investment in Challenger. Such instability could result in the total loss of our
investment. Our investment in Challenger was $38.7 million at
December 31, 2010.
As we expanded our operations outside of the United States, we must comply with numerous laws
and regulations relating to international business operations, including the 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 FCPAs accounting provisions.
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We operate in a highly competitive, fragmented industry in which price competition could reduce our
profitability.
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 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 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 experience of our rig crews to differentiate us from our competitors.
This strategy is less effective as lower demand for 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 which can, in turn, reduce our profitability.
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, 2010, 2009 and 2008, none 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.
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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 have historically focused on
drilling in unconventional resource plays.
A majority of our drilling contracts are with exploration and production companies in search
of oil and natural gas in unconventional resource plays. Drilling on land in resource plays
generally occurs at deeper drilling depths than drilling in conventional plays. 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 unconventional resource plays to drilling
for customers in conventional plays, a portion of our rig fleet could be disadvantaged in competing
for new conventional drilling projects as compared to competitors that primarily use shallower
drilling depth rigs when drilling in conventional plays.
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. |
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 disposal of hazardous 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. Handling, storage and
disposal of both hazardous and non-hazardous wastes are also subject to these regulatory
requirements. In addition, our operations are often conducted in or near ecologically sensitive
areas, which are subject to special protective measures and that may expose us to additional
operating costs and liabilities 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.
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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.
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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, limit our ability to build and/or
refurbish drilling rigs, 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 February 28, 2011, we had an aggregate of 63,912,927
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.
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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; |
| limitations on the ability of our stockholders to call a special meeting and
act by written consent; |
| 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.
Item 1B. | Unresolved Staff Comments |
None.
Item 2. | Property |
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 sellers 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.
Our contract land drilling segment is supported by several offices and yard facilities located
throughout this segments areas of operations, including Oklahoma, Louisiana, Texas, North Dakota
and Pennsylvania.
We own our office and yard in Duncan, Oklahoma and an 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.
Item 3. | Legal Proceedings |
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 Companys consolidated
financial position, results of operations or cash flows.
Item 4. | Reserved |
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PART II
Item 5. | Market For Registrants 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.
High | Low | |||||||
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 |
$ | 6.50 | $ | 4.60 | ||||
Second Quarter |
$ | 5.07 | $ | 3.34 | ||||
Third Quarter |
$ | 4.22 | $ | 3.40 | ||||
Fourth Quarter |
$ | 8.07 | $ | 3.95 | ||||
Year ending December 31, 2011: |
||||||||
First Quarter (through February 28) |
$ | 8.95 | $ | 6.34 |
On February 28, 2011, the last reported sale price of our common stock on The Nasdaq
Global Select Market was $8.95 and we had approximately 34 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, 2010 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 |
| $ | | 2,549,878 | ||||||||
Equity compensation plans not approved
by security holders |
| | | |||||||||
Total |
| $ | | 2,549,878 | ||||||||
(1) | As of December 31, 2010, we had no options to purchase shares of our common stock
outstanding. As of December 31, 2010, we had issued 2,470,746 shares of our restricted stock under
our 2006 Stock Incentive 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 our 2005 Stock Incentive
Plan. |
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Item 6. | Selected Financial Data. |
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 2010, 2009, 2008, 2007 and 2006 from our historical audited consolidated financial
statements. You should review this information together with Managements 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.
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Years Ended December 31, | ||||||||||||||||||||
(in thousands, except per share amounts) | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
Consolidated Statements of Operations
Information: |
||||||||||||||||||||
Contract drilling revenues |
$ | 124,399 | $ | 102,896 | $ | 233,922 | $ | 257,409 | $ | 270,322 | ||||||||||
Costs and expenses: |
||||||||||||||||||||
Contract drilling |
90,290 | 70,721 | 140,935 | 139,693 | 128,287 | |||||||||||||||
Depreciation and amortization |
28,445 | 36,180 | 39,194 | 34,989 | 27,192 | |||||||||||||||
General and administrative |
17,108 | 15,782 | 29,821 | 19,604 | 17,027 | |||||||||||||||
Gain on Challenger transactions |
| | (2,252 | ) | | | ||||||||||||||
Loss on Bronco MX transaction |
1,487 | 23,705 | | | | |||||||||||||||
Impairment of goodwill |
| | 21,115 | | | |||||||||||||||
Impairment of drilling rigs and related equipment |
7,900 | | | | | |||||||||||||||
Loss on sale of drilling rigs and related equipment |
23,732 | | | | | |||||||||||||||
Total operating costs and expenses |
168,962 | 146,388 | 228,813 | 194,286 | 172,506 | |||||||||||||||
Income (loss) from continuing operations |
(44,563 | ) | (43,492 | ) | 5,109 | 63,123 | 97,816 | |||||||||||||
Other income (expense): |
||||||||||||||||||||
Interest expense |
(4,671 | ) | (6,933 | ) | (4,048 | ) | (5,030 | ) | (1,499 | ) | ||||||||||
Loss from early extinguishment of debt |
| (2,859 | ) | (155 | ) | | (1,000 | ) | ||||||||||||
Interest income |
201 | 273 | 1,039 | 1,237 | 164 | |||||||||||||||
Loss on partial sale of investment in Bronco MX |
(1,271 | ) | | | | | ||||||||||||||
Equity in income (loss) of Challenger |
(984 | ) | (1,914 | ) | 2,186 | | | |||||||||||||
Equity in income (loss) of Bronco MX |
22 | (588 | ) | | | | ||||||||||||||
Impairment of investment in Challenger |
| (21,247 | ) | (14,442 | ) | | | |||||||||||||
Other income (expense) |
204 | (383 | ) | (343 | ) | 285 | 408 | |||||||||||||
Change in fair value of warrant |
(1,578 | ) | 1,850 | | | | ||||||||||||||
Total other income (expense) |
(8,077 | ) | (31,801 | ) | (15,763 | ) | (3,508 | ) | (1,927 | ) | ||||||||||
Income (loss) from continuing operations before tax |
(52,640 | ) | (75,293 | ) | (10,654 | ) | 59,615 | 95,889 | ||||||||||||
Income tax expense (benefit) |
(18,135 | ) | (27,151 | ) | (5,339 | ) | 22,690 | 37,194 | ||||||||||||
Income (loss) from continuing operations |
(34,505 | ) | (48,142 | ) | (5,315 | ) | 36,925 | 58,695 | ||||||||||||
Income (loss) from discontinued operations |
(16,172 | ) | (9,437 | ) | (2,928 | ) | 667 | 1,138 | ||||||||||||
Net income (loss) |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | $ | 59,833 | |||||||
Income (loss) per common share-Basic |
||||||||||||||||||||
Continuing Operations |
$ | (1.27 | ) | $ | (1.81 | ) | $ | (0.20 | ) | $ | 1.42 | $ | 2.39 | |||||||
Discontinued Operations |
$ | (0.60 | ) | $ | (0.35 | ) | $ | (0.11 | ) | $ | 0.03 | $ | 0.04 | |||||||
Income (loss) per common share-Basic |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | $ | 1.45 | $ | 2.43 | |||||||
Income (loss) per common share-Diluted |
||||||||||||||||||||
Continuing Operations |
$ | (1.27 | ) | $ | (1.81 | ) | $ | (0.20 | ) | $ | 1.41 | $ | 2.38 | |||||||
Discontinued Operations |
$ | (0.60 | ) | $ | (0.35 | ) | $ | (0.11 | ) | $ | 0.03 | $ | 0.05 | |||||||
Income (loss) per common share-Diluted |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | $ | 1.44 | $ | 2.43 | |||||||
Weighted average number of shares outstanding-Basic |
27,091 | 26,651 | 26,293 | 25,996 | 24,585 | |||||||||||||||
Weighted average number of shares
outstanding-Diluted |
27,091 | 26,651 | 26,293 | 26,101 | 24,623 | |||||||||||||||
Other Financial Data (Unaudited): |
||||||||||||||||||||
Calculation of Adjusted EBITDA (1): |
||||||||||||||||||||
Net income (loss) |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | $ | 37,592 | $ | 59,833 | |||||||
Interest expense |
4,671 | 6,933 | 4,048 | 5,030 | 1,499 | |||||||||||||||
Income tax expense (benefit) |
(18,135 | ) | (27,151 | ) | (5,339 | ) | 22,690 | 37,194 | ||||||||||||
Depreciation and amortization |
28,445 | 36,180 | 39,194 | 34,989 | 27,192 | |||||||||||||||
Other adjustments related to discontinued operations |
14,498 | 3,641 | 13,465 | 9,398 | 4,242 | |||||||||||||||
Other and non-recurring expense |
40,204 | 48,905 | 35,557 | | | |||||||||||||||
Adjusted EBITDA (1) |
19,006 | 10,929 | 78,682 | 109,699 | 129,960 | |||||||||||||||
As of December 31, | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
Consolidated Balance Sheet
Information: |
||||||||||||||||||||
Total current assets |
$ | 51,547 | $ | 43,077 | $ | 107,821 | $ | 72,019 | $ | 73,372 | ||||||||||
Total assets |
342,030 | 445,583 | 612,354 | 568,605 | 482,488 | |||||||||||||||
Total debt |
6,825 | 51,903 | 117,547 | 68,118 | 64,727 | |||||||||||||||
Total liabilities |
48,688 | 105,312 | 218,343 | 172,176 | 142,503 | |||||||||||||||
Total stockholders/members equity |
293,342 | 340,271 | 394,011 | 396,429 | 339,985 |
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(1) | 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, impairment, book loss on certain asset sales and other non-cash charges. 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. |
Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operation. |
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 services to 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 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 building,
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 2010.
In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to build,
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 building and refurbishment programs.
We have a 20% 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 PEMEX and/or
companies contracted with PEMEX. 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 one operating segment: contract land drilling. In
June of 2009 we made the decision to suspend operations in our well servicing segment because of
deteriorating market conditions resulting from the rapid decrease in oil and natural gas prices
which began in the third quarter of 2008, as well as the inability of many customers to obtain
financing related to their drilling and workover programs. The following is a description of this
operating segment.
Through the second quarter of 2010, we explored alternatives to restructure our well servicing
segment. During Q1 and Q2 2010 the market for workover services continued at depressed levels
within our primary geographic well servicing market (Oklahoma). Late in Q2 2010, we determined that
higher NPV projects were available within our drilling segment and chose to deploy capital in this
segment rather than commit the capital required to restructure operations in the well servicing
segment.
In late June 2010 we made a decision to market the assets constituting the well servicing
segment for sale and redeploy the proceeds to reduce debt and to support the Companys core
drilling business. We have presented all well servicing operating results as discontinued
operations in our Consolidated Statements of Operations for all periods presented.
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In September 2010, substantially all of the assets of the well servicing segment were sold at
auction to multiple bidders. The Company had one workover rig held for sale at December 31, 2010,
with a carrying amount of $130.
In September and November 2010, we sold at auction in separate lots to multiple bidders two
complete drilling rigs and components comprising six other drilling rigs (rigs 2, 9, 51, 52, 54,
70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at auction were not
being utilized currently in our business. In an unrelated transaction on September 23, 2010, we
sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated
third party. On November 29, 2010, the Company sold two drilling rigs (rigs 5 and 7) and entered
into a contract to sell one drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an
unaffiliated third party.
In February 2011, we entered into a contract to sell two drilling rigs (rigs 56 and 62) to
Windsor Permian LLC, an unaffiliated third party. The drilling rigs and related equipment sold at
auction and held for sale are being sold as part of a broader strategy by management to divest of
older drilling rigs and use the proceeds to pay down existing indebtedness.
