UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| (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, 2007 |
| 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 1-2199
ALLIS-CHALMERS ENERGY INC.
(Exact name of registrant as specified in its charter)
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| Delaware | | 39-0126090 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) |
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5075 WESTHEIMER, SUITE 890
HOUSTON, TEXAS | | 77056
(Zip code) |
| (Address of principal executive offices) | | |
(713) 369-0550
Registrant’s telephone number, including area code
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Title of Security: | | Name of Exchange: |
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| Common Stock, par value $0.01 per share | | New York Stock Exchange |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d). 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 if disclosure of delinquent filers pursuant to ITEM 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” inRule 12b-2 of the Exchange Act. (Check one):
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| Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the common equity held by non-affiliates of the registrant, computed using the closing price of the common stock of $22.99 per share on June 30, 2007, as reported on the New York Stock Exchange, was approximately $462,009,706 (affiliates included for this computation only: directors, executive officers and holders of more than 5% of the registrant’s common stock).
As of February 29, 2008 there were 35,130,914 shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Certain information called for by Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this annual report onForm 10-K or incorporated by reference from the registrant’s definitive proxy statement for its 2008 annual meeting of stockholders.
DEFINITIONS
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| “air drilling” | | A technique in which oil, natural gas, or geothermal wells are drilled by creating a pressure within the well that is lower than the reservoir pressure. The result is increased rate of penetration, reduced formation damage and reduced drilling costs. |
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| “blow out preventors” | | A large safety device placed on the surface of an oil or natural gas well to maintain high pressure well bores. |
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| “booster” | | A machine that increases the pressure and/or volume of air when used in conjunction with a compressor or a group of compressors. |
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| “capillary tubing” | | A small diameter tubing installed in producing wells and through which chemicals are injected to enhance production and reduce corrosion and other problems. |
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| “casing” | | A pipe placed in a drilled well to secure the well bore and formation. |
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| “choke manifolds” | | An arrangement of pipes, valves and special valves on the rig floor that controls pressure during drilling by diverting pressure away from the blow-out preventors and the annulus of the well. |
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| “coiled tubing” | | A small diameter tubing used to service producing and problematic wells and to work in high pressure applications during drilling, production and workover operations. |
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| “directional drilling” | | The technique of drilling a well while varying the angle of direction of a well and changing the direction of a well to hit a specific target. |
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| “double studded adapter” | | A device that joins two dissimilar connections on certain equipment, including valves, piping and blow-out preventers. |
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| “drill pipe” | | A pipe that attaches to the drill bit to drill a well. |
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| “foam unit” | | A compressor, a booster, a mist pump and a fuel tank all mounted together on one flat bed trailer to be used for completion, workover and/or shallow drilling operations. Foam units are designed to provide a small footprint and easy transport. |
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| “horizontal drilling” | | The technique of drilling wells at a90-degree angle. |
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| “laydown machines” | | A truck mounted machine used to move drill pipe, casing and tubing onto a pipe rack (from which a derrick crane lifts the drill pipe, casing and tubing and inserts it into the well). |
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| “land drilling rig” | | Composed of a drawworks or hoist, a derrick, a power plant, rotating equipment and pumps to circulate the drilling fluid and the drill string. |
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| “logging-while-drilling” | | The technique of measuring, in real time, the formation pressure and the position of equipment inside of a well. |
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| “measurement-while-drilling” | | The technique used to measure direction and angle while drilling a well. |
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| “mist pump” | | A drilling pump that uses mist as the circulation medium for injecting small amounts of foaming agent, corrosion agent and other chemical solutions into the well. |
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| “pulling rig” | | A type of well-servicing rig used to pull downhole equipment, such as tubing, rods or the pumps from a well, and replace them when |
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| | necessary. A pulling rig is also used to set downhole tools and perform lighter jobs. |
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| “spacer spools” | | High pressure connections or links which are stacked to elevate the blow out preventors to the drilling rig floor. |
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| “spiral heavy weight drill pipe” | | A heavy drill pipe used for special applications primarily in directional drilling. The “spiral” design increases flexibility and penetration of the pipe. |
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| “straight-hole drilling” | | The technique of drilling that allows very little or no vertical deviation. |
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| “test plugs” | | A device used to test the connections of well heads and the blow out preventors. |
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| “torque turn service” or “torque turn equipment” | | A monitoring device to insure proper makeup of the casing. |
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| “tubing” | | A pipe placed inside the casing to allow the well to produce. |
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| “tubing work strings” | | The tubing used on workover rigs through which high pressure liquids, gases or mixtures are pumped into a well to perform production operations. |
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| “wear bushings” | | A device placed inside a wellhead to protect the wellhead from wear. |
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| “workover rigs” | | Similar to a land drilling rig, however, they are smaller than the drilling rig for the same depth of well. These rigs are used to complete the drilled wells or to repair them whenever necessary. |
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SPECIAL NOTE
REGARDING FORWARD-LOOKING STATEMENTS
This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, regarding our business, financial condition, results of operations and prospects. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements. However, these are not the exclusive means of identifying forward-looking statements. Although such forward-looking statements reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Further information about the risks and uncertainties that may impact us are described in “Risk Factors” beginning on page 14 of this annual report. You should read those sections carefully. You should not place undue reliance on forward-looking statements, which speak only as of the date of this annual report. We undertake no obligation to update publicly any forward-looking statements in order to reflect any event or circumstance occurring after the date of this annual report or currently unknown facts or conditions or the occurrence of unanticipated events.
PART I.
ITEM 1. BUSINESS
We provide services and equipment to oil and natural gas exploration and production companies throughout the United States including Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: Rental Services; International Drilling; Directional Drilling; Tubular Services; Underbalanced Drilling and Production Services. Our central operating strategy is to provide high-quality, technologically advanced services and equipment. As a result of our commitment to customer service, we have developed strong relationships with many of the leading oil and natural gas companies, including both independents and majors.
Our growth strategy is focused on identifying and pursuing opportunities in markets we believe are growing faster than the overall oilfield services industry in which we believe we can capitalize on our competitive strengths. Over the past several years, we have significantly expanded the geographic scope of our operations and the range of services we provide through strategic acquisitions and organic growth. Our organic growth has primarily been achieved through expanding our geographic scope, acquiring complementary property and equipment, hiring personnel to service new regions and cross-selling our products and services. Since 2001, we have completed 23 acquisitions, including six in 2005, six in 2006 and four in 2007.
Unless the context requires otherwise, references in this annual report to “Allis-Chalmers,” “we”, “us”, “our” and “ours” refer to Allis-Chalmers Energy Inc., together with its subsidiaries.
Our annual reports onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are made available free of charge on our website atwww.alchenergy.com as soon as reasonably practicable after we electronically file or furnish them to the Securities and Exchange Commission, or SEC.
We have adopted a Code of Business Ethics and Conduct to provide guidance to our directors, officers and employees on matters of business ethics and conduct. Our Code of Business Ethics and Conduct is available on the investor relations section of our website.
Information contained on or connected to our website is not incorporated by reference into this annual report onForm 10-K and should not be considered part of this report or any other filing we make with the SEC.
Divisional and geographic financial information appears in “Item 8. Financial Information — Notes to Consolidated Financial Statements — Note 14.”
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Our History
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| | • | We were incorporated in 1913 under Delaware law. |
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| | • | We reorganized in bankruptcy in 1988 and sold all of our major businesses. From 1988 to May 2001 we had only one operating company in the equipment repair business. |
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| | • | In May 2001, under new management we consummated a merger in which we acquired Oil Quip Rentals, Inc., or Oil Quip, and its wholly-owned subsidiary, Mountain Compressed Air, Inc., or MCA. |
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| | • | In December 2001, we sold Houston Dynamic Services, Inc., our last pre-bankruptcy business. |
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| | • | In February 2002, we acquired approximately 81% of the capital stock of Allis-Chalmers Tubular Services Inc., or Tubular, formerly known as Jens’ Oilfield Service, Inc. and substantially all of the capital stock of Strata Directional Technology, Inc., or Strata. |
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| | • | In July 2003, we entered into a limited liability company operating agreement with M-I L.L.C., or M-I, a joint venture between Smith International and Schlumberger N.V., to form a Delaware limited liability company named AirComp LLC, or AirComp. Pursuant to this agreement, we owned 55% and M-I owned 45% of AirComp. |
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| | • | In September 2004, we acquired the remaining 19% of the capital stock of Tubular. |
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| | • | In September 2004, we acquired all of the outstanding stock of Safco-Oil Field Products, Inc., or Safco. |
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| | • | In November 2004, AirComp acquired substantially all of the assets of Diamond Air Drilling Services, Inc. and Marquis Bit Co., LLC, which we refer to collectively as Diamond Air. |
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| | • | In December 2004, we acquired Downhole Injection Services, LLC, or Downhole. |
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| | • | In April 2005, we acquired all of the outstanding stock of Delta Rental Service, Inc., or Delta. |
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| | • | In May 2005, we acquired all of the outstanding stock of Capcoil Tubing Services, Inc., or Capcoil. |
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| | • | In July 2005, we acquired M-I’s interest in AirComp, and acquired the compressed air drilling assets of W. T. Enterprises, Inc., or W.T. |
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| | • | Effective August 2005, we acquired all of the outstanding stock of Target Energy Inc., or Target. |
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| | • | In September 2005, we acquired the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc. |
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| | • | In January 2006, we acquired all of the outstanding stock of Specialty Rental Tools, Inc., or Specialty. |
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| | • | In April 2006, we acquired all of the outstanding stock of Rogers Oil Tool Services, Inc., or Rogers. |
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| | • | In August 2006, we acquired all of the outstanding stock of DLS Drilling, Logistics & Services Corporation, or DLS. |
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| | • | In October 2006, we acquired all of the outstanding stock of Petro-Rentals, Incorporated, or Petro Rentals. |
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| | • | In December 2006, we acquired all of the outstanding stock of Tanus Argentina S.A., or Tanus. |
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| | • | In December 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc., or OGR. |
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| | • | In June 2007, we acquired Coker Directional, Inc., or Coker and merged it with Strata. |
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| | • | In July 2007, we acquired Diggar Tools, LLC, or Diggar and merged it with Strata. |
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| | • | In October 2007, we acquired Rebel Rentals, Inc. or Rebel. |
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| | • | In November 2007, we acquired substantially all the assets Diamondback Oilfield Services, Inc. or Diamondback. |
As a result of these transactions, our prior results may not be indicative of current or future operations of those sectors.
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Industry Overview
We provide products and services primarily to domestic onshore and offshore oil and natural gas exploration and production companies. The main factor influencing demand for our products and services is the level of drilling activity by oil and natural gas companies, which, in turn, depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. Current industry forecasts suggest an increasing demand for oil and natural gas coupled with flat or declining production curve, which we believe should result in the continuation of historically high crude oil and natural gas commodity prices. The EIA forecasts that U.S. oil and natural gas consumption will increase at an average annual rate of 0.8% and 0.3% through 2030, respectively. The EIA estimates that U.S. oil and natural gas production will increase at an average annual rate of 0.4% and 0.3% respectively.
We anticipate that oil and natural exploration and production companies will continue to increase capital spending for their exploration and drilling programs. According to Lehman Bros. Survey of E&P Spending, U.S. spending in 2008 will increase by 3.5% to $78.5 billion while international spending will increase by 16.16% to $230.24 billion. Baker Hughes rig count data indicates that the average total rig count in the United States increased 92% from an average of 918 in 2000 to 1,763 as of February 29, 2008, while the average natural gas rig count increased 97% from an average of 720 in 2000 to 1,418 as of February 29, 2008. While the number of rigs drilling for natural gas has increased significantly since the beginning of 1996, natural gas production has remained relatively flat over the same period of time. This is largely a function of increasing decline rates for natural gas wells in the United States. The offshore Gulf of Mexico rig count, however, decreased to 58 rigs at February 29, 2008 from 90 rigs in the comparable 2007 period due to the relocation of rigs to the more attractive international markets. We believe that a continued increase in capital expenditure will be required for the natural gas industry to help meet the expected increased demand for natural gas in the United States.
We believe oil and natural gas producers are becoming increasingly focused on their core competencies in identifying reserves and reducing burdensome capital and maintenance costs. In addition, we believe our customers are currently consolidating their supplier bases to streamline their purchasing operations and benefit from economies of scale.
Competitive Strengths
We believe the following competitive strengths will enable us to capitalize on future opportunities:
Strategic position in high growth markets. We focus on markets we believe are growing faster than the overall oilfield services industry and in which we can capitalize on our competitive strengths. Pursuant to this strategy, we have become a significant provider of products and services in directional drilling, underbalanced drilling and rental services. We employ approximately 105 full-time directional drillers, own 30 measurement-while-drilling tools and a fleet of 300 downhole motors. We believe our ability to attract and retain experienced drillers has made us a leader in the segment. We also believe we are one of the largest underbalanced drillers based on amount of air drilling equipment with approximately 260 compressors, boosters and foam units enabling us to provide customized packages. In addition, we have significant operations in what we believe will be among the higher growth oil and natural gas producing regions within the United States and internationally, including the Barnett Shale in North Texas, the Arkoma, Woodford Shale and Anadarko Basins in Oklahoma, the Fayetteville Shale in Arkansas, onshore and offshore Louisiana, the Piceance Basin in Southern Colorado, all five oil and natural gas producing regions in Mexico, and all five major oil and natural gas producing regions of Argentina.
Strong relationships with diversified customer base. We have strong relationships with many of the major and independent oil and natural gas producers and service companies in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, Arkansas, offshore in the Gulf of Mexico, Argentina and Mexico. Our largest customers include Pan American Energy, Repsol-YPF, Apache Corporation, BP, Anadarko Petroleum, Oxy, ConocoPhilips, Chesapeake Energy, Newfield Exploration, Nexen Petroleum, XTO Energy, El Paso Corporation, Materiales y Equipo Petroleo, or Matyep and Devon Energy. Since 2002, we have broadened our customer base as a result of our acquisitions, technical
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expertise and reputation for quality customer service and by providing customers with technologically advanced equipment and highly skilled operating personnel.
Successful execution of growth strategy. Over the past six years, we have grown both organically and through successful acquisitions of competing businesses. Since 2001, we have completed 23 acquisitions. We strive to improve the operating performance of our acquired businesses by increasing their asset utilization and operating efficiency. These acquisitions and organic growth have expanded our geographic presence and customer base and, in turn, have enabled us to cross-sell various products and services.
Diversified and increased cash flow sources. We operate as a diversified oilfield service company through our six business segments. We believe that our product and service offerings and geographical presence through our six business segments provide us with diverse sources of cash flow. Our acquisition of DLS in August 2006 increased our international presence and provides stable long-term contracts. Our acquisition of Petro Rentals in October 2006 significantly enhanced our production-related services and equipment, and our acquisition of substantially all the assets of OGR in December 2006 expanded our Rental Services segment and increased our offshore and international operations.
Experienced management team. Our executive management team has extensive experience in the energy sector, and consequently has developed strong and longstanding relationships with many of the major and independent exploration and production companies. We believe that our management team has demonstrated its ability to grow our businesses organically, make strategic acquisitions and successfully integrate these acquired businesses into our operations.
Business Strategy
The key elements of our growth strategy include:
Mitigate cyclical risk through balanced operations. We strive to mitigate cyclical risk in the oilfield service sector by balancing our operations between onshore versus offshore; drilling versus production; rental tools versus service; domestic versus international; and natural gas versus crude oil. We will continue to shape our organic and acquisition growth efforts to provide further balance across these five categories. Part of our strategy is to further increase our international operations because they increase our exposure to crude oil and provide opportunities for long-term contracts.
Expand geographically to provide greater access and service to key customer segments. We have locations in Texas, New Mexico, Colorado, Wyoming, Arkansas, Oklahoma and Louisiana in order to enhance our proximity to customers and more efficiently serve their needs. Our acquisition of DLS expanded our geographic footprint into Argentina and Bolivia. We plan to continue to establish new locations in the United States and internationally. In 2007, we expanded our presence domestically into non-traditional geographic regions experiencing strong growth and new drilling activity.
Prudently pursue strategic acquisitions. To complement our organic growth, we have pursued strategic acquisitions which we believe are accretive to earnings, complement our products and services, provide new equipment and technology, expand our geographic footprint and market presence, and further diversify our customer base.
Expand products and services provided in existing operating locations. Since the beginning of 2004, we have invested approximately $175.2 million in capital expenditures to grow our business organically by investing in new, technologically advanced equipment and by expanding our product and service offerings. This strategy is consistent with our belief that our customers favor modern equipment emphasizing efficiency and safety and integrated suppliers that can provide a broad product and service offering in many geographic locations.
Increase utilization of assets. We seek to increase revenues and enhance margins by increasing the utilization of our assets with new and existing customers. We expect to accomplish this through leveraging longstanding relationships with our customers and cross-selling our suite of services and equipment, while taking advantage of continued improvements in industry fundamentals. We also expect
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to continue to implement this strategy in our recently expanded rental tools segment, thus improving the utilization and profitability of this newly acquired business with minimal additional investment.