Our contract land drilling segment provides contract land drilling services. As of February
28, 2011, we owned a fleet of 25 marketed land drilling rigs. We currently operate our drilling
rigs in Oklahoma, Texas, Pennsylvania, West Virginia, and North Dakota. 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 25
operating drilling rigs range from 650 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 and are frequently utilized in unconventional resource
plays. 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 decided 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 20 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 three months ended December 31, 2010 and 2009 and years ended December 31, 2010, 2009,
and 2008, our rig utilization rates, revenue days, and average number of marketed rigs were as
follows:
Three Months Ended | ||||||||||||||||||||
December 31, | Years Ended December 31, | |||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2008 | ||||||||||||||||
Average number of
operating rigs |
24 | 37 | 33 | 44 | 44 | |||||||||||||||
Revenue days |
2,152 | 1,049 | 7,450 | 5,699 | 12,712 | |||||||||||||||
Utilization Rates |
96 | % | 31 | % | 62 | % | 36 | % | 79 | % |
The increase in the number of revenue days in 2010 is due to the increase in oil and
natural gas drilling activity in response to commodity prices and the availability of financing to
our customers to fund their drilling programs. 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.
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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
activity in the markets we serve and affect the demand for our drilling services and the revenue
rates we can charge for our drilling 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 depends on.
Our business environment was 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 a
result of this deterioration, there was and continues to be significant uncertainty in the capital
markets and access to financing has been adversely impacted. As a result of these conditions, our
customers reduced their exploration budgets which resulted in a significant decrease in demand for
our services and a reduction in revenue rates and utilization. During 2010, demand for drilling
activity improved as certain commodity prices strengthened in the latter half of the year. During
2010 the Company did not record any contract drilling revenue related to terminated contracts.
During 2009 the Company recorded $7.9 million of contract drilling revenue related to terminated
contracts. 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, 2011, the closing prices for near month delivery contracts for crude oil and
natural gas as traded on the NYMEX were $96.97 per barrel and $4.04 per MMbtu, respectively. The
Baker Hughes domestic land drilling rig count as of February 28, 2011 was 1,674. 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, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Crude oil (Bbl) |
$ | 91.38 | $ | 79.36 | $ | 44.60 | ||||||
Natural gas (Mmbtu) |
$ | 4.41 | $ | 5.57 | $ | 5.62 | ||||||
U.S. Land Rig Count |
1,670 | 1,150 | 1,653 |
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 over the previous several years. Falling commodity prices and the oversupply of rigs,
similar to what we began experiencing in 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. During 2010, these
commodity prices strengthened and the overall demand for drilling activity increased in oil and
natural gas resource plays. We expect continued increases in exploration and production spending
in 2011, which we expect will result in modest increases in industry rig utilization and revenue
rates in 2011, as compared to 2010. Continued fluctuations in the demand for gas and oil, among
other factors including supply, could contribute to price volatility which may continue to affect
demand for our services and could materially affect our future financial results.
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 managements most subjective judgments. The most critical accounting policies
and estimates are described below.
Revenue and Cost RecognitionOur 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 occasionally 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.
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Our management has determined that it is appropriate to use the percentage-of-completion
method to recognize revenue on our footage contracts, which is the predominant practice in the
industry. Although our footage contracts do not have express terms that provide us with rights to
receive payment for the work that we perform prior to drilling wells to the agreed upon depth, we
use this method because, as provided in applicable accounting literature, we believe we achieve a
continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately
could recover the fair value of our work-in-progress even in the event we were unable to drill to
the agreed upon depth in breach of the applicable contract. However, ultimate recovery of that
value, in the event we were unable to drill to the agreed upon depth in breach of the contract,
would be subject to negotiations with the customer and the possibility of litigation.
We are entitled to receive payment under footage contracts when we deliver to our customer a
well completed to the depth specified in the contract, unless the customer authorizes us to drill
to a shallower depth. Since inception, we have completed all our footage contracts. Although our
initial cost estimates for footage contracts do not include cost estimates for risks such as stuck
drill pipe or loss of circulation, we believe that our experienced management team, our knowledge
of geologic formations in our areas of operations, the condition of our drilling equipment and our
experienced crews enable us to make reasonably dependable cost estimates and complete contracts
according to our drilling plan. While we do bear the risk of loss for cost overruns and other
events that are not specifically provided for in our initial cost estimates, our pricing of footage
contracts takes such risks into consideration. When we encounter, during the course of our drilling
operations, conditions unforeseen in the preparation of our original cost estimate, we immediately
adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a
loss on a contract in progress at the end of a reporting period due to a change in our cost
estimate, we immediately accrue the entire amount of the estimated loss, including all costs that
are included in our revised estimated cost to complete that contract, in our consolidated statement
of operations for that reporting period. We had no footage contracts in progress at December 31,
2010 and 2009. 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, 2010 and 2009, our unbilled receivables totaled $428,000 and
$828,000, 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 ReceivableWe 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 $1.7 million
and $3.6 million at December 31, 2010 and 2009, 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 customers 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.
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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. 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
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 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.
In the second quarter of 2010, management decided to sell the property and equipment of our
well servicing segment. Management determined that the business was no longer consistent with our
long-term strategic objectives. Since the well servicing property and equipment met the held for
sale criteria, we were required to present its property and equipment held for sale at the lower of
carrying amount or fair value less cost to sell. We evaluated well servicings respective assets
held for sale for impairment. We engaged a third party independent appraisal company to determine
the fair value of the well servicing assets. The analysis as of June 30, 2010 resulted in a $23.4
million impairment charge ($14.3 million after tax). This charge was recorded in the second
quarter of 2010 and is reflected as a component of loss from discontinued operations in our
Consolidated Statements of Operations.
In the third
quarter of 2010, management made the decision to divest of older drilling rigs
and use the proceeds to pay down existing indebtedness. Consequently, management decided to sell
five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs met the held for sale
criteria, we are required to present these assets held for sale at the lower of carrying amount or
fair value less anticipated cost to sell. We evaluated these assets as of September 30, 2010, for
impairment. The fair value of the drilling rigs was determined using level 3 inputs. The fair
value was determined by the sale price of similar assets sold by us in an auction during the third
quarter and negotiated prices with interested parties. The analysis as of September 30, 2010
resulted in a $7.8 million impairment charge. We recognized an
additional impairment during the fourth quarter of approximately
$139,000 related to assets held for sale.
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, 2010 and 2009, we did not capitalize any interest.
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We review
our equity investments 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 volatility and
decline in oil and natural gas prices, a deteriorating global economic environment through 2009
and the anticipated future earnings of Challenger, we deemed it necessary to test the investment
for impairment during 2008, 2009, and 2010.
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
our fair value estimates, certain key assumptions included an
assumed discount rate of 14.5% and 16.5%, a
control premium of 25.0% and 30.0% and a long-term growth rate of
4.0% and 4.0% for 2009 and 2008, respectively. The analysis resulted in a non-cash impairment
charge of $14.4 million in 2008. The analysis resulted in a fair
value of $39.8 million related to our investment in Challenger,
as of September 30, 2009, 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 the statement of operations ended December
31, 2009.
In developing our fair value estimates,
as of December 31, 2010, certain key assumptions included an
assumed discount rate of 15.0%, a control premium of 22.1% and a long-term growth rate of 3.0%.
The analysis resulted in a fair value of $40.9 million related to our investment in Challenger,
which was above the carrying value of the investment and resulted in no impairment.
Recent civil and
political disturbances in Libya elsewhere in North Africa, and the Middle
East may affect Challengers operations. Ongoing
political unrest may result in loss of revenue and damage to
equipment. Any impact from the
political turmoil and protests on Challengers operations could negatively impact the
Companys investment in Challenger. The current conditions may trigger additional impairment
analysis during 2011 which could result in an impairment of our investment.
Stock
Based CompensationWe 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, $3.3 million, and $5.8 million for 2010, 2009, and 2008,
respectively.
Deferred Income TaxesWe 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 InvestmentsInvestee 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 companys 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 companys 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
(loss) of Bronco MX and Equity in income (loss) 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 EstimatesOur other accrued expenses as of December 31, 2010 and December
31, 2009 included accruals of approximately $3.7 million and $2.5 million, respectively, for costs
under our workers compensation insurance. We have a deductible of $500,000 per covered accident
under our workers compensation insurance. We maintain letters of credit in the aggregate amount of
$11.5 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.
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Year in Review Highlights
The following are recent highlights that have impacted our results of operations for the year
ended December 31, 2010.
Asset Sales and Held for Sale
On September 21, 2010 through September 23, 2010, we sold at auction in separate lots to
multiple bidders two complete drilling rigs and components comprising four other drilling rigs
(rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at
auction were not being utilized currently in our business. We received net proceeds of
approximately $8.3 million, net of selling expenses of $817,000, for the drilling rigs and related
equipment. We recorded losses of $19.9 million related to the sale of the drilling rigs and
ancillary equipment. The loss was based on net book values of approximately $28.2 million for the
drilling rigs and ancillary equipment. We used the entire proceeds to pay down existing
indebtedness under our revolving credit facility.
In an unrelated transaction on September 23, 2010, we sold two drilling rigs (rigs 41 and 42)
in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated net proceeds
of $7.2 million. We recorded a $1.7 million loss on the sale of these assets based on a net book
value of $8.9 million.
The decision was made by management in the third quarter to sell an additional five drilling
rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs met the held for sale criteria, we were
required to present such assets, comprised of property and equipment, at the lower of carrying
amount or fair value less the anticipated costs to sell. We evaluated these assets for impairment
as of September 30, 2010, which resulted in recognizing a $7.8 million impairment charge which
includes estimated selling expenses of approximately $125,000. At September 30, 2010, the fair
value estimate was derived from the sale price of similar assets sold at auction during the third
quarter and negotiated prices with interested parties. The drilling rigs and related equipment
were presented as part of our land drilling segment.
On November 17, 2010, the Company sold at auction in separate lots to multiple bidders two
complete drilling rigs (rigs 51 & 54) and ancillary equipment. The drilling rigs and equipment
sold at auction were not being utilized currently in the Companys business. The Company received
net proceeds of approximately $1.7 million, net of selling expenses of $115,000, for the drilling
rigs and related equipment. The Company recorded a loss of $2.2 million related to the sale of the
drilling rigs and ancillary equipment. The loss was based on net book values of approximately $3.9
million for the drilling rigs and ancillary equipment.
On November 29, 2010, the Company sold two drilling rigs (rigs 5 and 7) in a private sale to
Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $2.7 million. The
Company recorded a $14,000 gain on the sale of these assets based on a net book value of $2.7
million.
The Company believes the sale of rig 6 is probable within a year from the date on which we
classified the drilling rig as held for sale. Because the drilling rig meets the held for sale
criteria, the Company is required to present such assets, comprised of property and equipment, at
the lower of carrying amount or fair value less the anticipated costs to sell. The carrying amount
of the drilling rig and related equipment after impairment was $1.6 million at December 31, 2010,
and is included in Non-current assets held for sale in our Consolidated Balance Sheets. The
Company recognized an additional impairment during the fourth quarter of approximately $139,000
related to this rig. At December 31, 2010, the Companys fair value estimate was derived from the
negotiated prices with interested parties. The drilling rig and related equipment were included as
part of our land drilling segment.
The drilling rigs and related equipment sold at auction and the drilling rig held for sale are
being sold as part of a broader strategy by management to divest of older drilling rigs and use the
proceeds to pay down existing indebtedness.
Well Servicing Segment
In June 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.
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Through the second quarter of 2010, Bronco senior management explored alternatives to
restructure the well servicing segment. During Q1 and Q2 2010 the market for workover services
continued at depressed levels within the primary geographic market of our well servicing assets
(Oklahoma). Late in Q2 2010, management determined that higher NPV projects were available within
the core drilling segment of the business and chose to deploy capital in this segment rather than
commit the capital required to restructure operations in the well servicing segment.
In late June management made a decision to market the assets constituting the well servicing
segment for sale and redeploy the proceeds to reduce debt and to support the Companys core
drilling business. Since the well servicing property and equipment met the held for sale
criteria, we were required to present its property and equipment held for sale at the lower of
carrying amount or fair value less cost to sell. Accordingly, in the second quarter of 2010, we
evaluated well servicings respective assets held for sale for impairment. We engaged a third
party independent appraisal company to determine the fair value of the well servicing assets. The
analysis as of June 30, 2010 resulted in $23.4 million impairment charge ($14.3 million after tax).
This charge was recorded in the second quarter of 2010 and is reflected as a component of income
(loss) from discontinued operations in our Consolidated Statements of Operations.
In September 2010, substantially all of the assets of the well servicing segment were sold at
auction to multiple bidders. We received proceeds of $12.4 million, net of selling expenses of
$638,000. The sale of the assets of the well servicing segment resulted in a loss of $8.9 million,
which is reflected as a component of loss from discontinued operations in our Consolidated
Statements of Operations. We used the proceeds to pay down existing indebtedness under our
revolving credit facility.
Bronco MX Joint Venture
In September of 2009, CICSA purchased 60% of the outstanding membership interests of Bronco MX
from us. 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.
On July 1, 2010, CICSA contributed cash of approximately $45.1 million in exchange for
735,356,219 shares of Bronco MX. The cash contributed was used to purchase five drilling rigs. As
a result of the contribution, our membership interest in Bronco MX was decreased to approximately
20%. We have accounted for the share issuance as if we had sold a proportionate amount of our
shares. The Company recorded a loss on the transaction in the amount of $1.3 million, which is
included in our consolidated statements of operations.
Bronco MX is jointly managed, with CICSA having four representatives on its board of managers
and the Company having one representative 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 MXs ability to perform.
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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 have affected 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: |
||||||||||||||||
Fourth |
$ | 4.61 | $ | 3.29 | $ | 91.51 | $ | 79.49 | ||||||||
Third |
$ | 4.92 | $ | 3.65 | $ | 82.55 | $ | 71.63 | ||||||||
Second |
$ | 5.19 | $ | 3.91 | $ | 86.79 | $ | 68.01 | ||||||||
First |
$ | 6.01 | $ | 3.84 | $ | 83.76 | $ | 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; |
| In June 2010, management made a decision to sell the assets in the well servicing segment. We recorded a $23.4 million impairment charge ($14.3 million after tax). |
| In July 2010, subsequent to the end of our second quarter, we completed the sale of the property and equipment of our trucking assets for $11.3 million in cash, net of selling expenses in the amount of $403,000. Proceeds from this sale were used to repay existing indebtedness under our revolving credit facility with Banco Inbursa. |
| In September 2010, we sold at auction in separate lots to multiple bidders substantially all of the assets of our discontinued well servicing segment, two complete drilling rigs and components comprising four other drilling rigs (rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. We recorded losses of $8.9 million and $19.9 million from the sale of the assets of our well servicing segment and drilling rigs and related equipment, respectively. |
| In September 2010, we sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated proceeds of $7.2 million. We recorded a loss of $1.7 million on the sale of these assets. |
Additionally, in the third quarter of 2010 management made the decision to continue to divest
of smaller legacy mechanical rigs and invest the proceeds into new generation drilling rigs and
equipment. That decision resulted in the following transactions.
| In September 2010, management made a decision to sell five drilling rigs (rigs 5, 6, 7, 51 and 54). We recorded a $8 million impairment charge on these rigs. |
| In November 2010, we sold at auction in separate lots to multiple bidders two complete drilling rigs (rigs 51 and 54) and ancillary equipment. We recorded a loss of $2.2 million on the sale of these assets. |
| In November 2010, we sold two drilling rigs (rigs 5 and 7) and entered into a contract to sale one drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $4.5 million. The Company recorded a $14,000 gain on the sale of rigs 5 and 7. |
| In February 2011, we sold two drilling rigs (rigs 56 and 62) in a private sale to Windsor Permian LLC, an unaffiliated third party, for estimated proceeds of $11.5 million. |
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Results of Operations
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Contract
Drilling Revenue. For the year ended December 31, 2010, we reported contract drilling
revenues of approximately $124.4 million, a 21% increase from revenues of
$102.9 million for 2009.
The increase is primarily due to an increase in total revenue days and an increase in average
dayrates. Revenue days increased 31% to 7,450 days for the year ended
December 31, 2010 from 5,699
days during 2009. Average dayrates for our drilling services increased $455, or 3%, to $16,527
for the year ended December 31, 2010 from $16,072 in 2009. The increase in the number of revenue
days for the year ended December 31, 2010 as compared to 2009 is attributable to the increase in
our utilization rate. Utilization increased to 62% from 36% for the year ended December 31, 2010 as
compared to 2009. The 72% increase in utilization was primarily due to the increase in demand for
our services related to an increase in drilling activity as a result of higher oil and natural gas
prices. For the year ended December 31, 2010, the Company did not record any contract drilling
revenue related to terminated contracts compared to $7.9 million for 2009.
Equity in Income
(Loss) of Challenger. Our equity in the loss of Challenger was $984,000 for
the year ended December 31, 2010 compared to $1.9 million for the year ended
December 31, 2009.
The equity in loss of Challenger represents our 25% share of Challengers loss for
2010 and 2009.
For the year ended December 31, 2010, Challenger had operating revenues of
$49.3 million and
operating costs of $36.7 million. For the year ended December 31, 2009, Challenger
had operating
revenues of $56.5 million and operating costs of $35.4 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. Due to the volatility and decline in oil and
natural gas prices, a deteriorating global economic environment and the anticipated future earnings
of Challenger in 2009, 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 for the year ended December 31, 2009. We
performed an impairment analysis as of December 31, 2010 and based
upon the results, we were not required to record additional
impairments during the year ended December 31, 2010. During the
first quarter of 2011, political instability and unrest occurred in
Libya, which could result in additional impairments of our investment
in challenger.
Equity in Income (Loss) of Bronco MX. Equity in income of Bronco MX was $22,000 for the year
ended December 31, 2010. Equity in loss of Bronco MX was $588,000 for the period September 18
through December 31, 2009. The equity in income (loss) of Bronco MX represents our proportionate
share of Bronco MXs loss for 2010 and 2009. For the year ended December 31, 2010, Bronco MX had
operating revenues of $34.1 million and operating costs of $33.4 million. For the period September
18 through December 31, 2009, Bronco MX had operating revenues of $7.2 million and operating costs
of $9.8 million.
Contract Drilling Expense. Contract drilling expense increased $19.6 million to $90.3 million
for the year ended December 31, 2010 from $70.7 million in 2009. This 28% increase is primarily due
to the increase in the number of revenue days from 5,699 for the year ended December 31, 2009 to
7,450 for 2010. As a percentage of contract drilling revenue, drilling expense increased to 73%
for the year ended December 31, 2010 from 69% in 2009 due primarily to revenue related to
terminated contracts of $7.9 million for 2009.
Depreciation and Amortization Expense. Depreciation and amortization expense decreased $7.8
million to $28.4 million for the year ended December 31, 2010 from $36.2 million in 2009. The
decrease is due to the contribution of nine drilling rigs to Bronco MX in the third quarter of
2009, the sale of our workover rig segment in the third quarter of 2010, and the sale of six
complete drilling rigs and components comprising six other drilling rigs during 2010.
General and Administrative Expense. General and administrative expense increased $1.3 million,
or 8%, to $17.1 million for the year ended December 31, 2010 from $15.8 million in 2009. This
primarily resulted from a $2.0 million increase in accounts receivable write offs and a $309,000
increase in payroll costs. These increases were partially offset by a decrease in consulting fees
of $942,000 and a decrease in professional fees of $405,000. The decreases in consulting fees and
professional fees is due to expenses incurred during 2009 related to the Bronco MX transaction.
Interest Expense. Interest expense decreased $2.2 million to $4.7 million for the year ended
December 31, 2010 from $6.9 million in 2009. The decrease is due to a decrease in the average
outstanding balance under our credit facilities.
Income Tax Expense. We recorded an income tax benefit of $18.1 million for the
year ended December 31, 2010. This compares to an income tax benefit of $27.2 million in 2009. This
decrease is primarily due to a $22.7 million decrease in pre-tax loss to $52.6 million for the year
ended December 31, 2010 from $75.3 million in 2009.
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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 $102.9 million, a 56% decrease from
revenues of $233.9 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.
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
Challengers 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 $35.4 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. Due to the 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 during 2009. 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 MXs loss for 2009. For the period September 18 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 $65.0 million to $70.7 million
for the year ended December 31, 2009 from $135.7 million in 2008. This 48% 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 69%
for the year ended December 31, 2009 from 60% in 2008 due primarily to fixed costs on idle drilling
rigs.
Depreciation and Amortization Expense. Depreciation and amortization expense decreased $3.0
million to $36.2 million for the year ended December 31, 2009 from $39.2 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 47%, to $15.8 million for the year ended December 31, 2009 from $29.8 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 $3.3 million
decrease in accounts receivable write-offs, $2.5 million decrease in stock compensation expense, a
$1.4 million decrease in professional fees, a $1.0 million decrease in payroll costs, and a
$564,000 decrease in yard expense. 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 $2.9 million to $6.9 million for the year ended
December 31, 2009 from $4.0 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 $27.2 million for the
year ended December 31, 2009. This compares to an income tax
benefit of $5.3 million in
2008. This
increase is primarily due to a $64.6 million increase in pre-tax loss to $75.3 million
for the year
ended December 31, 2009 from $10.7 million in 2008.
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Liquidity and Capital Resources
Operating Activities. Net cash provided by operating activities was $38.3 million for 2010,
$22.2 million for 2009, and $48.4 million in 2008. The increase of $16.1 million from 2009 to 2010
was primarily due to an increase in cash receipts from customers and lower 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 $3.0 million for 2010 and $19.0 million for 2009 compared to cash used of
$75.0 million for 2008. In 2010, we received approximately $24.0 million in proceeds from the sale
of assets and $911,000 from principal payments on note receivable, which were partially offset by
$19.2 million used to purchase property and equipment. In 2009, we received $31.7 million from the
sale of 60% of the outstanding membership interests in Bronco MX, proceeds of $635,000 from the
sale of assets and principal payments on note receivable of $3.1 million, partially offset by $16.5
million used to purchase property and equipment. In 2008, approximately $5.1 million was used to
obtain a 25% interest in Challenger, $76.8 million was used to purchase property and equipment,
which amounts were partially offset by $4.0 million received from the sale of assets and $2.9
million received from a restricted cash account.
Financing Activities. We used cash for financing activities of $46.0 million for 2010 and
$58.4 million for 2009 as compared to cash provided of $47.5 million for 2008. Our net cash used
for financing activities for 2010 related to payments on our revolving credit facility with Banco
Inbursa in the amount of $50.9 million, partially offset by borrowings of $5.0 million under our
revolving credit facility with Banco Inbursa. 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, 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 $3.5 million in debt issuance costs.
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 with Banco Inbursa, as lender and as the issuing bank. 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.
The credit facility initially provided for revolving advances of up to $75.0 million and the
borrowing base under the credit facility was initially set at $75.0 million, subject to borrowing
base limitations. On February 9, 2011 we amended our credit facility which reduced the commitment
to $45.0 million. The credit facility matures on September 17, 2014. 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. Commitment fees expense
was $125,000 and $15,000 for the years ended December 31, 2010 and December 31, 2009, respectively.
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.
We were in compliance with all covenants at December 31, 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.
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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, 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, September 18, 2009, 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. Banco Inbursa subsequently transferred the
Warrant to CICSA.
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, 2010 and
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 volatilities of 50% and 45% and a risk free interest rate that ranged from 0.22% to 0.54% and
0.40% to 1.45% for 2010 and 2009, respectively. The fair value of the Warrant was $4.4 million and
$2.8 million at December 31, 2010 and December 31, 2009, respectively. We recorded a change in the
fair value of the Warrant on the consolidated statement of operations in the amount of $1.6 million
and $1.9 million for the years ended December 31, 2010 and December 31, 2009, respectively.
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.
This 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 year ended December 31, 2009 was $447,000.
This 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.
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 conjunction with our entry into our senior secured revolving credit facility with Banco
Inbursa, we issued a three-year 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, 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 to CICSA evidencing such transfer.
Capital Expenditures.
During 2010, we incurred aggregate refurbishment costs of $7.3 million related to enhancements
and refurbishments of rigs for opportunities domestically and incurred $8.0 million for the
purchase of top drives to upgrade our fleet.
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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.
Working Capital. Our working capital was $35.7 million at December 31, 2010, compared to
$25.3 million at December 31, 2009. Our current ratio, which we calculate by dividing our current
assets by our current liabilites, was 3.2 at December 31, 2010 compared to 2.4 at December 31,
2009.