Business Segments
Rental Services. We provide specialized rental equipment, including premium drill pipe, spiral heavy weight drill pipe, tubing work strings, blow out preventors, choke manifolds and various valves and handling tools, for both onshore and offshore well drilling, completion and workover operations. Most wells drilled for oil and natural gas require some form of rental equipment in both the drilling and completion of a well. We have an inventory of specialized equipment, which includes double studded adapters, test plugs, wear bushings, adaptor spools, baskets, spacer spools and other assorted handling tools in various sizes to meet our customers’ demands. We charge customers for rental equipment on a daily basis. Our customers are liable for the cost of inspection, repairs and lost or damaged equipment. We currently provide rental equipment in Texas, Oklahoma, Louisiana, Mississippi, Colorado, offshore in the Gulf of Mexico and internationally in Malaysia, Colombia, Russia, Mexico and Canada.
Our Rental Services segment was established with the acquisition of Safco in September 2004 and Delta in April 2005. We significantly expanded our Rental Services segment in January 2006 with the acquisition of Specialty. Specialty had been in the rental business for over 25 years, providing oil and natural gas operators and oilfield services companies with rental equipment. The acquisition of Specialty gave us a broader scope of rental equipment to offer our existing customer base, and allowed us to better compete in deep water drilling operations in the area of premium drill pipe and handling equipment. The acquisition of Specialty added new customer relationships and enhanced our relationships with key existing customers. We further expanded this segment with the acquisition of substantially all the assets of OGR in December 2006. The assets we acquired included an extensive inventory of premium rental equipment, including drill pipe, spiral heavy weight drill pipe, tubing work strings, landing strings, blow out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. Included in the acquisition were OGR’s facilities in Morgan City, Louisiana and Victoria, Texas. Our Rental Services segment currently operates through our subsidiary, Allis-Chalmers Rental Services LLC.
International Drilling. We provide drilling, completion, workover and related services for oil and natural gas wells. Headquartered in Buenos Aires, Argentina, we operate out of the San Jorge, Cuyan, Neuquen, Austral and Noroeste basins of Argentina. We also offer a wide variety of other oilfield services such as drilling fluids and completion fluids and engineering and logistics to complement our customers’ field organization.
Our International Drilling segment was established with acquisition of DLS in August 2006 for approximately $117.9 million. We operate a fleet of 56 rigs, including 20 drilling rigs and 35 service rigs (workover and pulling units) in Argentina and one drilling rig in Bolivia. Argentine rig operations are generally conducted in remote regions of the country and require substantial infrastructure and support. In 2007, we placed orders for four drilling rigs and 16 service rigs. Four of the service rigs were delivered in the fourth quarter of 2007, while the remaining rigs are expected to be delivered throughout the first three quarters of 2008. As of February 29, 2008, all of our rig fleet was actively marketed, except for one drilling rig that is presently inactive and would require approximately $6.4 million in capital expenditures to become operational.
Directional Drilling. We utilize state-of-the-art equipment to provide well planning and engineering services, directional drilling packages, downhole motor technology, well site directional supervision, exploratory and development re-entry drilling, downhole guidance services and other drilling services to our customers. We also provide logging-while-drilling and measurement-while-drilling (MWD) services. In 2007, we expanded our capability by completing three acquisitions for approximately $37.3 million in total. These were Coker (June 2007), Diggar (July 2007) and Diamondback (November 2007). These acquisitions provided additional directional drillers, downhole motors, and MWD tools and enabled us to expand our presence in the Northern Rockies and the Mid-Continent areas. We now have a team of approximately 105 full-time directional drillers and maintain an inventory of approximately 300 drilling motors. Our straight-hole motors offer an opportunity to capture additional market share. We currently provide our directional drilling services in Texas, Louisiana, Oklahoma, Colorado, Wyoming and West Virginia.
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According to Baker Hughes, as of February 29, 2008, 46% of all wells in the United States are drilled directionallyand/or horizontally. Management believes directional drilling offers several advantages over conventional drilling including:
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| | • | improvement of total cumulative recoverable reserves; |
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| | • | improved reservoir production performance beyond conventional vertical wells; and |
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| | • | reduction of the number of field development wells. |
Tubular Services. We provide specialized equipment and trained operators to perform a variety of pipe handling services, including installing casing and tubing, changing out drill pipe and retrieving production tubing for both onshore and offshore drilling and workover operations, which we refer to as tubular services. All wells drilled for oil and natural gas require casing to be installed for drilling, and if the well is producing, tubing will be required in the completion phase. We currently provide tubular services primarily in Texas, Louisiana and both onshore and offshore in the Gulf of Mexico and Mexico.
We expanded our Tubular Services in September 2005 by acquiring the casing and tubing assets of IHS/Spindletop, a division of Patterson Services, Inc., a subsidiary of RPC, Inc. We paid $15.7 million for RPC, Inc.’s casing and tubing assets, which consisted of casing and tubing installation equipment, including hammers, elevators, trucks, pickups, power units, laydown machines, casing tools and torque turn equipment. The acquisition of RPC, Inc.’s casing and tubing assets increased our capability in tubular services and expanded our geographic capability. We opened new field offices in Corpus Christi, Texas, Kilgore, Texas, Lafayette, Louisiana and Houma, Louisiana. The acquisition allowed us to enter the East Texas and Louisiana market for casing and tubing services as well as offshore in the Gulf of Mexico. Additionally, the acquisition greatly expanded our premium tubing services.
In April 2006 we acquired Rogers for $13.7 million. Historically, Rogers rented, sold and serviced power drill pipe tongs and accessories and rental tongs for snubbing and well control applications and provided specialized tong operators for rental jobs. In December 2006, we merged Rogers into Tubular. We expanded this segment again in October 2007 with the acquisition of Rebel Rentals, Inc. for $7.3 million. Rebel owns an inventory of equipment used primarily for tubing installation services in the South Louisiana and Gulf Coast regions.
We provide equipment used in casing and tubing services in Mexico to Matyep. Matyep provides equipment and services for offshore and onshore drilling operations to Petroleos Mexicanos, known as Pemex, in Villahermosa, Reynosa, Veracruz and offshore in the Bay of Campeche, Mexico. Matyep provides all personnel, repairs, maintenance, insurance and supervision for provision of the casing and tubing crew and torque turn service. Services to offshore drilling operations in Mexico are traditionally seasonal, with less activity during the first quarter of each calendar year due to weather conditions.
For the years ended December 31, 2007, 2006 and 2005, our Mexico operations accounted for approximately $7.9 million, $6.5 million and $6.4 million, respectively, of our revenues. We provide extended payment terms to Matyep and maintain a high accounts receivable balance due to these terms. The accounts receivable balance was approximately $2.8 million at December 31, 2007 and approximately $3.2 million at December 31, 2006. Tubular has been providing services to Pemex in association with Matyep since 1997.
Underbalanced Drilling. We provide compressed air equipment, chemicals and other specialized products for underbalanced drilling and production applications. With a combined fleet of approximately 260 compressors, boosters and foam units, we believe we are one of the world’s largest providers of underbalanced drilling services in the United States. We also provide premium air hammers and bits to oil and natural gas companies for use in underbalanced drilling. Our broad and diversified product line enables us to compete in the underbalanced market with equipment and services packages engineered and customized to specifically meet customer requirements.
Underbalanced drilling shortens the time required to drill a well and enhances production by minimizing formation damage. There is a trend in the industry to drill, complete and workover wells with underbalanced operations and we expect the market to continue to grow.
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In July 2005, we purchased the compressed air drilling assets of W. T., operating in West Texas and acquired the remaining 45% equity interest in AirComp from M-I. The acquired assets include air compressors, boosters, mist pumps, rolling stock and other equipment. These assets were integrated into AirComp’s assets and complement and add to AirComp’s product and service offerings. We currently provide compressed air drilling services in Alabama, Arkansas, Colorado, Mississippi, New Mexico, Oklahoma, Texas, Utah, West Virginia and Wyoming.
Production Services. We provide a variety of quality production-related rental tools and equipment and services, including wire line services, land and offshore pumping services and coil tubing. In addition, we perform workover services with coiled tubing units. Our production services segment was established with the acquisition of Downhole, in December 2004, and the acquisition of Capcoil, in May 2005. In February 2006, we merged Downhole into Capcoil and named the new entity Allis-Chalmers Production Services, Inc., or Production Services. In October 2006, we expanded our production services segment with the acquisition of Petro Rentals. Petro Rentals serves both the onshore and offshore markets, providing a variety of quality rental tools and equipment and services, with an emphasis on production-related equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. On June 29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a small portion of our Production Services segment.
We have an inventory of specialized equipment consisting of coil tubing units in various sizes ranging from 1/4” to 2” along with nitrogen pumping and transportation equipment. We purchased two additional coil tubing units in 2006, one additional coil tubing unit was received in the first quarter of 2007 and an additional coil tubing unit was delivered at the end of the second quarter of 2007. We also maintain a full range of stainless and carbon steel coiled tubing and related supplies used in the installation of the tubing. We currently provide production services in Texas, Louisiana, Arkansas and Oklahoma. We have ordered six additional coil tubing units ranging in size from 1 1/4” to 2”. The units are expected to be delivered in the third and fourth quarters of 2008.
Cyclical Nature Of Oilfield Services Industry
The oilfield services industry is highly cyclical. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. The peaks and valleys of demand are further apart than those of many other cyclical industries. This is primarily a result of the industry being driven by commodity demand and corresponding price increases. As demand increases, producers raise their prices. The price escalation enables producers to increase their capital expenditures. The increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. The increased capital expenditures also ultimately result in greater production which historically has resulted in increased supplies and reduced prices.
Demand for our services has been strong throughout 2004, 2005 and 2006. The market in 2007 was generally positive with some areas of weakness and some areas of growth. Certain customers slowed their drilling activity in 2007 in response to increased availability of drilling rigs and volatility of natural gas prices, while others remained very active. Activity in the U.S. Gulf of Mexico decreased in the second half of 2007 due to the hurricane season and relocation of rigs to more attractive international markets. Management believes demand will generally remain stable in 2008 due to high oil and natural gas prices and the capital expenditure plans of the exploration and production companies, however, activity in the U.S. Gulf of Mexico may remain low for the next year. Because of these market fundamentals for oil and natural gas, management believes the long-term trend of activity in our markets is favorable. However, these factors could be more than offset by other developments affecting the worldwide supply and demand for oil and natural gas products and developments in the U.S. economy.
Customers
In 2007 and 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented approximately 20.7% and 11.7% of our consolidated revenues, respectively. Pan America Energy is a joint venture that is owned 60% by British Petroleum and 40% by Bridas Corporation. Alejandro P. Bulgheroni and Carlos A. Bulgheroni, two of our directors, may be deemed to indirectly
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beneficially own all of the outstanding capital stock of Bridas Corporation and are members of the Management Committee of Pan American Energy. In 2005, none of our customers accounted for more than 10% of our revenues. Our primary customers are the major and independent oil and natural gas companies operating in the United States, Argentina and Mexico. The loss without replacement of our larger existing customers could have a material adverse effect on our results of operations.
Suppliers
The equipment utilized in our business is generally available new from manufacturers or at auction. Currently, due to the high level of activity in the oilfield services industry, there is a high demand for new and used equipment. Consequently, there is a limited amount of many types of equipment available at auction and significant backlogs on new equipment. However, the cost of acquiring new equipment to expand our business could increase as a result of the high demand for equipment in the industry.
Competition
We experience significant competition in all areas of our business. In general, the markets in which we compete are highly fragmented, and a large number of companies offer services that overlap and are competitive with our services and products. We believe that the principal competitive factors are technical and mechanical capabilities, management experience, past performance and price. While we have considerable experience, there are many other companies that have comparable skills. Many of our competitors are larger and have greater financial resources than we do.
The rental tool business is highly fragmented with hundreds of companies offering various rental tool services. Our largest competitors include Weatherford, Quail Rental Tools, Knight Rental Tools and W-H Energy Services (Thomas Tools).
Our five largest competitors in the contract drilling and workover service business, which operate primarily in Argentina, are Pride International, Servicios WellTech, Ensign Energy Services, Nabors and Helmerich & Payne.
We believe that there are five major directional drilling companies, Schlumberger, Halliburton, Baker Hughes, W-H Energy Services (Pathfinder) and Weatherford, that market both worldwide and in the United States as well as numerous small regional players.
Significant competitors in the tubular markets we serve include Frank’s Casing Crew and Rental Tools, Weatherford, BJ Services, Tesco and Premier. These markets remain highly competitive and fragmented with numerous casing and tubing crew companies working in the United States. Our primary competitors in Mexico are South American Enterprises and Weatherford, both of which provide similar products and services.
Our largest competitor for underbalanced drilling services is Weatherford. Weatherford focuses on large projects, but also competes in the more common compressed air, mist, foam and aerated mud drilling applications. Other competition comes from smaller regional companies.
In the production services market there are numerous competitors, most of which have larger coiled tubing services operations than us.
Backlog
We do not view backlog of orders as a significant measure for our business because our jobs are short-term in nature, typically one to 30 days, without significant on-going commitments.
Employees
Our strategy includes acquiring companies with strong management and entering into long-term employment contracts with key employees in order to preserve customer relationships and assure continuity following acquisition. In general, we believe we have good relations with our employees. None of our employees, other than our International Drilling employees, are represented by a union. We actively train employees across various functions, which we believe is crucial to motivate our workforce and maximize efficiency. Employees showing a higher level of skill are trained on more technologically complex equipment and given greater responsibility. All employees are responsible for on-going quality assurance. At February 29, 2008, we had
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approximately 3,050 employees. Almost all of our International Drilling operations are subject to collective bargaining agreements. We believe that we maintain a satisfactory relationship with the unions to which our International Drilling employees belong.
Insurance
We carry a variety of insurance coverages for our operations, and we are partially self-insured for certain claims in amounts that we believe to be customary and reasonable. However, there is a risk that our insurance may not be sufficient to cover any particular loss or that insurance may not cover all losses. We are responsible for the first $250,000 of claims under our workers compensation policy and the first $100,000 of claims under our general liability and medical insurance policies. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions.
Seasonality
Oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. For example, in the summer of 2005, the Gulf of Mexico suffered an unusually high number of hurricanes with unusual intensity. Additionally, in August to October of 2007 we witnessed a decline in offshore drilling rig operations in the Gulf of Mexico in anticipation of the hurricane season. Many of those rigs have not returned to the U.S. Gulf and have been relocated to the international markets. In addition, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the United States are also adversely affected by seasonal weather conditions. These weather conditions limit our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Federal Regulations and Environmental Matters
Our operations are subject to federal, state and local laws and regulations relating to the energy industry in general and the environment in particular. Environmental laws have in recent years become more stringent and have generally sought to impose greater liability on a larger number of potentially responsible parties. Because we provide services to companies producing oil and natural gas, which are toxic substances, we may become subject to claims relating to the release of such substances into the environment. While we are not currently aware of any situation involving an environmental claim that would likely have a material adverse effect on us, it is possible that an environmental claim could arise that could cause our business to suffer. We do not anticipate any material expenditures to comply with environmental regulations affecting our operations.
In addition to claims based on our current operations, we are from time to time named in environmental claims relating to our activities prior to our reorganization in 1988 (See “Item 3. Legal Proceedings”).
Intellectual Property Rights
Except for our relationships with our customers and suppliers described above, we do not own any patents, trademarks, licenses, franchises or concessions which we believe are material to the success of our business.
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Our business, financial condition, results of operations and the trading price of our securities can be materially and adversely affected by many events and conditions, including the following:
Risks Associated With Our Company
We may fail to acquire additional businesses, which will restrict our growth and may have a material adverse effect on our stock price or on our ability to meet our obligations under (and the price of) our securities.
Our business strategy is to acquire companies operating in the oilfield services industry. However, there can be no assurance that we will be successful in acquiring any additional companies. Successful acquisition of new companies will depend on various factors, including but not limited to:
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| | • | our ability to obtain financing; |
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| | • | the competitive environment for acquisitions; and |
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| | • | the integration and synergy issues described in the next risk factor. |
There can be no assurance that we will be able to acquire and successfully operate any particular business or that we will be able to expand into areas that we have targeted. If we fail to acquire additional businesses or are unable to finance such acquisitions, our financial condition, our results of operations, the price of our common stock and our ability to meet our obligations under long-term notes may be materially adversely affected.
We have made numerous acquisitions during the past five years. As a result of these transactions, our past performance is not indicative of future performance, and investors should not base their expectations as to our future performance on our historical results.
Difficulties in integrating acquired businesses may result in reduced revenues and income.
We may not be able to successfully integrate the businesses of our operating subsidiaries or any business we may acquire in the future. The integration of the businesses are complex and time consuming, place a significant strain on management and our information systems, and this strain could disrupt our businesses. Furthermore, if our combined businesses continue to grow rapidly, we may be required to replace our current information and accounting systems with systems designed for companies that are larger than ours. We may be adversely impacted by unknown liabilities of acquired businesses. We may encounter substantial difficulties, costs and delays involved in integrating common accounting, information and communication systems, operating procedures, internal controls and human resources practices, including incompatibility of business cultures and the loss of key employees and customers. These difficulties may reduce our ability to gain customers or retain existing customers, and may increase operating expenses, resulting in reduced revenues and income and a failure to realize the anticipated benefits of acquisitions.