We believe that
the liquidity shown on our balance sheet as of December 31, 2010, which
includes approximately $35.7 million in working capital (including $11.9 million in cash) and
availability under our then $75.0 million credit facility of $54.4 million at December 31, 2010
(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. We believe the reduction in our credit
facility to $45.0 million will not materially impact
our liquidity. However, additional capital may be required for future rig acquisitions. While we
would expect to fund such acquisitions with additional borrowings and the issuance of debt and
equity securities, we cannot assure you that such funding will be available or, if available, that
it will be on terms acceptable to us. The changes in the components of our working capital were as
follows (amounts in thousands):
December 31, | ||||||||||||
2010 | 2009 | Change | ||||||||||
Cash and cash equivalents |
$ | 11,854 | $ | 9,497 | $ | 2,357 | ||||||
Restricted cash |
2,700 | | 2,700 | |||||||||
Trade and other receivables |
24,656 | 15,306 | 9,350 | |||||||||
Affiliate receivables |
1,508 | 9,620 | (8,112 | ) | ||||||||
Unbilled receivables |
428 | 828 | (400 | ) | ||||||||
Income tax receivable |
5,700 | 3,800 | 1,900 | |||||||||
Current deferred income taxes |
2,765 | 1,360 | 1,405 | |||||||||
Current maturities of note receivable |
1,607 | 2,000 | (393 | ) | ||||||||
Prepaid expenses |
329 | 666 | (337 | ) | ||||||||
Current assets |
51,547 | 43,077 | 8,470 | |||||||||
Current debt |
95 | 89 | 6 | |||||||||
Accounts Payable |
7,945 | 9,756 | (1,811 | ) | ||||||||
Accrued liabilities and deferred
revenues |
7,847 | 7,952 | (105 | ) | ||||||||
Current liabilities |
15,887 | 17,797 | (1,910 | ) | ||||||||
Working capital |
$ | 35,660 | $ | 25,280 | $ | 10,380 | ||||||
The increase in
cash and cash equivalents and restricted cash at December 31,
2010 as compared to
December 31, 2009 was primarily due the sale of six complete drilling rigs and components
comprising six other drilling rigs and our well servicing segment and trucking operations which
resulted in net proceeds of $43.6 million as well as the decrease in affiliate receivables of $8.1
million, partially offset by the payments on our revolving credit facility with Banco Inbursa, in
the amount of $50.9 million. The increase in cash is also attributable to an overall increase in
drilling activity for 2010. Revenue days for the year ended December 31, 2010 were 7,450 compared
to 5,699 for 2009.
The increase in trade receivables and other receivables at December 31, 2010 as compared to
December 31, 2009 was due to an increase in revenue days and utilization rates during 2010 compared
to 2009. Utilization for the year ended December 31, 2010 was 62% compared to 36% for 2009.
Revenue days for the year ended December 31, 2010 were 7,450 compared to 5,699 for 2009.
The decrease in affiliate receivables at December 31, 2010 as compared to December 31, 2009
was mainly due to $7.1 million in payments received from Bronco MX.
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Contractual and Commercial Commitments
The following table summarizes our contractual obligations and commercial commitments at
December 31, 2010 (in thousands):
Payments Due by Period | ||||||||||||||||||||
Less than 1 | More than 5 | |||||||||||||||||||
Contractual Obligations | Total | year | 1-3 years | 4-5 years | years | |||||||||||||||
Short and long-term debt |
$ | 10,373 | $ | 95 | $ | 9,423 | $ | 855 | $ | | ||||||||||
Interest on long-term debt |
2,478 | 625 | 1,685 | 89 | 79 | |||||||||||||||
Operating lease
obligations |
2,032 | 770 | 1,185 | 77 | | |||||||||||||||
Total |
$ | 14,883 | $ | 1,490 | $ | 12,293 | $ | 1,021 | $ | 79 | ||||||||||
Off Balance Sheet Arrangements
We do not have any off balance sheet arrangements.
Recent Accounting Pronouncements
In December 2010, the FASB issued an accounting standard update that addresses the disclosure
of supplementary pro forma information for business combinations. This update clarifies that when
public entities are required to disclose pro forma information for business combinations that
occurred in the current reporting period, the pro forma information should be presented as if the
business combination occurred as of the beginning of the previous fiscal year when comparative
financial statements are presented. This update is effective prospectively for 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, 2010. Early adoption is permitted. The
Company is currently evaluating the impact, if any, the adoption will have on our consolidated
financial statements.
In January 2010, the FASB issued a new accounting standard which requires reporting entities
to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value
hierarchy established by ASC 820, Fair Value Measurements. Also required will be a reconciliation
of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3
method, which is used to price the hardest to value instruments. Entities will have to provide
fair value measurement disclosures for each class of financial assets and liabilities. The
guidance will be effective for fiscal years beginning after December 15, 2010. We are currently
evaluating the impact, if any, the adoption will have on our consolidated financial statements.
In December 2009, the FASB issued a new accounting standard which updates the
quantitative-based risks and rewards calculation for determining which reporting entity, if any,
has a controlling financial interest in a variable interest entity with an approach focused on
identifying which reporting entity has the power to direct the activities of a variable interest
entity that most significantly impact the entitys economic performance and (1) the obligation to
absorb losses of the entity or (2) the right to receive benefits from the entity. An approach that
is expected to be primarily qualitative will be more effective for identifying which reporting
entity has a controlling financial interest in a variable interest entity. The amendments in this
update also require additional disclosures about an reporting entitys involvement in variable
interest entities, which will enhance the information provided to users of financial statements.
This new standard is effective at the start of a reporting entitys first fiscal year beginning
after January 1, 2010. The adoption of this standard did not impact our consolidated financial
statements.
In October 2009, the FASB issued a new accounting standard that addresses the accounting for
multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately
rather than as a combined unit. This new standard addresses how to separate deliverables and how to
measure and allocate arrangement consideration to one or more units of accounting. Existing
accounting standards require a vendor to use objective and reliable evidence of fair value for the
undelivered items or the residual method to separate deliverables in a multiple-deliverable
arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be
separated in more circumstances than under current requirements. The new standard establishes a
hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to
multiple deliverables. The selling price used will be based on vendor-specific objective evidence
if available, third-party evidence if vendor-specific objective evidence is not available, or
estimated selling price if neither vendor-specific objective evidence nor third-party evidence is
available. The new standard must be prospectively applied to all revenue arrangements entered into
in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011.
We are currently evaluating the impact, if any, the adoption will
have on our consolidated financial statements.
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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 entitys 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.
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
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 $56,000
annually, based on the $9.1 million outstanding in the aggregate under our credit facility as of
December 31, 2010.
Item 8. | Financial Statements and Supplementary Data. |
Our
Financial Statements begin on page 49 of this Form 10-K, Index to Consolidated
Financial Statements, and are incorporated herein by this reference.
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. |
None.
Item 9A. | Controls and Procedures. |
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, 2010 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 SECs 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.
Managements 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 ControlIntegrated 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, 2010.
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The independent registered public accounting firm that audited the Companys financial
statements, Grant Thornton LLP, has issued an attestation report on the effectiveness of the
Companys 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.
Bronco Drilling Company, Inc.
We have audited Bronco Drilling Company, Inc.s (the Company) internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Companys 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 Managements Report on Internal
Control over Financial Reporting. Our
responsibility is to express an opinion on the Companys 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 companys 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
companys 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 companys 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, 2010, based on criteria established in Internal Control -
Integrated Framework issued by COSO.
We also have 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, 2010 and
2009, 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, 2010 and our report dated
March 15, 2011 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 15, 2011
March 15, 2011
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Table of Contents
PART III
Item 10. | Directors and Executive Officers and Corporate Governance. |
The information
relating to this Item 10 is incorporated by reference to either the Proxy
Statement for our 2011 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, 2010.
Item 11. | Executive Compensation. |
The information
relating to this Item 11 is incorporated by reference to either
the Proxy Statement for our 2011 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, 2010.
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
The information relating to this Item 12 is incorporated by reference to either the Proxy
Statement for our 2011 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, 2010.
Item 13. | Certain Relationships and Related Transactions, and Director Independence. |
The information relating to this Item 13 is incorporated by reference to either the Proxy
Statement for our 2011 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, 2010.
Item 14. | Principal Accounting Fees and Services |
The information relating to this Item 14 is incorporated by reference to either the Proxy
Statement for our 2011 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, 2010.
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PART IV
Item 15. | Exhibits, Financial Statement Schedules. |
(a) The following documents are filed as part of this report:
1. | Financial Statements | ||
See Index to Consolidated Financial Statements on page 47 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 Companys
Current Report on Form 8-K, File No. 000-51571, filed by the Company with the SEC on
January 16, 2007). |
|||
2.3 | Agreement and Plan of Merger, dated as of January 23, 2008, 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 January 24, 2008). |
|||
2.4 | 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). |
|||
2.5 | 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). |
45
Table of Contents
Exhibit No. | Description | |||
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 | 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. (incorporated by reference to Exhibit 10.6 to the Annual
Report on Form 10-K, File No. 000-51471, filed by the Company with
the SEC on March 15, 2010). |
|||
10.6 | 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). |
|||
10.7 | First Amendment to Credit Agreement, dated February 9, 2011, by and
among Bronco Drilling Company, Inc., certain subsidiaries thereof, 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 11, 2011). |
|||
+10.8 | Bronco Drilling Company, Inc. 2006 Stock Incentive Plan
(incorporated by reference to Appendix B to the Companys 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 Companys Current Report on Form 8-K, File
No. 000-51471, 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 Companys Current Report on Form 8-K, File No.
000-51471, filed by the Company with the SEC on June 15, 2008). |
|||
+10.11 | Bronco Drilling Company, Inc. 2006 Stock Incentive Plan, as amended
(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
December 15, 2010). |
|||
*21.1 | List of the Companys 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. |
46
Table of Contents
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
BRONCO DRILLING COMPANY, INC. AND SUBSIDIARIES
BRONCO DRILLING COMPANY, INC. AND SUBSIDIARIES
Page | ||||
Bronco Drilling Company, Inc. and Subsidiaries |
||||
48 | ||||
49 | ||||
50 | ||||
51 | ||||
52 | ||||
53 |
47
Table of Contents
Report of Independent Registered Public Accounting Firm
Board of Directors
Bronco Drilling Company, Inc.
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, 2010 and 2009, and the related consolidated
statements of operations, stockholdersequity and comprehensive income (loss) and cash flows for
each of the three years in the period ended December 31, 2010. These financial statements are the
responsibility of the Companys 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, 2010 and 2009, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2010, in conformity with accounting principles
generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the Companys internal control over financial reporting as of December 31,
2010, 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 15, 2011 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 15, 2011
March 15, 2011
48
Table of Contents
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share par value)
December 31, | ||||||||
2010 | 2009 | |||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 11,854 | $ | 9,497 | ||||
Restricted cash |
2,700 | | ||||||
Receivables |
||||||||
Trade and other, net of allowance for doubtful accounts of
$891 and $3,576 in 2010 and 2009, respectively |
24,656 | 15,306 | ||||||
Affiliate receivables, net of allowance of $800 in 2010 |
1,508 | 9,620 | ||||||
Unbilled receivables |
428 | 828 | ||||||
Income tax receivable |
5,700 | 3,800 | ||||||
Current deferred income taxes |
2,765 | 1,360 | ||||||
Current maturities of note receivable from affiliate |
1,607 | 2,000 | ||||||
Prepaid expenses |
329 | 666 | ||||||
Total current assets |
51,547 | 43,077 | ||||||
PROPERTY AND EQUIPMENT AT COST |
||||||||
Drilling rigs and related equipment |
315,085 | 386,514 | ||||||
Transportation, office and other equipment |
16,236 | 18,602 | ||||||
331,321 | 405,116 | |||||||
Less accumulated depreciation |
105,242 | 116,455 | ||||||
226,079 | 288,661 | |||||||
OTHER ASSETS |
||||||||
Note receivable from affiliate, less current maturities |
| 517 | ||||||
Investment in Challenger |
38,730 | 39,714 | ||||||
Investment in Bronco MX |
20,632 | 21,407 | ||||||
Debt issue costs and other |
3,362 | 3,672 | ||||||
Non-current assets held for sale and discontinued operations |
1,680 | 48,535 | ||||||
64,404 | 113,845 | |||||||
$ | 342,030 | $ | 445,583 | |||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable |
$ | 7,945 | $ | 9,756 | ||||
Accrued liabilities |
7,847 | 7,952 | ||||||
Current maturities of long-term debt |
95 | 89 | ||||||
Total current liabilities |
15,887 | 17,797 | ||||||
LONG-TERM DEBT, less current maturities and discount |
6,730 | 51,814 | ||||||
WARRANT |
4,407 | 2,829 | ||||||
DEFERRED INCOME TAXES |
21,664 | 32,872 | ||||||
COMMITMENTS AND CONTINGENCIES (Note 8) |
||||||||
STOCKHOLDERS EQUITY |
||||||||
Common stock, $.01 par value, 100,000
shares authorized; 27,236 and 26,713 shares
issued and outstanding at December 31, 2010 and 2009 |
277 | 270 | ||||||
Additional paid-in capital |
310,580 | 307,313 | ||||||
Accumulated other comprehensive income |
1,012 | 538 | ||||||
Retained earnings (Accumulated deficit) |
(18,527 | ) | 32,150 | |||||
Total stockholders equity |
293,342 | 340,271 | ||||||
$ | 342,030 | $ | 445,583 | |||||
The accompanying notes are an integral part of these statements.