In particular, the DLS and OGR acquisitions are our largest acquisitions to date and, consequently, the inherent integration risks may have a greater effect on us than the risks posed by our previous acquisitions. Furthermore, we will depend on these entities’ continued performance as a source of cash flow to service our debt obligations.
Our acquisition of DLS has substantially changed the nature of our operations and business.
Our acquisition of DLS, which established our International Drilling segment, has substantially changed the nature and geographic location of our operations and business as a result of the character and location of our International Drilling operations, which have substantially different operating characteristics and are in different geographic locations from our other businesses. Prior to the establishment of our International Drilling segment, we had operated as an oilfield services company domestically in Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Utah, Wyoming, offshore in the Gulf of Mexico, and internationally in Mexico. We had no significant operations in South America prior to acquiring DLS. Accordingly, this acquisition has subjected and will continue to subject us to risks inherent in operating in a foreign country where we did not have significant prior experience. Our International Drilling segment’s business consists of
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employing drilling and workover rigs for drilling, completion and repair services for oil and gas wells. We do not own any drilling rigs or workover rigs other than through DLS, and have not historically provided such services prior to our acquisition of DLS.
Failure to maintain effective disclosure controls and procedures and/or internal controls over financial reporting could have a material adverse effect on our operations.
As part of our growth strategy, we have recently completed several acquisitions of privately-held businesses, including closely-held entities, and in the future, we may make additional strategic acquisitions of privately-held businesses. Prior to becoming part of our consolidated company, these acquired businesses have not been required to implement or maintain the disclosure controls and procedures or internal controls over financial reporting that federal law requires of publicly-held companies such as ours. Similarly, it is likely that our future acquired businesses will not have been required to maintain such disclosure controls and procedures or internal controls prior to their acquisition. Likewise, upon the completion of any future acquisition, we will be required to integrate the acquired business into our consolidated company’s system of disclosure controls and procedures and internal controls over financial reporting, but we cannot assure you as to how long the integration process may take for any business that we may acquire. Furthermore, during the integration process, we may not be able to fully implement our consolidated disclosure controls and internal controls over financial reporting.
Likewise, during the course of our integration of any acquired business, we may identify needed improvements to our or such acquired business’ internal controls and may be required to design enhanced processes and controls in order to make such improvements. This could result in significant delays and costs to us and could require us to divert substantial resources, including management time, from other activities.
If we fail to achieve and maintain the adequacy of our disclosure controls and proceduresand/or our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to conclude that we have effective disclosure controls and proceduresand/or effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. If:
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| | • | we are not successful in improving our financial reporting process, our disclosure controls and proceduresand/or our internal controls over financial reporting; |
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| | • | we identify deficienciesand/or one or more material weaknesses in our internal controls over financial reporting; or |
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| | • | we are not successful in integrating acquired businesses into our consolidated company’s system of disclosure controls and procedures and internal controls over financial reporting, |
then our independent registered public accounting firm may be unable to attest that our internal control over financial reporting is fairly stated, or on the effectiveness of, our internal controls.
If it is determined that our disclosure controls and proceduresand/or our internal controls over financial reporting are not effectiveand/or we fail to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act on a timely basis, we may not be able to provide reliable financial and other reports or prevent fraud, which, in turn, could harm our business and operating results, cause investors to lose confidence in the accuracy and completeness of our financial reports, have a material adverse effect on the trading price of our common stockand/or adversely affect our ability to timely file our periodic reports with the SEC. Any failure to timely file our periodic reports with the SEC may give rise to a default under the indentures governing our outstanding 9.0% senior notes due 2014, and our outstanding 8.5% senior notes due 2017 (which we refer to collectively as our outstanding senior notes) and any other debt securities we may offer and, ultimately, an acceleration of amounts due thereunder. In addition, a default under the indentures generally will also give rise to a default under our credit agreement and could cause the acceleration of amounts due under the credit agreement. If an acceleration of our outstanding senior notes or our other debt were to occur, we cannot assure you that we would have sufficient funds to repay such obligations.
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Historically, we have been dependent on a few customers operating in a single industry; the loss of one or more customers could adversely affect our financial condition and results of operations.
Our customers are engaged in the oil and natural gas drilling business in the United States, Mexico and elsewhere. Historically, we have been dependent upon a few customers for a significant portion of our revenues. In 2007 and 2006, one of our customers, Pan American Energy represented 20.7% and 11.7% of our consolidated revenues, respectively. In 2005, no single customer generated over 10% of our revenues. Our International Drilling segment currently relies on one customer for a majority of its revenue. In 2007 and 2006, Pan American Energy represented 51.0% and 45.6% of our international revenues, respectively. This concentration of customers may increase our overall exposure to credit risk, and customers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations will be materially adversely affected if one or more of our significant customers fails to pay us or ceases to contract with us for our services on terms that are favorable to us or at all.
Our international operations may expose us to political and other uncertainties, including risks of:
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| | • | terrorist acts, war and civil disturbances; |
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| | • | changes in laws or policies regarding the award of contracts; and |
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| | • | the inability to collect or repatriate currency, income, capital or assets. |
Part of our strategy is to prudently and opportunistically acquire businesses and assets that complement our existing products and services, and to expand our geographic footprint. If we make acquisitions in other countries, we may increase our exposure to the risks discussed above.
Environmental liabilities could result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy laws in 1988, a number of parties, including the Environmental Protection Agency, have asserted that we are responsible for the cleanup of hazardous waste sites with respect to our pre-bankruptcy activities. We believe that such claims are barred by applicable bankruptcy law, and we have not experienced any material expense in relation to any such claims. However, if we do not prevail with respect to these claims in the future, or if additional environmental claims are asserted against us relating to our current or future activities in the oil and natural gas industry, we could become subject to material environmental liabilities that could have a material adverse effect on our financial condition and results of operations.
Products liability claims relating to discontinued operations could result in substantial losses.
Since our reorganization under the U.S. federal bankruptcy laws in 1988, we have been regularly named in products liability lawsuits primarily resulting from the manufacture of products containing asbestos. In connection with our bankruptcy, a special products liability trust was established and funded to address products liability claims. We believe that claims against us are barred by applicable bankruptcy law, and that the products liability trust will continue to be responsible for products liability claims. Since 1988, no court has ruled that we are responsible for products liability claims. However, if we are held responsible for product liability claims, we could suffer substantial losses that could have a material adverse effect on our financial condition and results of operations. We have not manufactured products containing asbestos since our reorganization in 1988.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.
Our products and services are used for the exploration and production of oil and natural gas. These operations are subject to inherent hazards that can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment and marine life, and suspension of operations. Litigation arising from an accident at a location where our products or services are used or provided may cause us to be named as a defendant in lawsuits asserting potentially large claims. We maintain customary insurance to protect our business against these potential losses. Our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. However, we could become subject to material uninsured liabilities that could have a material adverse effect on our financial condition and results of operations.
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The loss of key executives would adversely affect our ability to effectively finance and manage our business, acquire new businesses, and obtain and retain customers.
We are dependent upon the efforts and skills of our executives to finance and manage our business, identify and consummate additional acquisitions and obtain and retain customers. These executives include our Chief Executive Officer and Chairman Munawar H. Hidayatallah.
In addition, our development and expansion will require additional experienced management and operations personnel. No assurance can be given that we will be able to identify and retain these employees. The loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.
Risks Associated With Our Industry
Cyclical declines in oil and natural gas prices may result in reduced use of our services, affecting our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The oil and natural gas exploration and drilling business is highly cyclical. Generally, as oil and natural gas prices decrease, exploration and drilling activity declines as marginally profitable projects become uneconomic and are either delayed or eliminated. Declines in the number of operating drilling rigs result in reduced use of and prices for our services. Accordingly, when oil and natural gas prices are relatively low, our revenues and income will suffer. Oil and natural gas prices depend on many factors beyond our control, including the following:
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| | • | economic conditions in the United States and elsewhere; |
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| | • | changes in global supply and demand for oil and natural gas; |
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| | • | the level of production of the Organization of Petroleum Exporting Countries, commonly called OPEC; |
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| | • | the level of production of non-OPEC countries; |
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| | • | the price and quantity of imports of foreign oil and natural gas; |
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| | • | political conditions, including embargoes, in or affecting other oil and natural gas producing activities; |
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| | • | the level of global oil and natural gas inventories; and |
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| | • | advances in exploration, development and production technologies. |
Depending on the market prices of oil and natural gas, companies exploring for oil and natural gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. With the exception of certain contracts in Argentina and Mexico, our contracts are generally short-term, and oil and natural gas companies tend to respond quickly to upward or downward changes in prices. Any reduction in the demand for drilling services may materially erode both pricing and utilization rates for our services and adversely affect our financial results. As a result, we may suffer losses, be unable to make necessary capital expenditures and be unable to meet our financial obligations.
Our industry is highly competitive, with intense price competition.
The markets in which we operate are highly competitive. Contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment has intensified as recent mergers among oil and natural gas companies have reduced the number of available customers. Many other oilfield services companies are larger than we are and have resources that are significantly greater than our resources. These competitors are better able to withstand industry downturns, compete on the basis of price and acquire new equipment and technologies, all of which could affect our revenues and profitability. These competitors compete with us both for customers and for acquisitions of other businesses. This competition may cause our business to suffer. We believe that competition for contracts will continue to be intense in the foreseeable future.
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We may experience increased labor costs or the unavailability of skilled workers and the failure to retain key personnel could hurt our operations.
Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. There can be no assurance that labor costs will not increase. Any increase in our operating costs could cause our business to suffer.
Severe weather could have a material adverse impact on our business.
Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
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| | • | curtailment of services; |
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| | • | weather-related damage to facilities and equipment resulting in suspension of operations; |
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| | • | inability to deliver materials to job sites in accordance with contract schedules; and |
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| | • | loss of productivity. |
For example, oil and natural gas operations of our customers located offshore and onshore in the Gulf of Mexico and in Mexico have been adversely affected by floods, hurricanes and tropical storms, resulting in reduced demand for our services. Further, our customers’ operations in the Mid-Continent and Rocky Mountain regions of the United States are also adversely affected by seasonal weather conditions. This limits our access to these job sites and our ability to service wells in these areas. These constraints decrease drilling activity and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Our business may be affected by terrorist activity and by security measures taken in response to terrorism.
We may experience loss of business or delays or defaults in payments from customers that have been affected by actual or potential terrorist activities. Some oil and natural gas drilling companies have implemented security measures in response to potential terrorist activities, including access restrictions, that could adversely affect our ability to market our services to new and existing customers and could increase our costs. Terrorist activities and potential terrorist activities and any resulting economic downturn could adversely impact our results of operations, impair our ability to raise capital or otherwise adversely affect our ability to grow our business.
We are subject to government regulations.
We are subject to various federal, state, local and foreign laws and regulations relating to the energy industry in general and the environment in particular. Environmental laws have in recent years become more stringent and have generally sought to impose greater liability on a larger number of potentially responsible parties. Although we are not aware of any proposed material changes in any federal, state, local or foreign statutes, rules or regulations, any changes could materially affect our financial condition and results of operations.
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Risks Associated With Our International Drilling Business and Industry
A material or extended decline in expenditures by oil and gas companies due to a decline or volatility in oil and gas prices, a decrease in demand for oil and gas or other factors may reduce demand for our International Drilling services and substantially reduce our revenues, profitability, cash flows and/or liquidity.
The profitability of our International Drilling operations depends upon conditions in the oil and natural gas industry and, specifically, the level of exploration and production expenditures of oil and gas company customers. The oil and natural gas industry is cyclical and subject to governmental price controls. The demand for contract drilling and related services is directly influenced by many factors beyond our control, including:
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| | • | oil and natural gas prices and expectations about future prices; |
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| | • | the demand for oil and natural gas, both in Latin America and globally; |
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| | • | the cost of producing and delivering oil and natural gas; |
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| | • | advances in exploration, development and production technology; |
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| | • | government regulations, including governmental imposed commodity price controls, export controls and renationalization of a country’s oil and natural gas industry; |
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| | • | local and international political and economic conditions; |
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| | • | the ability of OPEC to set and maintain production levels and prices; |
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| | • | the level of production by non-OPEC countries; and |
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| | • | the policies of various governments regarding exploration and development of their oil and natural gas reserves. |
Depending on the factors outlined above, companies exploring for oil and natural gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. Such a reduction in demand may erode daily rates and utilization of our rigs. Any significant decrease in daily rates or utilization of our rigs could materially reduce our revenues, profitability, cash flowsand/or liquidity.
A majority of our International Drilling segment’s revenues are derived from one customer. The termination of the contract with this customer could have a significant negative effect on the revenue and results of operations from our International Drilling segment.
A majority of our International Drilling revenues are currently received pursuant to a strategic agreement with Pan American Energy. Additionally, in 2007 we placed orders for 16 new service rigs and 4 drilling rigs which will be added to this agreement. Pan American Energy is a joint venture that is owned 60% by British Petroleum and 40% by Bridas Corporation, an affiliate of the former DLS stockholders from which we acquired DLS, and which we refer to collectively as the DLS sellers. This agreement currently has an expiration date of June 30, 2011. However, Pan American Energy may terminate the agreement (i) without cause at any time with 60 days’ notice, or (ii) in the event of a breach of the agreement by us if such breach is not cured within 20 days of notice of the breach.
Because a majority of our International Drilling revenues are currently generated under this agreement, our International Drilling revenues and earnings will be materially adversely affected if this agreement is terminated unless we are able to enter into a satisfactory substitute arrangement. We cannot assure you that in the event of such a termination we would be able to enter into a substitute arrangement on terms similar to those contained in the current agreement with Pan American Energy.
Our International Drilling’s operations and financial condition could be affected by union activity and general labor unrest. Additionally, our International Drilling’s labor expenses could increase as a result of governmental regulation of payments to employees.
In Argentina, labor organizations have substantial support and have considerable political influence. The demands of labor organizations have increased in recent years as a result of the general labor unrest and dissatisfaction resulting from the disparity between the cost of living and salaries in Argentina as a result of the devaluation of the Argentine peso. There can be no assurance that our International Drilling segment will
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not face labor disruptions in the future or that any such disruptions will not have a material adverse effect on our financial condition or results of operations.
The Argentine government has in the past and may in the future promulgate laws, regulations and decrees requiring companies in the private sector to maintain minimum wage levels and provide specified benefits to employees, including significant mandatory severance payments. In the aftermath of the Argentine economic crisis of 2001 and 2002, both the government and private sector companies have experienced significant pressure from employees and labor organizations relating to wage levels and employee benefits. In early 2005, the Argentine government promised not to order salary increases by decree. However, there has been no abatement of pressure to mandate salary increases, and it is possible the government will adopt measures that will increase salaries or require our International Drilling segment to provide additional benefits, which would increase our costs and potentially reduce our International Drilling segment’s profitability and cash flow.
Rig upgrade, refurbishment and construction projects are subject to risks, including delays and cost overruns, which could have an adverse effect on our International Drilling segment’s results of operations and cash flows.
Our International Drilling segment often has to make upgrade and refurbishment expenditures for its rig fleet to comply with our quality management and preventive maintenance system or contractual requirements or when repairs are required in response to an inspection by a governmental authority. We may also make significant expenditures when rigs are moved from one location to another. Additionally, we may make substantial expenditures for the construction of new rigs. In 2007, we placed orders for 16 new service rigs and 4 drilling rigs to be placed in service during the first three quarters of 2008. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:
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| | • | shortages of material or skilled labor; |
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| | • | unforeseen engineering problems; |
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| | • | unanticipated change orders; |
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| | • | work stoppages; |
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| | • | adverse weather conditions; |
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| | • | long lead times for manufactured rig components; |
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| | • | unanticipated cost increases; and |
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| | • | inability to obtain the required permits or approvals. |
Significant cost overruns or delays could adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade, refurbishment or construction projects could exceed our planned capital expenditures, impairing our ability to service its debt obligations.
An oversupply of comparable rigs in the geographic markets in which we compete could depress the utilization rates and dayrates for our rigs and materially reduce our revenues and profitability.
Utilization rates, which are the number of days a rig actually works divided by the number of days the rig is available for work, and dayrates, which are the contract prices customers pay for rigs per day, are also affected by the total supply of comparable rigs available for service in the geographic markets in which we compete. Improvements in demand in a geographic market may cause our competitors to respond by moving competing rigs into the market, thus intensifying price competition. Significant new rig construction could also intensify price competition. In the past, there have been prolonged periods of rig oversupply with correspondingly depressed utilization rates and dayrates largely due to earlier, speculative construction of new rigs. Improvements in dayrates and expectations of longer-term, sustained improvements in utilization rates and dayrates for drilling rigs may lead to construction of new rigs. These increases in the supply of rigs could depress the utilization rates and dayrates for our rigs and materially reduce our International Drilling segment’s revenues and profitability.
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Worldwide political and economic developments may hurt our operations materially.
Currently, we derive substantially all of our International Drilling segment revenues from operations in Argentina. From time to time, we also generate revenues from operations in Bolivia. Our International Drilling operations are subject to the following risks, among others:
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| | • | expropriation of assets; |
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| | • | nationalization of components of the energy industry in the geographic areas where we operate; |
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| | • | foreign currency fluctuations and devaluation; |
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| | • | new economic and tax policies; |
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| | • | restrictions on currency, income, capital or asset repatriation; |
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| | • | political instability, war and civil disturbances; |
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| | • | uncertainty or instability resulting from armed hostilities or other crises in the Middle East or the geographic areas in which we operate; and |
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| | • | acts of terrorism. |
We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment of a percentage of the contract indexed to the U.S. dollar exchange rate. To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our local expense requirements in those currencies. Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.