49
Table of Contents
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands, except per share amounts)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
REVENUES |
||||||||||||
Contract drilling revenues, including 0%, 0%, and 2%
from related parties |
$ | 124,399 | $ | 102,896 | $ | 233,922 | ||||||
EXPENSES |
||||||||||||
Contract drilling |
90,290 | 70,721 | 140,935 | |||||||||
Depreciation and amortization |
28,445 | 36,180 | 39,194 | |||||||||
General and administrative |
17,108 | 15,782 | 29,821 | |||||||||
Gain on Challenger transactions |
| | (2,252 | ) | ||||||||
Loss on Bronco MX transaction |
1,487 | 23,705 | | |||||||||
Impairment of goodwill |
| | 21,115 | |||||||||
Impairment of drilling rigs and related equipment |
7,900 | | | |||||||||
Loss on sale of drilling rigs and related equipment |
23,732 | | | |||||||||
168,962 | 146,388 | 228,813 | ||||||||||
Income (loss) from continuing operations |
(44,563 | ) | (43,492 | ) | 5,109 | |||||||
OTHER INCOME (EXPENSE) |
||||||||||||
Interest expense |
(4,671 | ) | (6,933 | ) | (4,048 | ) | ||||||
Loss from early extinguishment of debt |
| (2,859 | ) | (155 | ) | |||||||
Interest income |
201 | 273 | 1,039 | |||||||||
Loss on partial sale of investment in Bronco MX |
(1,271 | ) | | | ||||||||
Equity in income (loss) of Challenger |
(984 | ) | (1,914 | ) | 2,186 | |||||||
Equity in income (loss) of Bronco MX |
22 | (588 | ) | | ||||||||
Impairment of investment in Challenger |
| (21,247 | ) | (14,442 | ) | |||||||
Other |
204 | (383 | ) | (343 | ) | |||||||
Change in fair value of warrant |
(1,578 | ) | 1,850 | | ||||||||
(8,077 | ) | (31,801 | ) | (15,763 | ) | |||||||
Loss from continuing operations before
income tax |
(52,640 | ) | (75,293 | ) | (10,654 | ) | ||||||
Income tax benefit |
(18,135 | ) | (27,151 | ) | (5,339 | ) | ||||||
Loss from continuing operations |
(34,505 | ) | (48,142 | ) | (5,315 | ) | ||||||
Loss from discontinued operations, net of tax |
(16,172 | ) | (9,437 | ) | (2,928 | ) | ||||||
NET LOSS |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | |||
Loss per common share-Basic |
||||||||||||
Continuing operations |
(1.27 | ) | (1.81 | ) | (0.20 | ) | ||||||
Discontinued operations |
(0.60 | ) | (0.35 | ) | (0.11 | ) | ||||||
Loss per common share-Basic |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | |||
Loss per common share-Diluted |
||||||||||||
Continuing operations |
(1.27 | ) | (1.81 | ) | (0.20 | ) | ||||||
Discontinued operations |
(0.60 | ) | (0.35 | ) | (0.11 | ) | ||||||
Loss per common share-Diluted |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | |||
Weighted average number of shares outstanding-Basic |
27,091 | 26,651 | 26,293 | |||||||||
Weighted average number of shares outstanding-Diluted |
27,091 | 26,651 | 26,293 | |||||||||
The accompanying notes are an integral part of these statements.
50
Table of Contents
Bronco Drilling Company, Inc. and Subsidiaries
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, 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 | ||||||||||||||||||
Net loss |
| | | | (50,677 | ) | (50,677 | ) | ||||||||||||||||
Other Comprehensive Income: |
||||||||||||||||||||||||
Foreign currency translation
adjustment |
| | | 474 | | 474 | ||||||||||||||||||
Total Comprehensive Income (Loss) |
(50,203 | ) | ||||||||||||||||||||||
Stock compensation |
523 | 7 | 3,267 | | | 3,274 | ||||||||||||||||||
Balance as of December 31, 2010 |
27,236 | $ | 277 | $ | 310,580 | $ | 1,012 | $ | (18,527 | ) | $ | 293,342 | ||||||||||||
The accompanying notes are an integral part of these statements.
51
Table of Contents
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(Unaudited) | ||||||||||||
Cash flows from operating activities from continuing operations: |
||||||||||||
Net loss |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | |||
Adjustments to reconcile net loss to net cash
provided by operating activities from continuing operations: |
||||||||||||
Loss from discontinued operations, net of tax |
16,172 | 9,437 | 2,928 | |||||||||
Depreciation and amortization |
29,241 | 36,942 | 39,455 | |||||||||
Bad debt expense |
2,282 | 240 | 3,582 | |||||||||
Loss (gain) on sale of assets |
(272 | ) | 466 | 941 | ||||||||
Write off of debt issue costs |
| 2,859 | 155 | |||||||||
Gain on Challenger transactions |
| | (3,138 | ) | ||||||||
Impairment of investment in Challenger |
| 21,247 | 14,442 | |||||||||
Impairment of goodwill |
| | 21,534 | |||||||||
Loss on sale of drilling rigs and related equipment |
23,732 | | ||||||||||
Impairment of drilling rigs and related equipment |
7,900 | | ||||||||||
Loss on partial sale of investment in Bronco MX |
1,271 | | ||||||||||
Equity in (income) loss of Challenger |
984 | 1,914 | (2,186 | ) | ||||||||
Equity in (income) loss of Bronco MX |
(22 | ) | 588 | | ||||||||
Change in fair value of warrant |
1,578 | (1,850 | ) | | ||||||||
Loss on Bronco MX transaction |
1,487 | 23,705 | | |||||||||
Imputed interest expense |
907 | 224 | | |||||||||
Stock compensation |
3,274 | 3,301 | 5,825 | |||||||||
Deferred income taxes |
(5,392 | ) | (25,760 | ) | (6,332 | ) | ||||||
Changes in current assets and liabilities: |
||||||||||||
Receivables |
(11,993 | ) | 40,490 | (1,643 | ) | |||||||
Affiliate receivables |
8,112 | (6,233 | ) | | ||||||||
Unbilled receivables |
400 | 1,990 | (937 | ) | ||||||||
Prepaid expenses |
190 | (64 | ) | (152 | ) | |||||||
Other assets |
(790 | ) | 244 | 717 | ||||||||
Accounts payable |
8,627 | (21,465 | ) | (13,973 | ) | |||||||
Accrued expenses |
181 | (6,762 | ) | (4,552 | ) | |||||||
Income taxes receivable |
1,086 | (1,730 | ) | | ||||||||
Net cash provided by operating activities from continuing operations |
38,278 | 22,204 | 48,423 | |||||||||
Cash flows from investing activities from continuing operations: |
||||||||||||
Restricted cash account |
(2,700 | ) | | 2,899 | ||||||||
Business acquisition, net of cash acquired |
| | (5,063 | ) | ||||||||
Principal payments on note receivable |
911 | 3,065 | | |||||||||
Proceeds from sale of assets |
23,982 | 32,375 | 3,965 | |||||||||
Purchase of property and equipment |
(19,177 | ) | (16,462 | ) | (76,793 | ) | ||||||
Net cash provided by (used in) investing activities from continuing operations |
3,016 | 18,978 | (74,992 | ) | ||||||||
Cash flows from financing activities from continuing operations: |
||||||||||||
Proceeds from borrowings |
5,000 | 55,000 | 51,100 | |||||||||
Payments of debt |
(50,986 | ) | (111,184 | ) | (79 | ) | ||||||
Debt issue costs |
| (2,232 | ) | (3,501 | ) | |||||||
Net provided by (used in) financing activities from continuing operations |
(45,986 | ) | (58,416 | ) | 47,520 | |||||||
Net increase (decrease) in cash and cash equivalents from continuing operations |
(4,692 | ) | (17,234 | ) | 20,951 | |||||||
Cash flows from discontinued operations: |
||||||||||||
Operating cash flows |
(16,611 | ) | 5,844 | 10,677 | ||||||||
Investing cash flows |
23,660 | (784 | ) | (7,803 | ) | |||||||
Financing cash flows |
| (5,005 | ) | (2,870 | ) | |||||||
Net increase (decrease) in cash and cash equivalents from discontinued operations |
7,049 | 55 | 4 | |||||||||
Increase (decrease) in cash and cash equivalents |
2,357 | (17,179 | ) | 20,955 | ||||||||
Beginning cash and cash equivalents |
9,497 | 26,676 | 5,721 | |||||||||
Ending cash and cash equivalents |
$ | 11,854 | $ | 9,497 | $ | 26,676 | ||||||
Supplementary disclosure of cash flow information: |
||||||||||||
Interest paid, net of amount capitalized |
$ | 4,026 | $ | 11,549 | $ | 2,704 | ||||||
Income taxes (refunded) paid |
(13,829 | ) | 339 | 198 | ||||||||
Supplementary disclosure of non-cash investing and financing: |
||||||||||||
Purchase of property and equipment in accounts payable |
2,034 | 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 | | |||||||||
Note issued for acquisition of property and equipment |
| | 1,277 | |||||||||
Assets exchanged/sold for equity interest and note receivable |
| | 72,503 | |||||||||
Common stock received for payment of receivable |
| | 1,900 |
The accompanying notes are an integral part of these statements.
52
Table of Contents
Bronco Drilling Company, Inc. and Subsidiaries
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 services to oil
and natural gas exploration and production companies. The accompanying consolidated financial
statements include the Companys 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 Companys actual results could differ significantly from those
estimates. Material estimates that are particularly susceptible to significant changes in the near
term relate to the Companys 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.
Restricted Cash
At December 31, 2010, the Company had restricted cash of $2,700, at a bank in escrow related
to the sale of drilling rigs.
Foreign Currency
The U.S. dollar is the functional currency for the Companys 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
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.
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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.
The asset unbilled receivables represents revenues we have recognized in excess of amounts
billed on drilling contracts in progress or costs deferred on daywork contracts in progress.
Accounts Receivable
The Company records trade accounts receivable at the amount invoiced to customers.
Substantially all of the Companys accounts receivable are due from companies in the oil and gas
industry. Credit is extended based on evaluation of a customers 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 Companys previous loss
history, the customers 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, 2010 and 2009, our allowance for
doubtful accounts was $1,691 and $3,576, 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 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 $14,111 and $26,038 as of December 31, 2010 and 2009, respectively.
The Company capitalizes interest as a component of the cost of drilling rigs constructed for
its own use. For the years ended December 31, 2010 and 2009, the Company did not capitalize any
interest.
The Company
evaluates for potential impairment of long-lived assets held for use 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 estimates 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. See Note 9, Asset Sales and Held for Sale, for discussion of impairment of drilling rigs and related equipment due to their classification as held
for sale. Assets held for sale are recorded at the lower of carrying amount or fair value less cost to
sell. See Note 10, Discontinued Operations, for discussion of well servicing segment
property and equipment impairment relating to its classification as held for sale. The assumptions used in
the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and
require management judgment.
Debt issue costs and other
Debt issue costs and other assets consist of intangibles related to acquisitions, net of
amortization, 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 Companys 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 $78, $751, and $974 for the years
ended December 31, 2010, 2009, and 2008, respectively. Total cost and accumulated amortization of
intangibles at December 31, 2010 and 2009 was $2,318 and $2,318 and $3,705 and $3,403,
respectively.
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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 $2,669 and $2,232 at December 31, 2010 and 2009, respectively. Amortization
expense related to debt issue costs was $688, $592, and $571 for the years ended December 31, 2010,
2009, and 2008, respectively, and is included in interest expense in the consolidated statements of
operations. Accumulated amortization related to loan fees was $864 and $126 as of December 31, 2010
and 2009, 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 enterprises 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,
2010, the tax years ended December 31, 2006 through December 31, 2009 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, 2010 and 2009. The following table sets forth the components of
comprehensive income (loss):
Years ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Net income (loss) |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | |||
Other comprehensive income translation adjustment |
474 | 538 | | |||||||||
Comprehensive income (loss) |
$ | (50,203 | ) | $ | (57,041 | ) | $ | (8,243 | ) | |||
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 Companys 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.
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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 companys 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 companys accounts are not reflected
within the Companys Consolidated Balance Sheets and Statements of Operations; however, the
Companys share of the earnings or losses of the Investee company is reflected in the caption
Equity in income (loss) of Challenger and Equity in income (loss) of Bronco MX in the
Consolidated Statements of Operations. The Companys carrying value in an equity method Investee
company is reflected in the caption Investment in Challenger and Investment in Bronco MX in the
Companys Consolidated Balance Sheets.
Recent Accounting Pronouncements
In December 2010, the FASB issued an accounting standard update that addresses the disclosure
of supplementary pro forma information for business combinations. This update clarifies that when
public entities are required to disclose pro forma information for business combinations that
occurred in the current reporting period, the pro forma information should be presented as if the
business combination occurred as of the beginning of the previous fiscal year when comparative
financial statements are presented. This update is effective prospectively for 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, 2010. Early adoption is permitted. The
Company is currently evaluating the impact, if any, the adoption will have on our consolidated
financial statements.
In January 2010, the FASB issued a new accounting standard which requires reporting entities
to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value
hierarchy established by ASC 820, Fair Value Measurements. Also required will be a reconciliation
of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3
method, which is used to price the hardest to value instruments. Entities will have to provide
fair value measurement disclosures for each class of financial assets and liabilities. The
guidance will be effective for fiscal years beginning after December 15, 2010. The Company is
currently evaluating the impact, if any, the adoption will have on our consolidated financial
statements.
In December 2009, the FASB issued a new accounting standard which updates the
quantitative-based risks and rewards calculation for determining which reporting entity, if any,
has a controlling financial interest in a variable interest entity with an approach focused on
identifying which reporting entity has the power to direct the activities of a variable interest
entity that most significantly impact the entitys economic performance and (1) the obligation to
absorb losses of the entity or (2) the right to receive benefits from the entity. An approach that
is expected to be primarily qualitative will be more effective for identifying which reporting
entity has a controlling financial interest in a variable interest entity. The amendments in this
update also require additional disclosures about an reporting entitys involvement in variable
interest entities, which will enhance the information provided to users of financial statements.
This new standard is effective at the start of a reporting entitys first fiscal year beginning
after January 1, 2010. The adoption of this standard did not impact our consolidated financial
statements.
In October 2009, the FASB issued a new accounting standard that addresses the accounting for
multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately
rather than as a combined unit. This new standard addresses how to separate deliverables and how to
measure and allocate arrangement consideration to one or more units of accounting. Existing
accounting standards require a vendor to use objective and reliable evidence of fair value for the
undelivered items or the residual method to separate deliverables in a multiple-deliverable
arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be
separated in more circumstances than under current requirements. The new standard establishes a
hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to
multiple deliverables. The selling price used will be based on vendor-specific objective evidence
if available, third-party evidence if vendor-specific objective evidence is not available, or
estimated selling price if neither vendor-specific objective evidence nor third-party evidence is
available. The new standard must be prospectively applied to all revenue arrangements entered into
in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011.
The Company is currently evaluating the impact, if any, the adoption
will have on our 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 entitys 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.
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Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to
conform to the current years presentation.
2. Equity Method Investments
On January 4, 2008, we acquired a 25% equity interest in Challenger Limited, in exchange for
six drilling rigs and cash. The Company also sold to Challenger four drilling rigs and ancillary
equipment. The Company recorded equity in loss of investment of $984 and $1,914 for the years
ended December 31, 2010 and 2009, 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.
The Company entered into a term note with Challenger related to the sale of four drilling rigs
and ancillary equipment. 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
collaterized by the assets sold to Challenger. The note receivable from Challenger at December 31,
2010 was $1,607, all of which was classified as current. The note receivable from Challenger at
December 31, 2009 was $2,517.
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 $1,508 and
$2,499 at December 31, 2010 and December 31, 2009, respectively, related to these services
provided.
At December 31, 2010, the book value of the Companys ordinary share investment in Challenger
was $38,730. The Companys 25% interest of the net assets of Challenger was estimated to be
$35,428. The basis difference between the Companys ordinary equity investment in Challenger and
the Companys 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 $324, respectively, at
December 31, 2010. These amounts are being amortized against the Companys 25% interest of
Challengers net income over the estimated useful lives of 15 years for the property, plant and
equipment. Amortization recorded during years ended December 31, 2010 and 2009 was $264 and
$1,026, respectively.
The Company reviews its investment in Challenger 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 in 2008, 2009 and 2010. 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 an impairment charge of $14,442 during 2008. The analysis resulted in a fair value of $39,800 related to our investment in Challenger
as of September 30, 2009, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the
amount of $21,247.
The analysis performed at December 31, 2010, resulted in a fair value of $40,863 related to our
investment in Challenger, which was above the carrying value of the investment and resulted in no
impairment. The estimate of fair value required management to make many estimates and judgments, such as
forecasts of future cash flows, discount rates of approximately 15.0% and long term growth rates
of 3.0% which it believes were reasonable and appropriate at
December 31, 2010. Changes
in such assumptions can result in an estimate of fair value that could be below the
carrying amount of our investment in Challenger.
Recent civil and
political disturbances in Libya the elsewhere in North Africa, and
the Middle East that developed during the first quarter of 2011 may affect Challengers operations. Ongoing
political unrest may result in loss of revenue and damage to equipment. Any impact from the
political turmoil in Libya and elsewhere in North Africa on Challengers operations could
negatively impact the Companys investment in Challenger
including, the entire loss of our investment.
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Summarized financial information of Challenger is presented below:
December 31, | ||||||||
2010 | 2009 | |||||||
Condensed statement of operations: |
||||||||
Revenues |
$ | 49,267 | $ | 56,509 | ||||
Gross margin |
$ | 12,616 | $ | 21,076 | ||||
Net Income (loss) |
$ | (2,931 | ) | $ | (3,552 | ) | ||
Condensed balance sheet: |
||||||||
Current assets |
$ | 61,147 | $ | 59,971 | ||||
Noncurrent assets |
124,494 | 130,667 | ||||||
Total assets |
$ | 185,641 | $ | 190,638 | ||||
Current liabilities |
$ | 28,788 | $ | 25,511 | ||||
Noncurrent liabilities |
15,189 | 20,531 | ||||||
Equity |
141,664 | 144,596 | ||||||
Total liabilities and equity |
$ | 185,641 | $ | 190,638 | ||||
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. Upon closing of the transaction,
the Company owned 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 general
specifications of the contributed rigs are as follows:
Approximate | ||||||||
Drilling Depth | ||||||||
Rig | Design | (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 |
The Company received $31,735 from CICSA in exchange for the 60% membership interest in Bronco
MX, which included reimbursement for 60% of value added taxes previously paid by, or on behalf of,
Bronco MX as a result of the importation to Mexico of the six drilling rigs that were contributed
by the Company to Bronco MX. Upon completion of the transaction, the Company treated Bronco MX as
a deconsolidated subsidiary in order to compute a loss in accordance with ASC Topic 810,
Consolidation, due to the Company not retaining a controlling financial interest in Bronco MX
subsequent to the sale. The Company recorded a net loss of $23,964 for the nine months ended
September 30, 2009 relating to the transactions. The loss was computed based on the proceeds
received from CICSA of $31,735 and the value of the Companys 40% retained interest in Bronco MX of
$21,495 less the book value of the net assets of Bronco MX, including rigs contributed to Bronco
MX, of $77,194. The Company recorded a negative adjustment to the loss during the year ended
December 31, 2010 of $1,487 due to post closing adjustments. Fair value of the Companys 40%
investment in Bronco MX was estimated using 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 Companys 40% retained interest in Bronco MX. At December 31,
2010, the book value of the Companys ordinary share investment in Bronco MX was $20,632. The
Company recorded equity in income (loss) of investment of $22 and ($588) for the year ended
December 31, 2010 and for the period September 18 through December 31, 2009, respectively, related
to its equity investment in Bronco MX. The Companys investment in Bronco MX was increased by $474
as a result of a currency translation gain for the year ended December 31, 2010.
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On July 1, 2010, CICSA contributed cash of approximately $45,100 in exchange for 735,356,219
shares of Bronco MX. As a result of the contribution, the Companys membership interest in Bronco
MX was decreased to approximately 20%. The Company accounted for the share issuance as if the
Company had sold a proportionate amount of its shares. The Company recorded a loss on the
transaction in the amount of $1,271.
Bronco MX is jointly managed, with CICSA having four representatives on its board of managers
and the Company having one representative 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 MXs 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, the Slim Affiliates), these
individuals and entities collectively beneficially own approximately 19.99% of our common stock.
CICSA is also a Slim Affiliate.
Summarized financial information of Bronco MX is presented below:
December 31, | ||||||||
2010 | 2009 | |||||||
Condensed statement of operations: |
||||||||
Revenues |
$ | 34,128 | $ | 7,171 | ||||
Gross margin |
$ | 765 | $ | (2,582 | ) | |||
Net Income (loss) |
$ | 826 | $ | (1,472 | ) | |||
Condensed balance sheet: |
||||||||
Current assets |
$ | 25,497 | $ | 8,931 | ||||
Noncurrent assets |
100,687 | 57,746 | ||||||
Total assets |
$ | 126,184 | $ | 66,677 | ||||
Current liabilities |
$ | 23,031 | $ | 13,162 | ||||
Noncurrent liabilities |
| | ||||||
Equity |
103,153 | 53,515 | ||||||
Total liabilities and equity |
$ | 126,184 | $ | 66,677 | ||||
3. Accrued liabilities
Accrued liabilities consisted of the following at December 31, 2010 and 2009:
2010 | 2009 | |||||||
Salaries, wages, payroll taxes and benefits |
$ | 1,252 | $ | 623 | ||||
Workers compensation liability |
3,695 | 2,458 | ||||||
Sales, use and other taxes |
829 | 2,211 | ||||||
Health insurance |
735 | 784 | ||||||
Deferred revenue |
755 | 1,251 | ||||||
General liability insurance |
500 | 500 | ||||||
Accrued interest |
81 | 125 | ||||||
$ | 7,847 | $ | 7,952 | |||||
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4. Long-term Debt and Warrant
Long-term debt consists of the following:
December 31, | December 31, | |||||||
2010 | 2009 | |||||||
Revolving credit facility with Banco Inbursa S.A., collateralized by the Companys assets,
and matures on September 17, 2014. Loans under the revolving credit facility
bear interest at variable rates as defined in the credit agreement. Presented net of discount of $3,548 and $4,455 at December 31, 2010 and 2009, respectively. (1) |
5,555 | 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. (2) |
1,270 | 1,358 | ||||||
6,825 | 51,903 | |||||||
Less current installments |
95 | 89 | ||||||
6,730 | 51,814 | |||||||
(1) | On September 18, 2009, the Company entered into a new senior secured revolving credit facility with Banco Inbursa S.A., or 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 interests of Bronco MX and (iii) cash-on-hand to repay all amounts outstanding under the Companys prior revolving credit agreement with Fortis Bank SA/NV, New York Branch, which was replaced by this credit facility. |
The credit facility initially provided for revolving advances of up to $75.0 million and the
borrowing base under the credit facility was initially set at $75.0 million, subject to
borrowing base limitations. On February 9, 2011 we amended our credit facility which
reduced the commitment to $45.0 million. The credit facility matures on September 17, 2014.