Over the past several years, Argentina and Bolivia have experienced political and economic instability that resulted in significant changes in their general economic policies and regulations.
Our operations are also subject to other risks, including foreign monetary and tax policies, expropriation, nationalization and nullification or modification of contracts. Additionally, our ability to compete may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, we may face governmentally imposed restrictions from time to time on its ability to transfer funds.
Devaluation of the Argentine peso will adversely affect our International Drilling segment’s results of operations.
The Argentine peso has been subject to significant devaluation in the past and may be subject to significant fluctuations in the future. Given the economic and political uncertainties in Argentina, it is impossible to predict whether, and to what extent, the value of the Argentine peso may depreciate or appreciate against the U.S. dollar. We cannot predict how these uncertainties will affect our financial results, but there is a risk that our financial performance could be adversely affected. Moreover, we cannot predict whether the Argentine government will further modify its monetary policy and, if so, what effect any of these changes could have on the value of the Argentine peso. Such changes could have an adverse effect on our financial condition and results of operations.
Argentina continues to face considerable political and economic uncertainty.
Although general economic conditions have shown improvement and political protests and social disturbances have diminished considerably since the economic crisis of 2001 and 2002, the rapid and radical nature of the changes in the Argentine social, political, economic and legal environment over the past several years and the absence of a clear political consensus in favor of any particular set of economic policies have given rise to significant uncertainties about the country’s economic and political future. It is currently unclear whether the economic and political instability experienced over the past several years will continue and it is possible that, despite recent economic growth, Argentina may return to a deeper recession, higher inflation and
21
unemployment and greater social unrest. If instability persists, there could be a material adverse effect on our results of operations and financial condition.
In the event of further social or political crisis, companies in Argentina may also face the risk of further civil and social unrest, strikes, expropriation, nationalization, forced renegotiation or modification of existing contracts and changes in taxation policies, including royalty and tax increases and retroactive tax claims.
In addition, investments in Argentine companies may be further affected by changes in laws and policies of the United States affecting foreign trade, taxation and investment.
An increase in inflation could have a material adverse effect on our results of operations.
The devaluation of the Argentine peso created pressures on the domestic price system that generated high rates of inflation in 2002 before substantially stabilizing in 2003 and remaining stable in 2004. In 2005, however, inflation rates began to increase. In addition, in response to the economic crisis in 2002, the federal government granted the Central Bank greater control over monetary policy than was available to it under the previous monetary regime, known as the “Convertibility” regime, including the ability to print currency, to make advances to the federal government to cover its anticipated budget deficit and to provide financial assistance to financial institutions with liquidity problems. We cannot assure you that inflation rates will remain stable in the future. Significant inflation could have a material adverse effect on our results of operations and financial condition.
Some of our customers may seek to cancel or renegotiate some of our International Drilling contracts during periods of depressed market conditions or if we experience operational difficulties.
Substantially all of our International Drilling segment’s contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate existing contracts if we experience operational problems. The likelihood that a customer may seek to terminate a contract for operational difficulties is increased during periods of market weakness. The cancellation of a number of our drilling contracts could materially reduce our revenues and profitability.
We are subject to numerous governmental laws and regulations, including those that may impose significant liability on us for environmental and natural resource damages.
Many aspects of our International Drilling segment’s operations are subject to laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. The countries where our International Drilling segment operates have environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment in connection with operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit our operations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and gas could materially limit future contract drilling opportunities or materially increase our costs or both.
22
We are subject to hazards customary for drilling operations, which could adversely affect our financial performance if we are not adequately indemnified or insured.
Substantially all of our International Drilling segment’s operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and gas well fires and explosions, natural disasters, pollution and mechanical failure. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we generally obtain indemnification from customers by contract for some of these risks. However, there may be limitations on the enforceability of indemnification provisions that allow a contractor to be indemnified for damages resulting from the contractor’s fault. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. However, we have a significant amount of self-insured retention or deductible for certain losses relating to workers’ compensation, employers’ liability, general liability and property damage. There is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will continue to be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive.
Risks Associated With an Investment in Our Common Stock
In connection with our acquisitions of DLS and substantially all the assets of OGR, the DLS sellers have the right to designate two nominees for election to our board of directors and OGR has the right to designate one nominee for election to our board of directors. The interests of the DLS sellers and OGR may be different from yours.
The DLS sellers collectively hold 3,311,300 shares of our common stock, representing approximately 9.4% of our issued and outstanding shares as of February 29, 2008. Under the investors rights agreement that we entered into in connection with the DLS acquisition, the DLS sellers have the right to designate two nominees for election to our board of directors. The stockholders of OGR hold 3.2 million shares of our common stock, representing approximately 9.1% of our issued and outstanding shares as of February 29, 2008. Under the investor rights agreement that we entered into in connection with the OGR acquisition, the stockholders of OGR have the right to designate one nominee for election to our board of directors. As a result, the DLS sellers and OGR stockholders have a greater ability to determine the composition of our board of directors and to control our future operations and strategy as compared to the voting power and control that could be exercised by a stockholder owning the same number of shares and not benefiting from board designation rights.
Conflicts of interest between the DLS sellers and OGR stockholders, on the one hand, and other holders of our securities, on the other hand, may arise with respect to sales of shares of capital stock owned by the DLS sellers or OGR or other matters. In addition, the interests of the DLS sellers or OGR stockholders regarding any proposed merger or sale may differ from the interests of other holders of our securities.
The board designation rights described above could also have the effect of delaying or preventing a change in our control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material and adverse effect on the market price of our securitiesand/or our ability to meet our obligations thereunder.
Our stock price may decrease in response to various factors, which could adversely affect our business and cause our stockholders to suffer significant losses. These factors include:
| | |
| | • | decreases in prices for oil and natural gas resulting in decreased demand for our services; |
| |
| | • | variations in our operating results and failure to meet expectations of investors and analysts; |
| |
| | • | increases in interest rates; |
23
| | |
| | • | the loss of customers; |
| |
| | • | failure of customers to pay for our services; |
| |
| | • | competition; |
| |
| | • | illiquidity of the market for our common stock; |
| |
| | • | developments specifically affecting the Argentine economy; |
| |
| | • | sales of common stock by existing stockholders; and |
| |
| | • | other developments affecting us or the financial markets. |
A reduced stock price will result in a loss to investors and will adversely affect our ability to issue stock to fund our activities.
Existing stockholders’ interest in us may be diluted by additional issuances of equity securities.
We expect to issue additional equity securities to fund the acquisition of additional businesses and pursuant to employee benefit plans. We may also issue additional equity securities for other purposes. These securities may have the same rights as our common stock or, alternatively, may have dividend, liquidation, or other preferences to our common stock. The issuance of additional equity securities will dilute the holdings of existing stockholders and may reduce the share price of our common stock.
We do not expect to pay dividends on our common stock, and investors will be able to receive cash in respect of the shares of common stock only upon the sale of the shares.
We have not paid any cash dividends on our common stock within the last ten years, and we have no intention in the foreseeable future to pay any cash dividends on our common stock. Furthermore, our credit agreement and the indentures governing our outstanding senior notes restrict our ability to pay dividends on our common stock. Therefore, an investor in our common stock will obtain an economic benefit from the common stock only after an increase in its trading price and only by selling the common stock.
Substantial sales of our common stock could adversely affect our stock price.
Sales of a substantial number of shares of common stock, or the perception that such sales could occur, could adversely affect the market price of our common stock by introducing a large number of sellers to the market. Such sales could cause the market price of our common stock to decline.
We have 35,130,914 shares outstanding as of February 29, 2008. At December 31, 2007, we had reserved an additional 2,323,728 shares of common stock for issuance under our equity compensation plans, of which 982,763 shares were issuable upon the exercise of outstanding options with a weighted average exercise price of $10.77 per share and 710,000 shares were issuable under restricted stock award grants subject to performance based vesting. In addition, we have reserved 4,000 shares of common stock for issuance upon the exercise of outstanding options (with an exercise price of $13.75 per share) granted to former and continuing board members in 1999 and 2000.
In connection with our acquisition of DLS, we entered into an investors rights agreement with the seller parties to the DLS stock purchase agreement, who collectively hold 3,311,300 shares of our common stock as of February 29, 2008. In connection with our acquisition of substantially all the assets of OGR, we entered into an investor rights agreement with the stockholders of OGR, who hold 3.2 million shares of our common stock. Under these agreements, the DLS sellers and the OGR stockholders are entitled to certain rights with respect to the registration of the sale of such shares under the Securities Act. By exercising their registration rights and causing a large number of shares to be sold in the public market, these holders could cause the market price of our common stock to decline.
We cannot predict whether future sales of our common stock, or the availability of our common stock for sale, will adversely affect the market price for our common stock or our ability to raise capital by offering equity securities.
24
Risks Associated With Our Indebtedness
We have a substantial amount of debt, which could adversely affect our financial health and prevent us from making principal and interest payments on our outstanding senior notes and our other debt.
At December 31, 2007, we had approximately $514.7 million of consolidated total indebtedness outstanding and approximately $81.6 million of additional secured borrowing capacity available under our credit agreement.
Our substantial debt could:
| | |
| | • | make it more difficult for us to satisfy our obligations with respect to our outstanding senior notes, any other debt securities we may offer and our other debt; |
| |
| | • | increase our vulnerability to general adverse economic and industry conditions, including declines in oil and natural gas prices and declines in drilling activities; |
| |
| | • | limit our ability to obtain additional financing for future working capital, capital expenditures, mergers and other general corporate purposes; |
| |
| | • | require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the availability of our cash flow for operations and other purposes; |
| |
| | • | limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; |
| |
| | • | make us more vulnerable to increases in interest rates; |
| |
| | • | place us at a competitive disadvantage compared to our competitors that have less debt; and |
| |
| | • | have a material adverse effect on us if we fail to comply with the covenants in the indentures relating to our outstanding senior notes, and any other debt securities we may offer or in the instruments governing our other debt. |
In addition, we may incur substantial additional debt in the future. Each of the indentures governing our outstanding senior notes permits (and we anticipate that the indentures governing any other debt securities we may offer will also permit) us to incur additional debt, and our credit agreement permits additional borrowings. If new debt is added to our current debt levels, these related risks could increase.
We may not maintain sufficient revenues to sustain profitability or to meet our capital expenditure requirements and our financial obligations. Also, we may not be able to generate a sufficient amount of cash flow to meet our debt service obligations.
Our ability to make scheduled payments or to refinance our obligations with respect to our debt will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to certain financial, business, and other factors beyond our control. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay scheduled expansion and capital expenditures, sell material assets or operations, obtain additional capital or restructure our debt. We cannot assure you that our operating performance, cash flow and capital resources will be sufficient for payment of our debt in the future. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, we cannot assure you that the terms of any such transaction would be satisfactory to us or if or how soon any such transaction could be completed.
If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses, which could result in a failure to grow or result in defaults in our obligations under our credit agreement, our outstanding senior notes or our other debt securities.
In order to refinance indebtedness, expand existing operations and acquire additional businesses, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses and may be unable to meet our obligations under our credit agreement, our senior notes or any other debt securities we may offer.
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The indentures governing our outstanding senior notes and our credit agreement impose (and we anticipate that the indentures governing any other debt securities we may offer will also impose) restrictions on us that may limit the discretion of management in operating our business and that, in turn, could impair our ability to meet our obligations.
The indentures governing our outstanding senior notes and our credit agreement contain (and we anticipate that the indentures governing any other debt securities we may offer will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things:
| | |
| | • | incur additional debt; |
| |
| | • | make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; |
| |
| | • | sell assets, including capital stock of our restricted subsidiaries; |
| |
| | • | restrict dividends or other payments by restricted subsidiaries; |
| |
| | • | create liens; |
| |
| | • | enter into transactions with affiliates; and |
| |
| | • | merge or consolidate with another company. |
The credit agreement also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests or that the lenders under the credit agreement will waive any failure to meet such ratios or tests.
These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise to conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of these covenants could result in a default under the indentures governing our outstanding senior notes and any other debt securities we may offerand/or the credit agreement. If there were an event of default under any of the indenturesand/or the credit agreement, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our credit agreement when it becomes due, the lenders under the credit agreement could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default.
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| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
26
The following table describes the location and general character of the principal physical properties used in each of our company’s businesses as of February 29, 2008. Our principal executive office is rented and located in Houston, Texas and the table below presents all of our operating locations and whether the property is owned or leased.
| | | | | |
Business Segment | | Location | | Owned/Leased |
| |
| Rental Services | | Houston, Texas | | Leased — 2 locations |
| | | Victoria, Texas | | Owned |
| | | Broussard, Louisiana | | Leased |
| | | Lafayette, Louisiana | | Leased |
| | | Morgan City, Louisiana | | Owned |
| International Drilling | | Buenos Aires, Argentina | | Leased |
| | | Comodoro Rivadavia, Argentina | | Owned |
| | | Neuquen, Argentina | | Owned |
| | | Rincon de los Sauces, Argentina | | Owned |
| | | Tartagal, Argentina | | Owned |
| | | Santa Cruz, Bolivia | | Leased |
| Directional Drilling | | Conroe, Texas | | Leased |
| | | Houston, Texas | | Leased — 2 locations |
| | | Oklahoma City, Oklahoma | | Leased |
| | | Denver, Colorado | | Leased |
| | | Casper, Wyoming | | Leased |
| Tubular Services | | Corpus Christi, Texas | | Leased |
| | | Edinburg, Texas | | Owned |
| | | Kilgore, Texas | | Leased |
| | | Pearsall, Texas | | Leased |
| | | Broussard, Louisiana | | Leased — 2 locations |
| | | Houma, Louisiana | | Leased |
| | | Youngsville, Louisiana | | Owned |
| | | Elk City, Oklahoma | | Leased |
| Underbalanced Drilling | | Fort Stockton, Texas | | Leased |
| | | Grandbury, Texas | | Leased |
| | | Houston, Texas | | Leased |
| | | Midland, Texas | | Leased |
| | | San Angelo, Texas | | Leased |
| | | Sonora, Texas | | Leased |
| | | Carlsbad, New Mexico | | Leased |
| | | Farmington, New Mexico | | Leased |
| | | Mt Morris, Pennsylvania | | Leased |
| | | Grand Junction, Colorado | | Leased |
| | | Wilburton, Oklahoma | | Leased |
| Production Services | | Searcy, Arkansas | | Leased |
| | | Alvin, Texas | | Leased |
| | | Corpus Christi, Texas | | Leased |
| | | Longview, Texas | | Leased |
| | | Broussard, Louisiana | | 1 Owned & 1 Leased |
| | | Houma, Louisiana | | Leased |
| |
| ITEM 3. | LEGAL PROCEEDINGS |
On June 29, 1987, we filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Our plan of reorganization was confirmed by the Bankruptcy Court after acceptance by our creditors and stockholders, and was consummated on December 2, 1988.
27
At confirmation of our plan of reorganization, the United States Bankruptcy Court approved the establishment of the A-C Reorganization Trust as the primary vehicle for distributions and the administration of claims under our plan of reorganization, two trust funds to service health care and life insurance programs for retired employees and a trust fund to process and liquidate future product liability claims. The trusts assumed responsibility for substantially all remaining cash distributions to be made to holders of claims and interests pursuant to our plan of reorganization. We were thereby discharged of all debts that arose before confirmation of our plan of reorganization.
We do not administer any of the aforementioned trusts and retain no responsibility for the assets transferred to or distributions to be made by such trusts pursuant to our plan of reorganization.
As part of our plan of reorganization, we settled U.S. Environmental Protection Agency claims for cleanup costs at all known sites where we were alleged to have disposed of hazardous waste. The EPA settlement included both past and future cleanup costs at these sites and released us of liability to other potentially responsible parties in connection with these specific sites. In addition, we negotiated settlements of various environmental claims asserted by certain state environmental protection agencies.
Subsequent to our bankruptcy reorganization, the EPA and state environmental protection agencies have in a few cases asserted that we are liable for cleanup costs or fines in connection with several hazardous waste disposal sites containing products manufactured by us prior to consummation of our plan of reorganization. In each instance, we have taken the position that the cleanup costs and all other liabilities related to these sites were discharged in the bankruptcy, and the cases have been disposed of without material cost. A number of Federal Courts of Appeal have issued rulings consistent with this position, and based on such rulings, we believe that we will continue to prevail in our position that our liability to the EPA and third parties for claims for environmental cleanup costs that had pre-petition triggers have been discharged. A number of claimants have asserted claims for environmental cleanup costs that had pre-petition triggers, and in each event, the A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, has responded to such claims, generally, by informing claimants that our liabilities were discharged in the bankruptcy. Each of such claims has been disposed of without material cost. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.
The EPA and certain state agencies continue from time to time to request information in connection with various waste disposal sites containing products manufactured by us before consummation of the plan of reorganization that were disposed of by other parties. Although we have been discharged of liabilities with respect to hazardous waste sites, we are under a continuing obligation to provide information with respect to our products to federal and state agencies. The A-C Reorganization Trust, under its mandate to provide plan of reorganization implementation services to us, has responded to these informational requests because pre-bankruptcy activities are involved.
The A-C Reorganization Trust is being dissolved, and as a result, we will assume the responsibility of responding to claimants and to the EPA and state agencies previously undertaken by the A-C Reorganization Trust. However, we have been advised by the A-C Reorganization Trust that its cost of providing these services has not been material in the past, and therefore we do not expect to incur material expenses as a result of responding to such requests. However, there can be no assurance that we will not be subject to environmental claims relating to pre-bankruptcy activities that would have a material adverse effect on us.
We are named as a defendant from time to time in product liability lawsuits alleging personal injuries resulting from our activities prior to our reorganization involving asbestos. These claims are referred to and handled by a special products liability trust formed to be responsible for such claims in connection with our reorganization. As with environmental claims, we do not believe we are liable for product liability claims relating to our business prior to our bankruptcy; moreover, the products liability trust continues to defend all such claims. However, there can be no assurance that we will not be subject to material product liability claims in the future or that the products liability trust will continue to have funds to pay any such claims.
We have been named as a defendant in three lawsuits in connection with our proposed merger with Bronco Drilling, Inc. We do not believe that the suits have any merit.
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We are involved in various other legal proceedings, including labor contract litigation, in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceedings is remote.
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| ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None
PART II
| |
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. |
MARKET PRICE INFORMATION
Our common stock is traded on the New York Stock Exchange under the symbol “ALY”. Prior to March 22, 2007, our common stock was traded on the American Stock Exchange. The following table sets forth, for periods prior to March 22, 2007, high and low sales prices from our common stock, as reported on the American Stock Exchange and for periods since March 22, 2007, high and low sale prices of our common stock reported on the New York Stock Exchange.
| | | | | | | | | |
Calendar Quarter | | High | | | Low | |
| |
2006 | | | | | | | | |
| First Quarter | | $ | 18.50 | | | $ | 12.46 | |
| Second Quarter | | | 17.62 | | | | 10.85 | |
| Third Quarter | | | 19.33 | | | | 9.80 | |
| Fourth Quarter | | | 25.55 | | | | 12.15 | |
2007 | | | | | | | | |
| First Quarter | | $ | 23.61 | | | $ | 14.10 | |
| Second Quarter | | | 24.39 | | | | 15.83 | |
| Third Quarter | | | 28.10 | | | | 18.35 | |
| Fourth Quarter | | | 19.49 | | | | 14.09 | |
Holders
As of February 29, 2008, there were approximately 1,275 holders of record of our common stock. On February 29, 2008, the closing price for our common stock reported on the New York Stock Exchange was $12.62 per share.
Dividends
No dividends were declared or paid during the past three years, and no dividends are anticipated to be declared or paid in the foreseeable future. Our credit facilities and the indentures governing our senior notes restrict our ability to pay dividends on our common stock.
29
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2007 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.
| | | | | | | | | | | | | |
| | | Number of
| | | | | | | |
| | | Securities to be
| | | Weighted
| | | | |
| | | Issued Upon
| | | Average Exercise
| | | Number of Securities
| |
| | | Exercise of
| | | Price of
| | | Remaining Available
| |
| | | Outstanding
| | | Outstanding
| | | for Future Issuance
| |
| | | Options, Warrants
| | | Options, Warrants
| | | Under Equity
| |
Plan Category | | And Rights | | | and Rights | | | Compensation Plans | |
| |
| Equity compensation plans approved by security holders | | | 1,696,763 | | | $ | 10.76 | | | | 527,131 | |
| Equity compensation plans not approved by security holders | | | 4,000 | | | $ | 13.75 | | | | — | |
| | | | | | | | | | | | | |
| Total | | | 1,700,763 | | | $ | 10.77 | | | | 527,131 | |
| | | | | | | | | | | | | |
Equity Compensation Plans Not Approved By Security Holders
These plans comprise the following:
In 1999 and 2000, the Board compensated former and continuing Board members who had served from 1989 to March 31, 1999 without compensation by issuing promissory notes totaling $325,000 and by granting stock options to these same individuals. Options to purchase 4,800 shares of common stock were granted with an exercise price of $13.75. These options vested immediately and expire in March 2010. As of December 31, 2007, 4,000 of these options remain outstanding.
In connection with the private placement in April 2004, we issued warrants for the purchase of 800,000 shares of our common stock at an exercise price of $2.50 per share. A total of 486,557 of these warrants were exercised in 2005 and the remaining warrants were exercised in 2006. Warrants for 4,000 shares of our common stock at an exercise price of $4.65 were also issued in May 2004 and were exercised in January 2007.
30
PERFORMANCE GRAPH
Set forth below is a line graph comparing the annual percentage change in the cumulative return to the stockholders of our common stock with the cumulative return of the Russell 2000 and the CoreData Services Oil and Gas Equipment and Services Index for the period commencing January 1, 2002 and ending on December 31, 2007. Our common stock was a component of the Russell 2000 during the year ended December 31, 2007. The CoreData Services Oil and Gas Equipment and Services Index is an index of approximately 75 oil and gas equipment and services providers. The information contained in the performance graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.
The graph assumes that $100 was invested on January 1, 2002 in our common stock and in each index, and that all dividends were reinvested. No dividends have been declared or paid on our common stock. Stockholder returns over the indicated period should not be considered indicative of future shareholder returns.
COMPARISON OF CUMULATIVE TOTAL RETURN
OF ONE OR MORE COMPANIES, PEER GROUPS, INDUSTRY INDEXES
AND/OR BROAD MARKETS
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fiscal Year Ending |
| Company/Index/Market | | 12/31/2002 | | 12/31/2003 | | 12/31/2004 | | 12/30/2005 | | 12/29/2006 | | 12/31/2007 |
Allis-Chalmers Energy Inc. | | | 100.00 | | | | 101.96 | | | | 192.16 | | | | 489.02 | | | | 903.53 | | | | 578.43 | |
| |
Oil & Gas Equipment/Svcs | | | 100.00 | | | | 121.99 | | | | 167.42 | | | | 253.03 | | | | 298.70 | | | | 425.38 | |
| |
Russell 2000 Index | | | 100.00 | | | | 145.37 | | | | 170.81 | | | | 176.48 | | | | 206.61 | | | | 196.40 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
31
| |
| ITEM 6. | SELECTED FINANCIAL DATA. |
The following selected historical financial information for each of the five years ended December 31, 2007, has been derived from our audited consolidated financial statements and related notes. Certain reclassifications have been made to the prior year’s selected financial data to conform with the current period presentation. This information is only a summary and should be read in conjunction with material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere herein. As discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we have during the past five years effected a number of business combinations and other transactions that materially affect the comparability of the information set forth below (in thousands, except per share amounts):
| | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | 2003 | |
| |
Statement of Operations Data | | | | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 570,967 | | | $ | 310,964 | | | $ | 108,022 | | | $ | 49,307 | | | $ | 33,278 | |
| Income from operations | | $ | 124,782 | | | $ | 67,730 | | | $ | 13,518 | | | $ | 4,291 | | | $ | 2,981 | |
| Net income from continuing operations | | $ | 50,440 | | | $ | 35,626 | | | $ | 7,175 | | | $ | 888 | | | $ | 2,927 | |
| Net income attributed to common stockholders | | $ | 50,440 | | | $ | 35,626 | | | $ | 7,175 | | | $ | 764 | | | $ | 2,271 | |
| Per Share Data: | | | | | | | | | | | | | | | | | | | | |
| Net income from continuing operations per common share: | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 1.48 | | | $ | 1.73 | | | $ | 0.48 | | | $ | 0.10 | | | $ | 0.58 | |
| Diluted | | $ | 1.45 | | | $ | 1.66 | | | $ | 0.44 | | | $ | 0.09 | | | $ | 0.50 | |
| Weighted average number of common shares outstanding: | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 34,158 | | | | 20,548 | | | | 14,832 | | | | 7,930 | | | | 3,927 | |
| Diluted | | | 34,701 | | | | 21,410 | | | | 16,238 | | | | 9,510 | | | | 5,850 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | 2003 | |
| |
Balance Sheet Data | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 1,053,585 | | | $ | 908,326 | | | $ | 137,355 | | | $ | 80,192 | | | $ | 53,662 | |
| Long-term debt classified as: | | | | | | | | | | | | | | | | | | | | |
| Current | | $ | 6,434 | | | $ | 6,999 | | | $ | 5,632 | | | $ | 5,541 | | | $ | 3,992 | |
| Long-term | | $ | 508,300 | | | $ | 561,446 | | | $ | 54,937 | | | $ | 24,932 | | | $ | 28,241 | |
| Redeemable convertible Preferred stock | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,171 | |
| Stockholders’ equity | | $ | 414,329 | | | $ | 253,933 | | | $ | 60,875 | | | $ | 35,109 | | | $ | 4,541 | |
| Book value per share | | $ | 11.80 | | | $ | 8.99 | | | $ | 3.61 | | | $ | 2.58 | | | $ | 1.30 | |
| |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with our selected historical financial data and our accompanying financial statements and the notes to those financial statements included elsewhere in this document. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of risks and uncertainties, including, but not limited to, those discussed under “Item 1A. Risk Factors.”
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Overview of Our Business
We are a multi-faceted oilfield services company that provides services and equipment to oil and natural gas exploration and production companies throughout the United States, including Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: Rental Services; International Drilling; Directional Drilling; Tubular Services; Underbalanced Drilling and Production Services.
We derive operating revenues from rates per job that we charge for the labor and equipment required to provide a service and rates per day for equipment and tools that we rent to our customers. The price we charge for our services depends upon several factors, including the level of oil and natural gas drilling activity and the competitive environment in the particular geographic regions in which we operate. Contracts are awarded based on the price, quality of service and equipment, and the general reputation and experience of our personnel. The demand for drilling services has historically been volatile and is affected by the capital expenditures of oil and natural gas exploration and development companies, which can fluctuate based upon the prices of oil and natural gas or the expectation for the prices of oil and natural gas.
The number of working drilling rigs, typically referred to as the “rig count,” is an important indicator of activity levels in the oil and natural gas industry. The rig count in the United States increased from 862 as of December 31, 2002 to 1,763 as of February 29, 2008, according to the Baker Hughes rig count. Furthermore, directional and horizontal rig counts increased from 283 as of December 31, 2002 to 817 as of February 29, 2008, which accounted for 33% and 46% of the total U.S. rig count, respectively. The offshore Gulf of Mexico rig count, however, decreased to 58 rigs at February 29, 2008 from 90 rigs one year earlier. We believe this is due to the relocation of rigs to international markets as a result of the high oil prices.
Our cost of revenues represents all direct and indirect costs associated with the operation and maintenance of our equipment. The principal elements of these costs are direct and indirect labor and benefits, repairs and maintenance of our equipment, insurance, equipment rentals, fuel and depreciation. Operating expenses do not fluctuate in direct proportion to changes in revenues because, among other factors, we have a fixed base of inventory of equipment and facilities to support our operations, and in periods of low drilling activity we may also seek to preserve labor continuity to market our services and maintain our equipment.
Results of Operations
In April 2005, we acquired all of the outstanding stock of Delta and, in May 2005, we acquired all of the outstanding stock of Capcoil. We report the operations of Downhole and Capcoil in our Production Services segment and the operations of Safco and Delta in our Rental Services segment. In July 2005, we acquired the 45% interest of M-I in our Underbalanced Drilling subsidiary, AirComp, making us the 100% owner of AirComp. In addition, in July 2005, we acquired the underbalanced drilling assets of W. T. On August 1, 2005, we acquired all of the outstanding capital stock of Target. We included Target results in our Directional Drilling segment because Target’s measurement while drilling equipment is utilized in that segment. On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. We consolidated the results of these acquisitions from the day they were acquired.
In January 2006, we acquired all of the outstanding stock of Specialty and in December 2006, we acquired substantially all of the assets of OGR. We report the operations of Specialty and OGR in our Rental Services segment. In April 2006, we acquired all of the outstanding stock of Rogers. We report the operations of Rogers in our Tubular Services segment. In August 2006, we acquired all of the outstanding stock of DLS and in December 2006, we acquired all of the outstanding stock of Tanus. We report the operations of DLS and Tanus in our International Drilling segment. In October 2006, we acquired all of the outstanding stock of Petro Rentals. We report the operations of Petro Rentals in our Production Services segment. We consolidated the results of these acquisitions from the day they were acquired.
In June 2007, we acquired all of the outstanding stock of Coker and in July 2007, we acquired all of the outstanding stock of Diggar and in November 2007, we acquired substantially all of the assets of Diamondback. We report the operations of Coker, Diggar and Diamondback in our Directional Drilling segment. In October 2007, we acquired all of the outstanding stock of Rebel. We report the operations of
33
Rebel in our Tubular Services segment. We consolidated the results of these acquisitions from the day they were acquired.
The foregoing acquisitions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.
Comparison of Years Ended December 31, 2007 and December 31, 2006
Our revenues for the year ended December 31, 2007 were $571.0 million, an increase of 83.6% compared to $311.0 million for the year ended December 31, 2006. Revenues increased in all of our business segments due principally to the acquisitions completed during the two year period ended December 31, 2007, the investment in new equipment and the opening of new operating locations. The most significant increase in revenues was due to the acquisition of DLS on August 14, 2006 which established our International Drilling segment. Revenues also increased significantly at our Rental Services segment due to the acquisition of the OGR assets on December 18, 2006. Our Directional Drilling segment revenues increased in the 2007 period compared to the 2006 period due to acquisitions completed in the third and fourth quarters of 2007 which added downhole motors, measurement-while-drilling, or MWD, tools, and directional drilling personnel resulting in increased capacity and increased market penetration. Revenues increased at our Underbalanced Drilling segment due to the purchase of additional equipment, principally new compressor packages, and expansion of operations into new geographic regions.
Our gross margin for the year ended December 31, 2007 increased 69.9% to $178.6 million, or 31.3% of revenues, compared to $105.1 million, or 33.8%, of revenues for the year ended December 31, 2006. The increase in gross profit is due to the increase in revenues in all of our business segments. The decrease in gross profit as a percentage of revenues is primarily due to the 151.3% increase in depreciation expense to $50.9 million in 2007 from $20.3 million in 2006. The increase in depreciation expense is due to the acquisition of the OGR assets, the acquisition of DLS and our capital expenditures. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.
General and administrative expense was $58.6 million for the year ended December 31, 2007 compared to $35.5 million for the year ended December 31, 2006. General and administrative expense increased due to the acquisitions, and the hiring of additional sales, operations, accounting and administrative personnel. As a percentage of revenues, general and administrative expenses were 10.3% in 2007 compared to 11.4% in 2006. General and administrative expense includes share-based compensation expense of $4.7 million in 2007 and $3.0 million in 2006.
On June 29, 2007, we sold our capillary tubing assets that were part of our Production Services segment. The total consideration was approximately $16.3 million in cash. We recognized a gain of $8.9 million related to the sale of these assets.
Amortization expense was $4.1 million for the year ended December 31, 2007 compared to $1.9 million for the year ended December 31, 2006. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions.
Income from operations for the year ended December 31, 2007 totaled $124.8 million, an 84.2% increase over the $67.7 million in income from operations for the year ended December 31, 2006, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expense and amortization expense. Our income from operations as a percentage of revenues increased slightly to 21.9% in 2007 from 21.8% in 2006. Income from operations in the 2007 period includes an $8.9 million gain from the sale of our capillary tubing assets in the second quarter of 2007.
Our net interest expense was $46.3 million for the year ended December 31, 2007, compared to $20.3 million for the year ended December 31, 2006. Interest expense increased in 2007 due to our increased debt. In August 2006 we issued $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. In January 2007 we issued $250.0 million of senior notes bearing interest at 8.5% to pay off, in part, the $300.0 million bridge loan utilized to complete the OGR acquisition and for working capital. This bridge loan was repaid on January 29, 2007. The average interest rate on the bridge loan was
34
approximately 10.6%. Interest expense for 2007 includes the write-off of deferred financing fees of $1.2 million related to the repayment of the bridge loan. Interest expense includes amortization expense of deferred financing costs of $1.9 million and $1.5 million for 2007 and 2006, respectively.
Our provision for income taxes for the year ended December 31, 2007 was $28.8 million, or 36.4% of our net income before income taxes, compared to $11.4 million, or 24.3% of our net income before income taxes for 2006. The increase in our provision for income taxes is attributable to the increase in our operating income and a higher effective tax rate. The effective tax rate in 2006 was favorably impacted by the reversal of our valuation allowance on our deferred tax assets. The valuation allowance was reversed due to operating results that allowed for the realization of our deferred tax assets.
We had net income attributed to common stockholders of $50.4 million for the year ended December 31, 2007, an increase of 41.6%, compared to net income attributed to common stockholders of $35.6 million for the year ended December 31, 2006.