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 6.05% at December 31, 2010. The Company incurred $2,232 in debt issue costs
related to this credit facility.
The Company pays 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 Companys 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 Companys direct and indirect subsidiaries. Commitment
fees expense for the years ended December 31, 2010 and 2009 was $125 and $15, respectively.
The credit facility contains customary representations and warranties and various
affirmative and negative covenants, including, but not limited to, covenants that restrict
the Companys 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.
The Company was in compliance with all covenants at
December 31, 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 Companys 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
Companys 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 September 18, 2009, 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. Banco Inbursa subsequently transferred the
Warrant to CICSA.
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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 Companys 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 is amortized to interest expense
over the term of the revolving credit facility. 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 years ended December 31, 2010 and
December 31, 2009 was $907 and $224, respectively.
In accordance with accounting standards, the Company revalued the Warrant as of December 31,
2010 and 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 volatilities of 50% and 45% and a risk
free interest rate that ranged from 0.22% to 0.54% and 0.40% to 1.45% for 2010 and 2009,
respectively. The fair value of the Warrant was $4,407 and $2,829 at December 31, 2010 and
December 31, 2009, respectively. The Company recorded a gain (loss) on the change in the
fair value of the Warrant on the consolidated statement of operations in the amount of
$(1,578) and $1,850 for the years ended December 31, 2010 and December 31, 2009,
respectively.
(2) | 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. |
Long-term debt maturing each year subsequent to December 31, 2010 is as follows:
2011 |
$ | 95 | ||
2012 |
100 | |||
2013 |
107 | |||
2014 |
9,216 | |||
2015 |
120 | |||
2016 and thereafter |
735 | |||
$ | 10,373 | |||
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 enterprises 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,
2010, 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, 2010, the tax years ended December 31, 2006 through December 31, 2009 are open for
examination by U.S. taxing authorities.
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Income tax expense (benefit) consists of the following:
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Current: |
||||||||||||
State |
$ | 212 | $ | 28 | $ | (165 | ) | |||||
Federal |
874 | (1,419 | ) | (874 | ) | |||||||
Deferred: |
||||||||||||
State |
(3,133 | ) | (1,660 | ) | (432 | ) | ||||||
Federal |
(16,088 | ) | (24,100 | ) | (3,868 | ) | ||||||
Income tax expense (benefit) |
$ | (18,135 | ) | $ | (27,151 | ) | $ | (5,339 | ) | |||
Deferred income tax assets and liabilities are as follows:
Years Ended December 31, | ||||||||
2010 | 2009 | |||||||
Deferred tax assets: |
||||||||
Stock option expense |
$ | 2,369 | $ | 2,607 | ||||
Alternative minimum tax credit carryforward |
| 2,225 | ||||||
Net operating loss carryforwards |
27,903 | 37,905 | ||||||
Accounts receivable allowance |
341 | 1,383 | ||||||
Tax credits |
| | ||||||
Employee benefits and insurance accruals |
277 | 303 | ||||||
Other |
2,987 | 1,093 | ||||||
Total deferred tax assets |
33,877 | 45,516 | ||||||
Deferred tax liabilities: |
||||||||
Property and equipment, principally due
to differences in depreciation and
impairments |
52,712 | 76,964 | ||||||
Other |
64 | 64 | ||||||
Total deferred tax liabilities |
52,776 | 77,028 | ||||||
Net deferred tax liabilities |
$ | 18,899 | $ | 31,512 | ||||
In assessing its ability to realize deferred tax assets, the Company considers whether it is
more likely than not that some portion or all of the deferred tax assets will not be realized.
Ultimate realization of deferred tax assets depends on the generation of future taxable income
during the periods in which those temporary differences become deductible. The Company considers
the scheduled reversal of deferred tax liabilities and projected future taxable income in making
this assessment. The Company believes it is more likely than not that it will realize the benefits
of these deductible differences.
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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, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Expected tax expense (benefit) |
$ | (17,473 | ) | $ | (25,783 | ) | $ | (4,870 | ) | |||
State income taxes (benefit) |
(2,977 | ) | (2,201 | ) | (345 | ) | ||||||
Nondeductible officer compensation |
155 | 121 | 330 | |||||||||
Nondeductible meals and entertainment |
26 | 19 | 68 | |||||||||
Stock compensation adjustment |
447 | 783 | | |||||||||
Goodwill impairment |
| | 1,125 | |||||||||
Foreign tax expense/(credit) |
1,019 | (660 | ) | (832 | ) | |||||||
Prior year estimate adjustment |
630 | 356 | (295 | ) | ||||||||
Other |
38 | 214 | (520 | ) | ||||||||
$ | (18,135 | ) | $ | (27,151 | ) | $ | (5,339 | ) | ||||
6. Workers Compensation and Health Insurance
The Company is insured under a large deductible workers compensation insurance policy. The
policy generally provides for a $500 deductible per covered accident. The Company maintains letters
of credit in the aggregate amount of $11,460 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, 2010 and 2009
included approximately $3,695 and $2,458, 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, 2010 and 2009 included
approximately $735 and $784, respectively, for our estimate of incurred but not reported costs
related to the self-insurance portion of our health insurance.
7. Transactions with Affiliates
During 2009, the Company had 6 operating leases with affiliated entities. As of January 9,
2010, these entities are no longer affiliated entities. Related rent expense was approximately
$520 for the year ended December 31, 2009.
The Company had receivables from affiliates of $1,508 and $9,620 at December 31, 2010 and
2009, respectively.
Additional information about our transactions with affiliates is included in Note 2, Equity
Method Investments.
8. Commitments and Contingencies
The Company leases 14 service locations under noncancelable operating leases that have various
expirations from 2011 to 2015. Related rent expense was $986, $1,194, and $1,064 for the years
ended December 31, 2010, 2009, and 2008, respectively.
Aggregate future minimum lease payments under the noncancelable operating leases for
years subsequent to December 31, 2010 are as follows:
2011 |
$ | 770 | ||
2012 |
554 | |||
2013 |
401 | |||
2014 |
230 | |||
2015 |
77 | |||
$ | 2,032 | |||
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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 Companys consolidated
financial position, results of operations or cash flows.
9. Asset Sales and Held for Sale
On September 21, 2010 through September 23, 2010, the Company sold at auction in separate lots
to multiple bidders two complete drilling rigs and components comprising four other drilling rigs
(rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at
auction were not being utilized currently in the Companys business. The Company received net
proceeds of approximately $8,286, net of selling expenses of $817, for the drilling rigs and
related equipment. The Company recorded losses of $19,892 related to the sale of the drilling rigs
and ancillary equipment. The loss was based on net book values of approximately $28,178 for the
drilling rigs and ancillary equipment. The Company used the entire proceeds to pay down existing
indebtedness under its revolving credit facility.
In an unrelated transaction on September 23, 2010, the Company sold two drilling rigs (rigs 41
and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party, for net proceeds of
$7,173. The Company recorded a $1,685 loss on the sale of these assets based on a net book value
of $8,858.
The decision was made by management in the third quarter to sell an additional five drilling
rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs meet the held for sale criteria, the
Company is required to present such assets, comprised of property and equipment, at the lower of
carrying amount or fair value less the anticipated costs to sell. The Company evaluated these
assets for impairment as of September 30, 2010 and December 31,
2010, for the year ended 2010, which resulted in recognizing a $7,900 impairment
charge. Rig 6 is the only
drilling rig unsold at December 31, 2010 with a carrying value of $1,550, which is the anticipated
sale price, and is included in Non-current assets held for sale in our Consolidated Balance Sheets.
At December 31, 2010, the Companys fair value estimate was derived from negotiated prices with
interested parties. The drilling rigs and related equipment were included as part of our land
drilling segment.
On November 17, 2010, the Company sold at auction in separate lots to multiple bidders two
complete drilling rigs (rigs 51 & 54) and ancillary equipment. The drilling rigs and equipment
sold at auction were not being utilized currently in the Companys business. The Company received
net proceeds of approximately $1,666, net of selling expenses of $115, for the drilling rigs and
related equipment. The Company recorded losses of $2,169 related to the sale of the drilling rigs
and ancillary equipment. The loss was based on net book values of approximately $3,835 for the
drilling rigs and ancillary equipment.
On
November 29, 2010, the Company sold two drilling rigs (rigs 5
and 7) and entered into a contract to sell one drilling rig (rig 6) in a private sale to
Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $2,700. The
Company recorded a $14 gain on the sale of these assets based on a net book value of $2,686.
The drilling rigs and related equipment sold at auction and the drilling rig held for sale are
being sold as part of a broader strategy by management to divest of older drilling rigs and use the
proceeds to pay down existing indebtedness.
10. Discontinued Operations
Well Servicing
In the second quarter of 2010, management determined that our well servicing business segment
was no longer consistent with the Companys long-term strategic objectives and that the Company
should seek to market this business for sale. During Q1 and Q2 2010 the market for workover
services continued at depressed levels within the primary geographic market of our well servicing
assets (Oklahoma). Management determined that higher return projects were available within the
core drilling segment of the business and chose to deploy capital in this segment rather than
commit the capital required to restructure operations in the well servicing segment. In late June
management made a decision to market the assets
constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and
to support the Companys core drilling business. As of June 30, 2010, the well servicing property
and equipment was classified as held for sale in our Consolidated Balance Sheets and well servicing
operating results as discontinued operations in our Consolidated Statements of Operations. Well
servicing was previously presented as its own reportable segment.
Because the well servicing assets met the held for sale criteria, the Company was required to
present such assets, comprised of property and equipment, at the lower of carrying amount or fair
value less the anticipated cost to sell. In connection with its June 30, 2010 quarterly report,
the Company evaluated well servicings respective assets held for sale for impairment. The
Companys analysis as of June 30, 2010 resulted in recognizing a $23,376 impairment charge ($14,329
after tax). This second quarter charge is reflected as a component of loss from discontinued
operations in the Companys Consolidated Statements of Operations for the year ended.
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In September 2010, substantially all of the assets of the well servicing segment were
sold at auction to multiple bidders. The Company received proceeds of $12,362, net of selling
expenses of $638. The sale of the assets of the well servicing segment resulted in a loss of
$8,915, which is reflected as a component of loss from discontinued operations in the Companys
Consolidated Statements of Operations. The Company used the proceeds to pay down existing
indebtedness under its revolving credit facility. The Company has one workover rig held for sale
at December 31, 2010, with a carrying amount of $130. The Company recorded an impairment charge of
$318 related to this workover rig during the third quarter.
The results of
operations for the years ended December 31, 2010, 2009 and 2008 are below:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Revenue |
$ | | $ | 3,799 | $ | 33,284 | ||||||
Impairment of assets held for sale |
$ | 23,694 | $ | | $ | | ||||||
Loss from discontinued operations
before income tax |
$ | (36,383 | ) | $ | (10,094 | ) | $ | (3,555 | ) | |||
Income tax
benefit |
$ | (14,079 | ) | $ | (3,906 | ) | $ | (131 | ) | |||
Loss on sale
of well servicing assets |
$ | (8,915 | ) | $ | | $ | |
At June 30, 2010, the Companys fair value estimate was derived from an appraisal performed
specific to the property and equipment of the Companys well servicing segment. Refer to Note 12,
Fair Value Measurements, for further discussion.