The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2007 and December 31, 2006. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Revenues | | | Income (Loss) from Operations | |
| | | 2007 | | | 2006 | | | Change | | | 2007 | | | 2006 | | | Change | |
| | | (In thousands) | |
| |
| Rental Services | | $ | 121,186 | | | $ | 51,521 | | | $ | 69,665 | | | $ | 49,139 | | | $ | 26,293 | | | $ | 22,846 | |
| International Drilling | | | 215,795 | | | | 69,490 | | | | 146,305 | | | | 38,839 | | | | 12,233 | | | | 26,606 | |
| Directional Drilling | | | 96,080 | | | | 76,471 | | | | 19,609 | | | | 18,848 | | | | 17,666 | | | | 1,182 | |
| Tubular Services | | | 53,524 | | | | 50,887 | | | | 2,637 | | | | 10,744 | | | | 12,544 | | | | (1,800 | ) |
| Underbalanced Drilling | | | 50,959 | | | | 43,045 | | | | 7,914 | | | | 13,091 | | | | 10,810 | | | | 2,281 | |
| Production Services | | | 33,423 | | | | 19,550 | | | | 13,873 | | | | 10,535 | | | | 2,137 | | | | 8,398 | |
| General Corporate | | | — | | | | — | | | | — | | | | (16,414 | ) | | | (13,953 | ) | | | (2,461 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 570,967 | | | $ | 310,964 | | | $ | 260,003 | | | $ | 124,782 | | | $ | 67,730 | | | $ | 57,052 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Rental Services. Our Rental Services revenues were $121.2 million for the year ended December 31, 2007, an increase of 135.2% from the $51.5 million in revenues for the year ended December 31, 2006. Income from operations increased 86.9% to $49.1 million in 2007 compared to $26.3 million in 2006. The increase in revenue and operating income is primarily attributable to the acquisition of the OGR assets in December 2006. Income from operations as a percentage of revenues decreased to 40.5% for 2007 compared to 51.0% for the prior year as a result of higher depreciation expense associated with the OGR acquisition and capital expenditures. Rental Services revenues and operating income was impacted by a more competitive market environment due to the decreased U.S. Gulf of Mexico drilling activity in the last half of 2007 due to the hurricane season and the departure of drilling rigs in favor of the international markets.
International Drilling. On August 14, 2006, we acquired DLS which established our International Drilling segment. Our international drilling revenues were $215.8 million for the year ended December 31, 2007, an increase from the $69.5 million in revenues for the year ended December 31, 2006. Income from operations increased to $38.8 million in 2007 compared to $12.2 million in 2006. Income from operations as percentage of revenue increased to 18.0% for 2007 compared to 17.6% for 2006. During 2007 we placed orders for 16 service rigs (workover rigs and pulling rigs) and four drilling rigs. Four of the service rigs were delivered in the fourth quarter of 2007. We expect all the rigs to be placed in service during the first three quarters of 2008.
Directional Drilling. Revenues for the year ended December 31, 2007 for our Directional Drilling segment were $96.1 million, an increase of 25.6% from the $76.5 million in revenues for the year ended December 31, 2006. The increase in revenues is due to the purchase of additional MWD tools and the benefit of acquisitions completed in the last half of 2007 which added downhole motors, MWDs, and directional drillers. The additional equipment and personnel enabled us to strengthen our presence in new geographic markets and increase our market penetration. Income from operations increased 6.7% to $18.8 million for
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2007 from $17.7 million for 2006. Income from operations as a percentage of revenues decreased to 19.6% for 2007 compared to 23.1% for the prior year. The decrease in our operating margin a percentage of revenues is due to increased expenses for downhole motor rentals and repairs, experienced primarily in the first three quarters of 2007 prior to the recent additions to our downhole motor fleet, increased personnel costs and increased depreciation expense.
Tubular Services. Revenues for the year ended December 31, 2007 for the Tubular Services segment were $53.5 million, an increase of 5.2% from the $50.9 million in revenues for the year ended December 31, 2006. Revenues from domestic operations increased to $45.6 million in 2007 from $44.4 million in 2006 as a result of the investment in new equipment and the acquisition of Rogers in April 2006. Revenues from Mexican operations increased to $7.9 million in 2007 from $6.5 million in 2006. Income from operations decreased 14.3% to $10.7 million in 2007 from $12.5 million in 2006. Income from operations as a percentage of revenues decreased to 20.1% for 2007 compared to 24.7% for the prior year. The results of our Tubular Services segment were impacted by an increasingly competitive environment domestically for casing and tubing services, exacerbated by the decline in drilling activity in the U.S. Gulf of Mexico in the last half of 2007, and decreased sales of power tongs in 2007 compared to 2006. While revenues from Mexican operations increased 21.5% in 2007 compared to 2006, they were impacted in the fourth quarter of 2007, by severe weather and flooding in Mexico.
Underbalanced Drilling. Our Underbalanced Drilling revenues were $51.0 million for the year ended December 31, 2007, an increase of 18.4% compared to $43.0 million in revenues for the year ended December 31, 2006. Income from operations increased 21.1% to $13.1 million in 2007 compared to income from operations of $10.8 million in 2006. Income from operations as a percentage of revenues increased slightly to 25.7% in 2007 from 25.1% in 2006. Our Underbalanced Drilling revenues and operating income for the 2007 period increased compared to the 2006 period due in part to our investment in additional equipment, principally new compressors and new “foam” units. During 2007 Underbalanced Drilling was affected by a decrease in drilling activity in certain geographic areas by some of our customers, offset by an increased market presence and growth in drilling activity in other, more attractive geographic areas.
Production Services Segment. Our Production Services revenues were $33.4 million for the year ended December 31, 2007, compared to $19.6 million in revenues for the year ended December 31, 2006. Income from operations was $10.5 million in 2007 compared to income from operations of $2.1 million in 2006. Revenues for 2007 increased compared to 2006 due primarily to our acquisition of Petro Rentals on October 17, 2006, the addition of two coil tubing units in the fourth quarter of 2006, one unit in the first quarter of 2007 and one additional unit delivered at the end of the second quarter of 2007, offset in part by the sale of our capillary tubing assets in June 2007. The increase in income from operations can be attributed to an $8.9 million gain on sale of our capillary tubing assets. During 2007 our Production Services segment experienced delays in the delivery and activation of new coil tubing units. As a result, we experienced low utilization for our coil tubing units and increases in personnel expenses, including increased lodging, relocation and training expenses for the crews without the benefit of corresponding increases in revenues.
Comparison of Years Ended December 31, 2006 and December 31, 2005
Our revenues for the year ended December 31, 2006 was $311.0 million, an increase of 187.9% compared to $108.0 million for the year ended December 31, 2005. Revenues increased in all of our business segments due to the successful integration of acquisitions completed in the third quarter of 2005 and during 2006, the investment in new equipment, improved pricing for our services, the addition of operations and sales personnel and the opening of new operations offices. Revenues increased most significantly due to the acquisition of DLS on August 14, 2006 which expanded our operations to a sixth operating segment, International Drilling. Revenues also increased significantly at our Rental Services segment due to the acquisition of Specialty effective January 1, 2006. Our Tubular Services segment also had a substantial increase in revenue, primarily due to the acquisitions of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005, and the acquisition of Rogers as of April 1, 2006, along with the investment in additional equipment, improved market conditions and increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. Revenues increased at our Underbalanced Drilling segment due to the purchase of additional equipment and improved pricing for our services. Our Directional Drilling segment revenues
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increased in the 2006 period compared to the 2005 period due to improved pricing for directional drilling services, the August 2005 acquisition of Target which provides MWD tools and the purchase of additional down-hole motors and MWDs which increased our capacity and market presence.
Our gross margin for the year ended December 31, 2006 increased 243.8% to $105.1 million, or 33.8% of revenues, compared to $30.6 million, or 28.3%, of revenues for the year ended December 31, 2005. The increase in gross profit is due to the increase in revenues in all of our business segments. The increase in gross profit as a percentage of revenues is primarily due to the acquisition of Specialty as of January 1, 2006, in the high margin rental tool business, the improved pricing for our services generally and the investments in new capital equipment. Also contributing to our improved gross profit margin was the acquisition of Target, the purchase of additional MWD’s and the acquisition of Rogers. The increase in gross profit was partially offset by an increase in depreciation expense of 315.7% to $20.3 million compared to $4.9 million for 2005. The increase is due to additional depreciable assets resulting from the acquisitions and capital expenditures. Our cost of revenues consists principally of our labor costs and benefits, equipment rentals, maintenance and repairs of our equipment, depreciation, insurance and fuel. Because many of our costs are fixed, our gross profit as a percentage of revenues is generally affected by our level of revenues.
General and administrative expense was $35.5 million for the year ended December 31, 2006 compared to $15.6 million for the year ended December 31, 2005. General and administrative expense increased due to additional expenses associated with the acquisitions, and the hiring of additional sales, operations and administrative personnel. General and administrative expense also increased because of increased accounting and consulting fees and other expenses in connection with initiatives to strengthen our internal control processes, costs related to Sarbanes Oxley compliance efforts and increased corporate accounting and administrative staff. As a percentage of revenues, general and administrative expenses were 11.4% in 2006 compared to 14.4% in 2005.
We adopted SFAS No. 123R,Share-Based Payment,effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. Therefore, we recorded an expense of $3.4 million related to stock awards for the year ended December 31, 2006 of which $3.0 million was recorded in general and administrative expense with the balance being recorded as a direct cost. Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25, or APB No. 25. Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. Accordingly, no compensation cost was recognized under APB No. 25.
Amortization expense was $1.9 million for the year ended December 31, 2006 compared to $1.5 million for the year ended December 31, 2005. The increase in amortization expense is due to the amortization of intangible assets in connection with our acquisitions.
Income from operations for the year ended December 31, 2006 totaled $67.7 million, a 401.0% increase over the $13.5 million in income from operations for the year ended December 31, 2005, reflecting the increase in our revenues and gross profit, offset in part by increased general and administrative expenses. Our income from operations as a percentage of revenues increased to 21.8% in 2006 from 12.5% in 2005 due to the increase in our gross margin which offset the increases in amortization expense and general and administrative expenses.
Our net interest expense was $20.3 million for the year ended December 31, 2006, compared to $4.7 million for the year ended December 31, 2005. Interest expense increased in 2006 due to our increased debt. In January of 2006 we issued $160.0 million of senior notes bearing interest at 9.0% to fund the acquisition of Specialty, pay off other outstanding debt and for working capital. In August 2006 we issued an additional $95.0 million of senior notes bearing interest at 9.0% to fund a portion of the acquisition of DLS. On December 18, 2006, we borrowed $300.0 million in a senior unsecured bridge loan to fund the acquisition
37
of OGR. The average interest rate on the bridge loan was approximately 10.6%. Interest expense for 2006 includes the write-off of $453,000 related to financing fees on the bridge loan. This bridge loan was repaid on January 29, 2007 and the remaining $1.2 million of financing fees were written off in 2007. In the third quarter of 2005, we incurred debt retirement expense of $1.1 million related to the refinancing of our debt. This amount includes prepayment penalties and the write-off of deferred financing fees from a previous financing.
Minority interest in income of subsidiaries for the year ended December 31, 2006 was $0 compared to $488,000 for the corresponding period in 2005 due to the our acquisition of the minority interest at AirComp on July 11, 2005.
Our provision for income taxes for the year ended December 31, 2006 was $11.4 million, or 24.3% of our net income before income taxes, compared to $1.3 million, or 15.8% of our net income before income taxes for 2005. The increase in our provision for income taxes is attributable to the significant increase in our operating income which resulted in the utilization of our deferred tax assets including our net operating losses, and the increase in percentage of income taxes to net income before income taxes attributable to our operations in Argentina which are taxed at 35.0%.
We had net income attributed to common stockholders of $35.6 million for the year ended December 31, 2006, an increase of 396.5%, compared to net income attributed to common stockholders of $7.2 million for the year ended December 31, 2005.
The following table compares revenues and income from operations for each of our business segments for the years ended December 31, 2006 and December 31, 2005. Income from operations consists of our revenues less cost of revenues, general and administrative expenses, and depreciation and amortization:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Revenues | | | Income (Loss) from Operations | |
| | | 2006 | | | 2005 | | | Change | | | 2006 | | | 2005 | | | Change | |
| | | | | | | | | (In thousands) | | | | | | | |
| |
| Rental Services | | $ | 51,521 | | | $ | 5,059 | | | $ | 46,462 | | | $ | 26,293 | | | $ | 1,300 | | | $ | 24,993 | |
| International Drilling | | | 69,490 | | | | — | | | | 69,490 | | | | 12,233 | | | | — | | | | 12,233 | |
| Directional Drilling | | | 76,471 | | | | 46,579 | | | | 29,892 | | | | 17,666 | | | | 7,389 | | | | 10,277 | |
| Tubular Services | | | 50,887 | | | | 20,932 | | | | 29,955 | | | | 12,544 | | | | 4,994 | | | | 7,550 | |
| Underbalanced Drilling | | | 43,045 | | | | 25,662 | | | | 17,383 | | | | 10,810 | | | | 5,612 | | | | 5,198 | |
| Production Services | | | 19,550 | | | | 9,790 | | | | 9,760 | | | | 2,137 | | | | (99 | ) | | | 2,236 | |
| General Corporate | | | — | | | | — | | | | — | | | | (13,953 | ) | | | (5,678 | ) | | | (8,275 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 310,964 | | | $ | 108,022 | | | $ | 202,942 | | | $ | 67,730 | | | $ | 13,518 | | | $ | 54,212 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Rental Services Segment. Our rental services revenues were $51.5 million for the year ended December 31, 2006, an increase from the $5.1 million in revenues for the year ended December 31, 2005. Income from operations increased to $26.3 million in 2006 compared to $1.3 million in 2005. The increase in revenue and operating income is primarily attributable to the acquisition of Specialty effective January 1, 2006, improved pricing, improved utilization of our inventory of rental equipment and to a lesser extent, the acquisition of the OGR assets in December 2006.
International Drilling Segment. Our international drilling revenues were $69.5 million for the year ended December 31, 2006, and our income from operations was $12.2 million. This segment of our operations was created with the acquisition of DLS in August of 2006.
Directional Drilling Segment. Revenues for the year ended December 31, 2006 for our Directional Drilling segment were $76.5 million, an increase of 64.2% from the $46.6 million in revenues for the year ended December 31, 2005. Income from operations increased 139.1% to $17.7 million for 2006 from $7.4 million for 2005. The improved results for this segment are due to the increase in drilling activity in the Texas and Gulf Coast areas, improved pricing, the acquisition of Target as of August 1, 2005 and the purchase of an additional six MWDs. Our increased operating expenses as a result of the addition of operations and personnel were more than offset by the growth in revenues and improved pricing for our services
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Tubular Services Segment. Revenues for the year ended December 31, 2006 for the Tubular Services segment were $50.9 million, an increase of 143.1% from the $20.9 million in revenues for the year ended December 31, 2005. Revenues from domestic operations increased to $44.4 million in 2006 from $14.5 million in 2005 as a result of the acquisition of Rogers, the acquisition of the casing and tubing assets of Patterson Services, Inc. on September 1, 2005 and investment in new equipment, all of which resulted in increased market penetration for our services in South Texas, East Texas, Louisiana and the U.S. Gulf of Mexico. The year ended December 2005 was also adversely impacted by hurricane activity in September of 2005. Revenues from Mexican operations increased to $6.5 million in 2006 from $6.4 million in 2005. Income from operations increased 151.2% to $12.5 million in 2006 from $5.0 million in 2005. The increase in this segment’s operating income is due to increased revenues both domestically and in our Mexico operations.
Underbalanced Drilling Segment. Our underbalanced drilling revenues were $43.0 million for the year ended December 31, 2006, an increase of 67.7% compared to $25.7 million in revenues for the year ended December 31, 2005. Income from operations increased 92.6% to $10.8 million in 2006 compared to income from operations of $5.6 million in 2005. Our underbalanced drilling revenues and operating income for the 2006 period increased compared to the 2005 period due in part to the acquisition of the air drilling assets of W. T., our investment in additional equipment and improved pricing in West Texas.
Production Services Segment. Our production services revenues were $19.6 million for the year ended December 31, 2006, compared to $9.8 million in revenues for the year ended December 31, 2005. Income from operations was $2.1 million in 2006 compared to a loss from operations of $99,000 in 2005. The increase in revenue is attributable to the acquisition of Petro-Rentals completed in October 2006, the acquisition of Capcoil on May 1, 2005 and improved utilization and pricing for our services. The increase in operating income is primarily related to the operations of Petro-Rental and the addition of two coil tubing units in the fourth quarter of 2006.
Liquidity and Capital Resources
Our on-going capital requirements arise primarily from our need to service our debt, to acquire and maintain equipment, to fund our working capital requirements and to complete acquisitions. Our primary sources of liquidity are proceeds from the issuance of debt and equity securities and cash flows from operations. We had cash and cash equivalents of $43.7 million at December 31, 2007 compared to $39.7 million at December 31, 2006.
Operating Activities
In the year ended December 31, 2007, we generated $103.5 million in cash from operating activities. Net income for the year ended December 31, 2007 was $50.4 million. Non-cash additions to net income totaled $60.6 million in the 2007 period consisting primarily of $55.0 million of depreciation and amortization, $4.9 million related to the expensing of stock options as required under SFAS No. 123R, $8.0 million of deferred income tax, $730,000 for a provision for bad debts and $3.2 million of amortization and write-off of deferred financing fees, partially offset by $2.3 million of gain from the disposition of equipment and a $8.9 million gain from the sale of capillary assets.
During the year ended December 31, 2007, changes in working capital used $7.6 million in cash, principally due to an increase of $30.8 million in accounts receivable, an increase of $4.5 million in other assets and an increase in inventories of $5.4 million, offset by a decrease of $8.2 million in other current assets, an increase of $10.7 million in accounts payable, an increase of $6.0 million in accrued interest, an increase of $4.0 million in accrued employee benefits and payroll taxes, an increase of $1.5 million in accrued expenses and an increase in other long-term liabilities of $2.7 million. Our accounts receivables increased at December 31, 2007 primarily due to the increase in our revenues in 2007. Other assets increase primarily due to the contract costs related to the deployment of new rigs for our International Drilling segment. The decrease in other current assets is principally due to the collection of the working capital adjustment from the OGR acquisition for approximately $7.1 million in the first quarter of 2007. Accrued interest increased at December 31, 2007 due principally to interest accrued on our 8.5% senior notes issued in January 2007 and our 9.0% senior notes issued in August 2006 which are both payable semi-annually. Our accounts payable, accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the
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increase in costs due to our growth in revenues and acquisition completed in 2007. Other long-term liabilities increased primarily due to the deferral of contract revenue related to our new rigs being constructed in the International drilling segment.
In the year ended December 31, 2006, we generated $53.7 million in cash from operating activities. Net income for the year ended December 31, 2006 was $35.6 million. Non-cash additions to net income totaled $27.6 million in the 2006 period consisting primarily of $22.1 million of depreciation and amortization, $3.4 million related to the expensing of stock options as required under SFAS No. 123R, $2.2 million of deferred income tax, $781,000 for a provision for bad debts and $1.5 million for amortization of finance fees, including the bridge loan fees, partially offset by $2.4 million of gain from the disposition of equipment.
During the year ended December 31, 2006, changes in working capital used $9.9 million in cash, principally due to an increase of $23.2 million in accounts receivable, an increase of $2.6 million in inventories, a decrease of $2.3 million in accounts payable, offset in part by a decrease in other current assets of $2.5 million, an increase of $11.4 million in accrued interest, an increase of $3.4 million in accrued employee benefits and payroll taxes and an increase of $872,000 in accrued expenses. Our accounts receivables increased at December 31, 2006 primarily due to the increase in our revenues in 2006. Accrued interest increased at December 31, 2006 due principally to interest accrued on our 9.0% senior notes, which are payable semi-annually. Our accrued employee benefits and payroll taxes and other accrued expenses increased primarily due to the increase in costs due to our growth in revenues and acquisition completed in 2006.
In the year ended December 31, 2005, we generated $3.6 million in cash from operating activities. Net income for the year ended December 31, 2005 was $7.2 million. Non-cash additions to net income totaled $7.4 million in the 2005 period consisting primarily of $6.4 million of depreciation and amortization, $488,000 of minority interest in the income of a subsidiary, $962,000 in amortization and write-off of financing fees in conjunction with a refinancing and $219,000 for a provision for bad debts, partially offset by $669,000 of gain from the disposition of equipment.
During the year ended December 31, 2005, changes in working capital used $11.0 million in cash, principally due to an increase of $10.7 million in accounts receivable, an increase of $3.1 million in inventories, an increase in other assets of $936,000, a decrease in other liabilities of $266,000 and a decrease of $97,000 in accrued expenses, offset in part by a decrease in other current assets of $929,000, an increase of $2.4 million in accounts payable, an increase of $324,000 in accrued interest and a increase of $443,000 in accrued employee benefits and payroll taxes. Our accounts receivables increased at December 31, 2005 due primarily to the increase in our revenues in 2005. Accounts payable increased by $2.4 million at December 31, 2005 due to the increase in our cost of sales associated with the increase in our revenues and the acquisitions completed in 2005 and 2004.
Investing Activities
During the year ended December 31, 2007, we used $137.1 million in investing activities consisting of four acquisitions and our capital expenditures. During the year ended December 31, 2007, we completed the following acquisitions for a total net cash outlay of $41.0 million, consisting of the purchase price and acquisition costs less cash acquired:
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| | • | In June 2007, we acquired Coker for a purchase price of approximately $3.6 million in cash and a promissory note for $350,000. |
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| | • | In July 2007, we acquired Diggar for a purchase price of approximately $6.7 million in cash, the payment of approximately $2.8 million of debt and a promissory note for $750,000. |
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| | • | In October 2007, we acquired Rebel for a purchase price of approximately $5.0 million in cash, the payment of approximately $1.8 million of debt and escrow and promissory notes for an aggregate of $500,000. |
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| | • | In November 2007, we acquired substantially all of the assets of Diamondback for a purchase price of approximately $23.1 million in cash. |
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In addition we made capital expenditures of approximately $113.2 million during the year ended December 31, 2007, including $34.9 million to increase our inventory of equipment and replace“lost-in-hole” equipment in the Rental Services segment, $28.9 million to purchase, improve and replace equipment in our International Drilling segment, $11.2 million to purchase equipment for our Directional Drilling segment, $17.4 million to purchase and improve equipment in our Underbalanced Drilling segment, $9.3 million to purchase and improve our Tubular Services equipment and approximately $10.7 million to expand our Production Services segment. We received proceeds of $16.3 million from the sale of our capillary assets. We also received $12.8 million from the sale of assets during the year ended December 31, 2007, comprised mostly from equipment“lost-in-hole” from our Rental Services segment ($11.0 million) and our Directional Drilling segment ($1.4 million). We also made advance payments of $11.5 million on the purchase of new drilling and service rigs to be delivered in 2008 for our International Drilling segment.
During the year ended December 31, 2006, we used $559.4 million in investing activities consisting of six acquisitions and our capital expenditures. During the year ended December 31, 2006, we completed the following acquisitions for a total net cash outlay of $526.6 million, consisting of the purchase price and acquisition costs less cash acquired:
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| | • | Effective January 1, 2006, we acquired Specialty for a purchase price of approximately $95.3 million in cash. |
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| | • | Effective April 1, 2006, we acquired Rogers for a purchase price of approximately $11.3 million in cash, 125,285 shares of our common stock and a promissory note for $750,000. |
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| | • | On August 14, 2006, we acquired DLS for a purchase price of approximately $93.7 million in cash, 2.5 million shares of our common stock and the assumption of $9.1 million of indebtedness. |
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| | • | On October 16, 2006, we acquired Petro Rentals for a purchase price of approximately $20.2 million in cash, 246,761 shares of our common stock and the payment of approximately $9.6 million of debt. |
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| | • | Effective December 1, 2006, we acquired Tanus for a purchase price of $2.5 million in cash. |
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| | • | On December 18, 2006, we acquired substantially all of the assets of OGR for a purchase price of approximately $291.0 million in cash and 3.2 million shares of our common stock. |
In addition we made capital expenditures of approximately $39.7 million during the year ended December 31, 2006, including $4.5 million to replace“lost-in-hole” equipment and to increase our inventory of equipment in the Rental Services segment, $5.8 million to purchase, improve and replace equipment in our international drilling segment, $5.1 million to purchase equipment for our Directional Drilling segment, $7.7 million to purchase and improve equipment in our Underbalanced Drilling segment, $11.0 million to purchase and improve our tubular services equipment and approximately $5.3 million to expand our Production Services segment. We also received $6.9 million from the sale of assets during the year ended December 31, 2006, comprised mostly from equipment“lost-in-hole” from our Rental Services segment ($3.8 million) and our Directional Drilling segment ($1.8 million).
During the year ended December 31, 2005, we used $53.1 million in investing activities. During the year ended December 31, 2005, we completed the following acquisitions for a total net cash outlay of $36.9 million, consisting of the purchase price and acquisition costs less cash acquired:
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| | • | On April 1, 2005 we acquired Delta for a purchase price of approximately $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. |
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| | • | On May 1, 2005, we acquired Capcoil for a purchase price of approximately $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. |
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| | • | On July 11, 2005, we acquired the compressed air drilling assets of W.T. for a purchase price of $6.0 million in cash. |
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| | • | On July 11, 2005, we acquired from M-I it’s 45% interest in AirComp and subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and reissued a $4.0 million subordinated note. |
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| | • | Effective August 1, 2005, we acquired Target for a purchase price of approximately $1.3 million in cash and forgiveness of a lease receivable of $592,000. |
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| | • | On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for a purchase price of approximately $15.6 million. |
In addition we made capital expenditures of approximately $17.8 million during the year ended December 31, 2005, including $2.9 million to purchase equipment for our Directional Drilling segment, $7.0 million to purchase and improve equipment in our Underbalanced Drilling segment, $5.2 million to purchase and improve our tubular services equipment and approximately $1.5 million to expand our Production Services segment. We also received $1.6 million from the sale of assets during the year ended December 31, 2005, comprised mostly from equipment lost in the hole from our Directional Drilling segment ($1.0 million) and our Rental Services segment ($408,000).
Financing Activities
During the year ended December 31, 2007, financing activities provided a net of $37.6 million in cash. We received $250.0 million in borrowings from the issuance of our 8.5% senior notes due 2017. We also received $100.1 million in net proceeds from the issuance of 6,000,000 shares of our common stock, $1.7 million on the tax benefit of stock compensation plans and $3.3 million from the proceeds of warrant and option exercises for 882,624 shares of our common stock. The proceeds were used to repay long-term debt totaling $309.7 million and to pay $7.8 million in debt issuance costs. The repayment of long-term debt consisted primarily of the repayment of our $300.0 million bridge loan which was used to fund the acquisition of the OGR assets.
During the year ended December 31, 2006, financing activities provided a net of $543.6 million in cash. We received $557.8 million in borrowings under long-term debt facilities, consisting primarily of the issuance of $255.0 million of our 9.0% senior notes due 2014 and a $300.0 million senior unsecured bridge loan. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of the OGR assets. We also received $46.3 million in net proceeds from the issuance of 3,450,000 shares of our common stock, $6.4 million on the tax benefit of options and $6.3 million from the proceeds of warrant and option exercises for 1,851,377 shares of our common stock. The proceeds were used to repay long-term debt totaling $54.0 million, repay $6.4 million in net borrowings under our revolving lines of credit, repay related party debt of $3.0 million and to pay $9.9 million in debt issuance costs.
During the year ended December 31, 2005, financing activities provided a net of $44.1 million in cash. We received $56.3 million in borrowings under long-term debt facilities, $15.5 million in net proceeds from the issuance of 1,761,034 shares of our common stock, $2.5 million in net borrowings under our revolving lines of credit and $1.4 million from the proceeds of warrant and option exercises for 1,076,154 shares of our common stock. The proceeds were used to repay long-term debt totaling $28.2 million, repay related party debt of $1.5 million and to pay $1.8 million in debt issuance costs.
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $160.0 million and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes. Debt repaid included all outstanding balances under our credit agreement, including a $42.1 million term loan and $6.4 million in working capital advances, a $4.0 million subordinated note issued in connection with acquisition of AirComp, approximately $3.0 million subordinated note issued in connection with the acquisition of Tubular, approximately $548,000 on a real estate loan and approximately $350,000 on outstanding equipment financing.
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering,
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were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provides for a $25.0 million revolving line of credit with a maturity of January 2010. This agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the agreement are secured by substantially all of our assets excluding the DLS assets, but including 2/3 of our shares of DLS. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and has a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the United States. At December 31, 2007 and 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $8.4 million and $9.7 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 6.7% and 7.0% at December 31, 2007 and 2006, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2007 and 2006 was $4.9 million and $7.3 million, respectively.
As part of the acquisition of MCA in 2001, we issued a note to the sellers of MCA in the original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result of an action brought against us by the sellers. Under the terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims. At December 31, 2007 and 2006 the outstanding amounts due were $0 and $150,000, respectively.
In connection with the purchase of Delta, we issued to the sellers a note in the amount of $350,000. The note bore interest at 2% and the principal and accrued interest was repaid on its maturity of April 1, 2006. In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bears interest at 8.25% and is due June 29, 2008. In connection with the purchase of Diggar, we issued to the seller a note in the amount of $750,000. The note bears interest at 6.0% and is due July 26, 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount of $500,000. The notes bear interest at 5.0% and are due October 23, 2008.
In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to the seller in exchange for a non-compete agreement. Monthly payments of $20,576 were due under this agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products, Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We were required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements at December 31, 2007 and 2006 were $110,000 and $270,000, respectively.
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. At December 31, 2007 and 2006, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 7.8% to 8.7% and terms of 2 to 5 years. As of December 31, 2007 and 2006, the outstanding balances for rig and equipment
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financing loans were $595,000 and $3.5 million, respectively. In January 2006, we prepaid $350,000 of the outstanding equipment loans with proceeds from our senior notes offering.
In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. In April 2007 and August 2007, we obtained insurance premium financings in the amount of $3.2 million and $1.3 with fixed interest rates of 5.9% and 5.7%, respectively. Under terms of the agreements, amounts outstanding are paid over 11 month repayment schedules. The outstanding balance of these notes was approximately $1.7 million as of December 31, 2007.
We also have various capital leases with terms that expire in 2008. As of December 31, 2007 and 2006, amounts outstanding under capital leases were $14,000 and $414,000, respectively.
The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts and consulting agreements for the periods specified as of December 31, 2007.
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| | | Payments by Period | |
| | | | | | Less Than
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| | | Total | | | 1 Year | | | 1-3 Years | | | 3-5 Years | | | After 5 Years | |
| | | (In thousands) | |
| |
Contractual Obligations | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | $ | 514,720 | | | $ | 6,420 | | | $ | 2,950 | | | $ | 350 | | | $ | 505,000 | |
| Capital leases | | | 14 | | | | 14 | | | | — | | | | — | | | | — | |
| Interest payments on long-term debt | | | 334,018 | | | | 44,588 | | | | 88,577 | | | | 88,406 | | | | 112,447 | |
| Operating leases | | | 5,941 | | | | 2,618 | | | | 2,354 | | | | 593 | | | | 376 | |
| Employment contracts | | | 7,511 | | | | 3,543 | | | | 3,968 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total contractual cash obligations | | $ | 862,204 | | | $ | 57,183 | | | $ | 97,849 | | | $ | 89,349 | | | $ | 617,823 | |
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We have identified capital expenditure projects that will require up to approximately $140.0 million in 2008, exclusive of any acquisitions, of which $82.7 million is committed as of December 31, 2007. We believe that our cash generated from operations, cash on hand and cash available under our credit facilities will provide sufficient funds for our identified projects.
We intend to implement a growth strategy of increasing the scope of services through both internal growth and acquisitions. We are regularly involved in discussions with a number of potential acquisition candidates. We expect to make capital expenditures to acquire and to maintain our existing equipment. Our performance and cash flow from operations will be determined by the demand for our services which in turn are affected by our customers’ expenditures for oil and natural gas exploration and development and industry perceptions and expectations of future oil and natural gas prices in the areas where we operate. We will need to refinance our existing debt facilities as they become due and provide funds for capital expenditures and acquisitions. To effect our expansion plans, we will require additional equity or debt financing in excess of our current working capital and amounts available under credit facilities. There can be no assurance that we will be successful in raising the additional debt or equity capital or that we can do so on terms that will be acceptable to us.
Recent Developments
On January 23, 2008, we entered into an Agreement and Plan of Merger with Bronco Drilling Company, Inc., or Bronco, whereby Bronco will become a wholly-owned subsidiary of Allis-Chalmers. The merger agreement, which was approved by our Board of Directors and the Board of Directors of Bronco, provides that the Bronco stockholders will receive aggregate merger consideration with a value of approximately $437.8 million, consisting of (a) $280.0 million in cash and (b) shares of our common stock, par value $0.01 per share, having an aggregate value of approximately $157.8 million. The number of shares of our common stock to be issued will be based on the average closing price of our common stock for the ten-trading day period ending
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two days prior to the closing. Completion of the merger is conditioned upon, among other things, adoption of the merger agreement by Bronco’s stockholders and approval by our stockholders of the issuance of shares of our common stock to be used as merger consideration.
In order to finance some or all of the cash component of the merger consideration, the repayment of outstanding Bronco debt and transaction expenses, we expect to incur debt of up to $350.0 million. We intend to obtain up to $350.0 million from either (1) a permanent debt financing of up to $350.0 million or (2) if the permanent debt financing cannot be consummated prior to the closing date of the merger, the draw down under a senior unsecured bridge loan facility in an aggregate principal amount of up to $350.0 million to be arranged by RBC Capital Markets Corporation and Goldman Sachs Credit Partners L.P., acting as joint lead arrangers and joint bookrunners. We executed a commitment letter, dated January 28, 2008, with Royal Bank of Canada and Goldman Sachs who have each, subject to certain conditions, severally committed to provide 50% of the loans under the senior unsecured bridge facility to us. This commitment for the bridge loan facility will terminate on July 31, 2008, if we have not drawn the bridge facility by such date and the merger is not consummated by such date. The commitment may also terminate prior to July 31, 2008, if the merger is abandoned or a material condition to the merger is not satisfied or we breach our obligations under the commitment letter. We may use the proceeds of the bridge facility to finance the cash component of the merger consideration, repay outstanding Bronco debt and pay transaction expenses.