Trucking Assets
In July 2010, the Company completed the sale of all of the Companys trucking assets, property
and equipment, for $11,299 in cash, net of selling expenses of $403. As drilling activity
decreased in 2008 and 2009 the utilization of these trucking assets fell sharply. The ongoing
operating losses in our trucking division required resources to be directed away from the core
drilling business. As such, management made the decision in the second quarter 2010 to sell these
assets as their operations were not considered core. Proceeds from this sale were used to prepay
existing indebtedness under our revolving credit facility with Banco Inbursa in July 2010. Based
on the proceeds received and net book value of the property and equipment in the amount of $337,
the Company recognized a gain of $10,962 in the third quarter of 2010. Operating results and the
gain on sale of such assets are included as a component of discontinued operations in our
Consolidated Statements of Operations for all periods presented. The trucking assets and operating
activities were previously presented as part of our land drilling reportable segment. The results
of operations for the years ended December 31, 2010, 2009 and
2008 are below:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Revenue |
$ | 1,133 | $ | 3,842 | $ | 13,907 | ||||||
Income (loss) from discontinued
operations before income tax |
$ | 10,005 | $ | (5,301 | ) | $ | 805 | |||||
Income tax
expense (benefit) |
$ | 3,873 | $ | (2,052 | ) | $ | 311 | |||||
Gain on sale of trucking assets |
$ | 10,962 | $ | | $ | |
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11. 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, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Basic: |
||||||||||||
Continuing operations |
(34,505 | ) | (48,142 | ) | (5,315 | ) | ||||||
Discontinued operations |
(16,172 | ) | (9,437 | ) | (2,928 | ) | ||||||
Net loss |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | |||
Weighted average shares (thousands) |
27,091 | 26,651 | 26,293 | |||||||||
Continuing operations per share |
(1.27 | ) | (1.81 | ) | (0.20 | ) | ||||||
Discontinued operations per share |
(0.60 | ) | (0.35 | ) | (0.11 | ) | ||||||
Net loss per share |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | |||
Diluted: |
||||||||||||
Continuing operations |
(34,505 | ) | (48,142 | ) | (5,315 | ) | ||||||
Discontinued operations |
(16,172 | ) | (9,437 | ) | (2,928 | ) | ||||||
Net Loss |
$ | (50,677 | ) | $ | (57,579 | ) | $ | (8,243 | ) | |||
Weighted average shares: |
||||||||||||
Outstanding (thousands) |
27,091 | 26,651 | 26,293 | |||||||||
Restricted Stock and Options (thousands) |
| | | |||||||||
27,091 | 26,651 | 26,293 | ||||||||||
Continuing operations per share |
(1.27 | ) | (1.81 | ) | (0.20 | ) | ||||||
Discontinued operations per share |
(0.60 | ) | (0.35 | ) | (0.11 | ) | ||||||
Income (loss) per share |
$ | (1.87 | ) | $ | (2.16 | ) | $ | (0.31 | ) | |||
The weighted average number of diluted shares excludes 87,850, 89,108, and 82,962 shares for
the years ended December 31, 2010, 2009 and 2008, respectively, subject to restricted stock awards
due to their antidilutive effects.
12. 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 entitys 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.
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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, 2010 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 50% and a risk free interest rate that ranged from 0.22% to
0.54%. The fair value of the Warrant was $4,407 at December 31, 2010. The Company recorded a
change in the fair value of the Warrant on the consolidated statement of operations in the amount
of $(1,578) and $1,850 for the years ended December 31, 2010 and 2009, respectively.
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 Companys 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.
In the second quarter of 2010, management determined that our well servicing business segment
was no longer consistent with the Companys long-term strategic objectives and that the Company
should seek to market this business for sale. Because the well servicing property and equipment
met the held for sale criteria, the Company was required to present its assets held for sale at the
lower of carrying amount or fair value less the anticipated cost to sell. The Company evaluated
well servicings respective assets held for sale for impairment. The fair value of the well
servicing assets was determined using level 3 inputs. The Company engaged a third party
independent appraisal company to determine the fair value of the well servicing assets. The
appraised value was based on an on-site inspection of the assets and market research and analysis
of applicable data. The Companys analysis as of June 30, 2010 resulted in a $23,376 impairment
charge ($14,329 after tax). This charge was recorded in the second quarter of 2010 and is
reflected as a component of income (loss) from discontinued operations in the Companys
Consolidated Statements of Operations.
In the third quarter of 2010, management made the decision to divest of older drilling rigs
and use the proceeds to pay down existing indebtedness. Consequently, management decided to sell
five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs meet the held for sale
criteria, the Company is required to present these assets held for sale at the lower of carrying
amount or fair value less anticipated cost to sell. The Company evaluated these assets as of
September 30, 2010, for impairment. The fair value of the drilling rigs was determined using level
3 inputs. The fair value was determined by the sale price of similar assets sold by the Company in
an auction during the third quarter and negotiated prices with interested parties. The analysis as
of September 30, 2010 resulted in $7,761 impairment charge. The Company recorded an additional
impairment during the fourth quarter of $139.
The Company reviewed its investment in Challenger at December 31, 2010 for impairment due to
the recent volatility in oil and natural gas prices, the global economic environment and the
anticipated future earnings of Challenger. 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 $40,863 related to our
investment in Challenger, which was above the carrying value of the investment and resulted in no
impairment. The estimate of fair value required management to make many estimates and judgements,
such as forecasts of future cash flows, discount rates of 15.0% and long term growth rates
of 3.0% which it believes were reasonable and appropriate at December 31, 2010. Changes
in such assumptions can result in an estimate of fair value that could be below the carrying amount
of our investments in Challenger.
13. Restricted Stock
The Companys 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. Effective
December 10, 2010, the Companys board of directors and a majority of our shareholders approved an
amendment to the 2006 Plan to increase the shares available for issuance thereunder by 2,500,000
shares. 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.
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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 5,000,000 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 2,549,878 at December 31, 2010.
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, 2010, 2009 and 2008 related to shares of restricted stock was $3,274,
$3,301, and $5,825, respectively. Restricted stock activity for the years ended December 31, 2010,
2009 and 2008 was as follows:
Weighted Average | ||||||||
Grant Date | ||||||||
Shares | Fair Value | |||||||
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 | |||||
Granted |
1,247,000 | 4.74 | ||||||
Vested |
(529,102 | ) | 7.35 | |||||
Forfeited/expired |
| | ||||||
Outstanding at December 31, 2010 |
1,222,496 | $ | 4.82 | |||||
There was $3,863,209 of total unrecognized compensation cost related to nonvested restricted
stock awards to be recognized over a weighted-average period of 1.18 years as of December 31, 2010.
14. 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.
15. 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 Companys contributions for the years
ended December 31, 2010, 2009 and 2008 were $548, $628, and $1,093, respectively.
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16. Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for our years ended December 31, 2010
and 2009;
Bronco Drilling Company Inc.
Quarterly Results
Year Ended December 31, 2010
(Amounts in thousands except per share amounts)
(Unaudited)
Quarterly Results
Year Ended December 31, 2010
(Amounts in thousands except per share amounts)
(Unaudited)
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter (1) | Quarter (2) | |||||||||||||
2010 |
||||||||||||||||
Revenues |
$ | 22,295 | $ | 29,938 | $ | 34,837 | $ | 37,329 | ||||||||
Loss from continuing operations before
income tax |
(8,626 | ) | (8,907 | ) | (31,796 | ) | (3,311 | ) | ||||||||
Income tax benefit |
(2,621 | ) | (2,341 | ) | (12,126 | ) | (1,047 | ) | ||||||||
Loss from continuing operations |
(6,005 | ) | (6,566 | ) | (19,670 | ) | (2,264 | ) | ||||||||
Income (loss) from discontinued operations |
(1,414 | ) | (15,371 | ) | 846 | (233 | ) | |||||||||
Net loss |
(7,419 | ) | (21,937 | ) | (18,824 | ) | (2,497 | ) | ||||||||
Income (loss) per common share-Basic |
||||||||||||||||
Continuing operations |
$ | (0.23 | ) | $ | (0.24 | ) | $ | (0.72 | ) | $ | (0.08 | ) | ||||
Discontinued operations |
(0.05 | ) | (0.57 | ) | 0.03 | (0.01 | ) | |||||||||
Loss per common share-Basic |
$ | (0.28 | ) | $ | (0.81 | ) | $ | (0.69 | ) | $ | (0.09 | ) | ||||
Income (loss) per common share-Diluted |
||||||||||||||||
Continuing operations |
$ | (0.23 | ) | $ | (0.24 | ) | $ | (0.72 | ) | $ | (0.08 | ) | ||||
Discontinued operations |
(0.05 | ) | (0.57 | ) | 0.03 | (0.01 | ) | |||||||||
Loss per common share-Diluted |
$ | (0.28 | ) | $ | (0.81 | ) | $ | (0.69 | ) | $ | (0.09 | ) | ||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter (3) | Quarter | |||||||||||||
2009 |
||||||||||||||||
Revenues |
$ | 45,282 | $ | 25,894 | $ | 15,826 | $ | 15,894 | ||||||||
Income (loss) from continuing
operations before income tax |
1,558 | (6,753 | ) | (64,152 | ) | (5,946 | ) | |||||||||
Income tax expense (benefit) |
1,251 | (2,361 | ) | (23,716 | ) | (2,325 | ) | |||||||||
Income (loss) from continuing operations |
307 | (4,392 | ) | (40,436 | ) | (3,621 | ) | |||||||||
Loss from discontinued operations |
(2,016 | ) | (2,766 | ) | (2,218 | ) | (2,437 | ) | ||||||||
Net loss |
(1,709 | ) | (7,158 | ) | (42,654 | ) | (6,058 | ) | ||||||||
Income (loss) per common share-Basic |
||||||||||||||||
Continuing operations |
$ | 0.01 | $ | (0.17 | ) | $ | (1.52 | ) | $ | (0.13 | ) | |||||
Discontinued operations |
(0.07 | ) | (0.10 | ) | (0.08 | ) | (0.10 | ) | ||||||||
Loss per common share-Basic |
$ | (0.06 | ) | $ | (0.27 | ) | $ | (1.60 | ) | $ | (0.23 | ) | ||||
Income (loss) per common share-Diluted |
||||||||||||||||
Continuing operations |
$ | 0.01 | $ | (0.17 | ) | $ | (1.52 | ) | $ | (0.13 | ) | |||||
Discontinued operations |
(0.07 | ) | (0.10 | ) | (0.08 | ) | (0.10 | ) | ||||||||
Loss per common share-Diluted |
$ | (0.06 | ) | $ | (0.27 | ) | $ | (1.60 | ) | $ | (0.23 | ) | ||||
(1) | Includes $7,761 of impairment of drilling rigs and related equipment and $20,809 of loss on sale of drilling rigs and related equipment. | |
(2) | Includes $2,923 of loss on sale of drilling rigs and related equipment. | |
(3) | Includes $21,247 of impairment to our Challenger Investment and $23,964 loss on Bronco MX transaction. |
17. Valuation and Qualifying Accounts
The Companys valuation and qualifying accounts for the years ended December 31, 2010, 2009
and 2008 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, 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 | |||||||
Year ended December
31, 2010 |
||||||||||||||||
Allowance for
doubtful
receivables |
$ | 3,576 | $ | 2,692 | $ | (4,577 | ) | $ | 1,691 | |||||||
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Table of Contents
18. Subsequent Events
On February 9, 2011, the Company entered into an amendment to its revolving credit facility
(the Amended Credit Facility) with Banco Inbursa S.A., Institucion de Banca Multiple, Grupo
Financiero Inbursa. The Amended Credit Facililty reduced the commitment of the lender from $75,000
to $45,000 and reduced the number of drilling rigs pledged as collateral thereunder.
On February 25, 2011, the Company entered into a purchase and sale agreement to sell two
drilling rigs (rigs 56 and 62) to Windsor Drilling LLC. The Company expects to record a loss on
the sale of the drilling rigs of approximately $1,703 based on estimated proceeds of $11,500 and a net
book value of $13,203.
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Table of Contents
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 15, 2011 | 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 persons 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
|
Chief Executive, President and Director (Principal Executive Officer) |
March 15, 2011 | ||
/S/ Matthew S. Porter
|
Chief Financial Officer (Principal Accounting and Financial Officer) |
March 15, 2011 | ||
/S/ David House
|
Director | March 15, 2011 | ||
/S/ Richard B. Hefner
|
Director | March 15, 2011 | ||
/S/ Gary Hill
|
Director | March 15, 2011 | ||
/S/ William R. Snipes
|
Director | March 15, 2011 |
71