On January 29, 2008, Burt A. Adams resigned as our President and Chief Operating Officer, effective February 28, 2008. Mr. Adams will remain as a member of our Board of Directors. On January 29, 2008, Mark C. Patterson was elected our Senior Vice-President — Rental Services. On January 29, 2008, Terrence P. Keane was elected our Senior Vice-President — Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH Ltd., or BCH, to invest $40.0 million in cash in BCH in the form of a 15% Convertible Subordinated Secured debenture. The debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable investment bank. BCH is a Canadian-based oilfield services company engaged in contract drilling operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility will be used to fund a portion of the purchase price of the new drilling and service rigs ordered for our international drilling operation. The facility is available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual instalments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. Interest is payable every six months. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets.
Critical Accounting Policies
We have identified the policies below as critical to our business operations and the understanding of our results of operations. The impact and any associated risks related to these policies on our business operations is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations where such policies affect our reported and expected financial results. For a detailed discussion on the application of these and other accounting policies, see Note 1 in the Notes to the Consolidated Financial Statements included elsewhere in this document. Our preparation of this report requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of our financial statements, and the reported amounts of revenue and expenses during the reporting period. There can be no assurance that actual results will not differ from those estimates.
Allowance For Doubtful Accounts. The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customer payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Those uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to
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pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customers will not be able to make the required payments at either contractual due dates or in the future.
Revenue Recognition. We provide rental equipment and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. The Securities and Exchange Commission’s Staff Accounting Bulletin No. 104,Revenue Recognition in Financial Statements, provides guidance on the SEC staff’s views on application of generally accepted accounting principles to selected revenue recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.
Impairment Of Long-Lived Assets. Long-lived assets, which include property, plant and equipment, goodwill and other intangibles, comprise a significant amount of our total assets. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of our future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.
Goodwill And Other Intangibles. As of December 31, 2007, we have recorded approximately $138.4 million of goodwill and $35.2 million of other identifiable intangible assets. We perform purchase price allocations to intangible assets when we make a business combination. Business combinations and purchase price allocations have been consummated for acquisitions in all of our reportable segments. The excess of the purchase price after allocation of fair values to tangible assets is allocated to identifiable intangibles and thereafter to goodwill. Subsequently, we perform our initial impairment tests and annual impairment tests in accordance with Financial Accounting Standards Board No. 141,Business Combinations, and Financial Accounting Standards Board No. 142,Goodwill and Other Intangible Assets.These initial valuations used two approaches to determine the carrying amount of the individual reporting units. The first approach is the Discounted Cash Flow Method, which focuses on our expected cash flow. In applying this approach, the cash flow available for distribution is projected for a finite period of years. Cash flow available for distribution is defined as the amount of cash that could be distributed as a dividend without impairing our future profitability or operations. The cash flow available for distribution and the terminal value (our value at the end of the estimation period) are then discounted to present value to derive an indication of value of the business enterprise. This valuation method is dependent upon the assumptions made regarding future cash flow and cash requirements. The second approach is the Guideline Company Method which focuses on comparing us to selected reasonably similar publicly traded companies. Under this method, valuation multiples are: (i) derived from operating data of selected similar companies; (ii) evaluated and adjusted based on our strengths and weaknesses relative to the selected guideline companies; and (iii) applied to our operating data to arrive at an indication of value. This valuation method is dependent upon the assumption that our value can be evaluated by analysis of our earnings and our strengths and weaknesses relative to the selected similar companies. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.
Income Taxes. The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the
46
ultimate tax liabilities in certain tax jurisdictions are determined. Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.
It is our intention to permanently reinvest all of the undistributed earnings of ournon-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of ournon-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
Recently Issued Accounting Standards
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of Statement No. 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. We believe that the adoption of SFAS No. 157 will not have a material impact on our financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one or more other businesses or assets at the acquisition date and in subsequent periods. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) beginning January 1, 2009 and apply to future acquisitions.
In February 2007, the FASB issued Statement No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the provisions of SFAS No. 159 and have not yet determined the impact, if any, on our financial statements.
In December 2007, the FASB issued SFAS No. 160,Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS No. 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as
47
equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We believe the adoption of SFAS No. 160 will not have a material impact on our financial position or results of operations.
Off-Balance Sheet Arrangements
We have no off balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. We have a $90.0 million revolving line of credit with a maturity of January 2010. At December 31, 2007, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $8.4 million. We do not guarantee obligations of any unconsolidated entities.
| |
| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK. |
We are exposed to market risk primarily from changes in interest rates and foreign currency exchange risks.
Interest Rate Risk
Fluctuations in the general level of interest rates on our current and future fixed and variable rate debt obligations expose us to market risk. We are vulnerable to significant fluctuations in interest rates on our variable rate debt and on any future refinancing of our fixed rate debt and on future debt.
At December 31, 2007, we were exposed to interest rate fluctuations on approximately $4.9 million of bank loans carrying variable interest rates. A hypothetical one hundred basis point increase in interest rates for these notes payable would increase our annual interest expense by approximately $49,000. Due to the uncertainty of fluctuations in interest rates and the specific actions that might be taken by us to mitigate the impact of such fluctuations and their possible effects, the foregoing sensitivity analysis assumes no changes in our financial structure.
We have also been subject to interest rate market risk for short-term invested cash and cash equivalents. The principal of such invested funds would not be subject to fluctuating value because of their highly liquid short-term nature. As of December 31, 2007, we had $31.1 million invested in short-term maturing investments.
Foreign Currency Exchange Rate Risk
We have designated the U.S. dollar as the functional currency for our operations in international locations as we contract with customers, purchase equipment and finance capital using the U.S. dollar. Local currency transaction gains and losses, arising from remeasurement of certain assets and liabilities denominated in local currency, are included in our consolidated statements of income. For the years ended December 31, 2007 and 2006, we had a net foreign exchange loss of $128,000 and $515,000, respectively relating to our DLS operations. We conduct business in Mexico through our Mexican partner, Matyep. This business exposes us to foreign exchange risk. To control this risk, we provide for payment in U.S. dollars.
48
| |
| ITEM 8. | FINANCIAL STATEMENTS. |
INDEX TO FINANCIAL STATEMENTS
ALLIS-CHALMERS ENERGY INC. AND SUBSIDIARIES
| | | | | |
| | | Page | |
| |
| | | 50 | |
| | | 51 | |
| | | 53 | |
| | | 54 | |
| | | 55 | |
| | | 56 | |
| | | 57 | |
| | | 92 | |
49
MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF ALLIS-CHALMERS ENERGY INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Allis-Chalmers Energy Inc. and its subsidiaries, or Allis-Chalmers. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing, using the criteria inInternal Control-Integral Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Allis-Chalmers’ system of 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 accounting principles generally accepted in the United States of America. Because of its inherent limitation, internal control over financial reporting may not prevent or detect misstatements.
Based on our assessment, we have concluded that Allis-Chalmers maintained effective internal control over financial reporting as of December 31, 2007, based on criteria inInternal Control-Integrated Frameworkissued by the COSO. The effectiveness of Allis-Chalmers internal control over financial reporting as of December 31, 2007 has been audited by UHY LLP, an independent registered public accounting firm, as stated in their report, which is included herein.
Management’s Certifications
The certifications of Allis-Chalmers’ Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Allis-Chalmers’Form 10-K.
ALLIS-CHALMERS ENERGY INC.
| | | | | | | | | |
| By: | | /s/ Munawar H. Hidayatallah
| | | | By: | | /s/ Victor M. Perez
|
| | | Munawar H. Hidayatallah | | | | | | Victor Perez |
| | | Chief Executive Officer | | | | | | Chief Financial Officer |
50
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Allis-Chalmers Energy Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule 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 audits 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 6 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretations No. 48:Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109 and, as discussed in Note 1, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004):Share Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2008 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 6, 2008
51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Allis-Chalmers Energy Inc.:
We have audited Allis-Chalmers Energy Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Allis-Chalmers Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting of Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Allis-Chalmers Energy Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Allis-Chalmers Energy Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated March 6, 2008 expressed an unqualified opinion thereon.
/s/ UHY LLP
Houston, Texas
March 6, 2008
52
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | |
| | | December 31, | |
| | | 2007 | | | 2006 | |
| | | (In thousands, except
| |
| | | for share and per share
| |
| | | amounts) | |
| |
ASSETS |
| Cash and cash equivalents | | $ | 43,693 | | | $ | 39,745 | |
| Trade receivables, net of allowance for doubtful accounts of $1,924 and | | | | | | | | |
| $826 at December 31, 2007 and 2006, respectively | | | 130,094 | | | | 95,766 | |
| Inventories | | | 32,209 | | | | 28,615 | |
| Prepaid expenses and other | | | 11,898 | | | | 16,636 | |
| | | | | | | | | |
| Total current assets | | | 217,894 | | | | 180,762 | |
| Property and equipment, at cost net of accumulated depreciation of $77,008 and $29,743 at December 31, 2007 and 2006, respectively | | | 626,668 | | | | 554,258 | |
| Goodwill | | | 138,398 | | | | 125,835 | |
| Other intangible assets, net of accumulated amortization of $6,218 and $4,475 at December 31, 2007 and 2006, respectively | | | 35,180 | | | | 32,840 | |
| Debt issuance costs, net of accumulated amortization of $2,718 and $1,501 at December 31, 2007 and 2006, respectively | | | 14,228 | | | | 9,633 | |
| Other assets | | | 21,217 | | | | 4,998 | |
| | | | | | | | | |
| Total assets | | $ | 1,053,585 | | | $ | 908,326 | |
| | | | | | | | | |
| |
| LIABILITIES AND STOCKHOLDERS’ EQUITY |
| Current maturities of long-term debt | | $ | 6,434 | | | $ | 6,999 | |
| Trade accounts payable | | | 37,464 | | | | 25,666 | |
| Accrued salaries, benefits and payroll taxes | | | 15,283 | | | | 10,888 | |
| Accrued interest | | | 17,817 | | | | 11,867 | |
| Accrued expenses | | | 20,545 | | | | 16,951 | |
| | | | | | | | | |
| Total current liabilities | | | 97,543 | | | | 72,371 | |
| Deferred income tax liability | | | 30,090 | | | | 19,953 | |
| Long-term debt, net of current maturities | | | 508,300 | | | | 561,446 | |
| Other long-term liabilities | | | 3,323 | | | | 623 | |
| | | | | | | | | |
| Total liabilities | | | 639,256 | | | | 654,393 | |
| Commitments and Contingencies | | | | | | | | |
| Stockholders’ Equity | | | | | | | | |
| Preferred stock, $0.01 par value (25,000,000 shares authorized, none issued) | | | — | | | | — | |
| Common stock, $0.01 par value (100,000,000 shares authorized; 35,116,035 issued and outstanding at December 31, 2007 and 28,233,411 issued and outstanding at December 31, 2006) | | | 351 | | | | 282 | |
| Capital in excess of par value | | | 326,095 | | | | 216,208 | |
| Retained earnings | | | 87,883 | | | | 37,443 | |
| | | | | | | | | |
| Total stockholders’ equity | | | 414,329 | | | | 253,933 | |
| | | | | | | | | |
| Total liabilities and stockholders’ equity | | $ | 1,053,585 | | | $ | 908,326 | |
| | | | | | | | | |
The accompanying Notes are an integral part of the Consolidated Financial Statements.
53
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| | | (In thousands, except per
| |
| | | share amounts) | |
| |
| Revenues | | $ | 570,967 | | | $ | 310,964 | | | $ | 108,022 | |
| Cost of revenues | | | | | | | | | | | | |
| Direct costs | | | 341,450 | | | | 185,579 | | | | 72,567 | |
| Depreciation | | | 50,914 | | | | 20,261 | | | | 4,874 | |
| | | | | | | | | | | | | |
| Gross margin | | | 178,603 | | | | 105,124 | | | | 30,581 | |
| General and administrative expenses | | | 58,622 | | | | 35,536 | | | | 15,576 | |
| Gain on capillary asset sale | | | (8,868 | ) | | | — | | | | — | |
| Amortization | | | 4,067 | | | | 1,858 | | | | 1,487 | |
| | | | | | | | | | | | | |
| Income from operations | | | 124,782 | | | | 67,730 | | | | 13,518 | |
| | | | | | | | | | | | | |
| Other income (expense): | | | | | | | | | | | | |
| Interest expense | | | (49,534 | ) | | | (21,309 | ) | | | (4,746 | ) |
| Interest income | | | 3,259 | | | | 972 | | | | 49 | |
| Other | | | 776 | | | | (347 | ) | | | 186 | |
| | | | | | | | | | | | | |
| Total other expense | | | (45,499 | ) | | | (20,684 | ) | | | (4,511 | ) |
| | | | | | | | | | | | | |
| Income before minority interest and income taxes | | | 79,283 | | | | 47,046 | | | | 9,007 | |
| Minority interest in income of subsidiaries | | | — | | | | — | | | | (488 | ) |
| Provision for income taxes | | | (28,843 | ) | | | (11,420 | ) | | | (1,344 | ) |
| | | | | | | | | | | | | |
| Net income | | $ | 50,440 | | | $ | 35,626 | | | $ | 7,175 | |
| | | | | | | | | | | | | |
| Income per common share: | | | | | | | | | | | | |
| Basic | | $ | 1.48 | | | $ | 1.73 | | | $ | 0.48 | |
| | | | | | | | | | | | | |
| Diluted | | $ | 1.45 | | | $ | 1.66 | | | $ | 0.44 | |
| | | | | | | | | | | | | |
| Weighted average number of common shares outstanding: | | | | | | | | | | | | |
| Basic | | | 34,158 | | | | 20,548 | | | | 14,832 | |
| | | | | | | | | | | | | |
| Diluted | | | 34,701 | | | | 21,410 | | | | 16,238 | |
| | | | | | | | | | | | | |
The accompanying Notes are an integral part of the Consolidated Financial Statements.
54
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Capital in
| | | Retained
| | | Total
| |
| | | Common Stock | | | Excess of
| | | Earnings
| | | Stockholders’
| |
| | | Shares | | | Amount | | | Par Value | | | (Deficit) | | | Equity | |
| | | (In thousands, except share amounts) | |
| |
| Balances, December 31, 2004 | | | 13,611,525 | | | $ | 136 | | | $ | 40,331 | | | $ | (5,358 | ) | | $ | 35,109 | |
| Net income | | | — | | | | — | | | | — | | | | 7,175 | | | | 7,175 | |
| Issuance of common stock: | | | | | | | | | | | | | | | | | | | | |
| Acquisitions | | | 411,275 | | | | 4 | | | | 1,746 | | | | — | | | | 1,750 | |
| Secondary public offering, net of offering costs | | | 1,761,034 | | | | 18 | | | | 15,441 | | | | — | | | | 15,459 | |
| Stock options and warrants exercised | | | 1,076,154 | | | | 11 | | | | 1,371 | | | | — | | | | 1,382 | |
| | | | | | | | | | | | | | | | | | | | | |
| Balances, December 31, 2005 | | | 16,859,988 | | | | 169 | | | | 58,889 | | | | 1,817 | | | | 60,875 | |
| Net income | | | — | | | | — | | | | — | | | | 35,626 | | | | 35,626 | |
| Issuance of common stock: | | | | | | | | | | | | | | | | | | | | |
| Acquisitions | | | 6,072,046 | | | | 61 | | | | 94,919 | | | | — | | | | 94,980 | |
| Secondary public offering, net of offering costs | | | 3,450,000 | | | | 34 | | | | 46,263 | | | | — | | | | 46,297 | |
| Issuance under stock plans | | | 1,851,377 | | | | 18 | | | | 6,303 | | | | — | | | | 6,321 | |
| Stock-based compensation | | | — | | | | — | | | | 3,394 | | | | — | | | | 3,394 | |
| Tax benefits on stock plans | | | — | | | | — | | | | 6,440 | | | | — | | | | 6,440 | |
| | | | | | | | | | | | | | | | | | | | | |
| Balances, December 31, 2006 | | | 28,233,411 | | | | 282 | | | | 216,208 | | | | 37,443 | | | | 253,933 | |
| Net income | | | — | | | | — | | | | — | | | | 50,440 | | | | 50,440 | |
| Issuance of common stock: | | | | | | | | | | | | | | | | | | | | |
| Secondary public offering, net of offering costs | | | 6,000,000 | | | | 60 | | | | 99,995 | | | | — | | | | 100,055 | |
| Issuance under stock plans | | | 882,624 | | | | 9 | | | | 3,310 | | | | — | | | | 3,319 | |
| Stock-based compensation | | | — | | | | — | | | | 4,863 | | | | — | | | | 4,863 | |
| Tax benefits on stock plans | | | — | | | | — | | | | 1,719 | | | | — | | | | 1,719 | |
| | | | | | | | | | | | | | | | | | | | | |
| Balances, December 31, 2007 | | | 35,116,035 | | | $ | 351 | | | $ | 326,095 | | | $ | 87,883 | | | $ | 414,329 | |
| | | | | | | | | | | | | | | | | | | | | |
The accompanying Notes are an integral part of the Consolidated Financial Statements.
55
ALLIS-CHALMERS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| | | (In thousands) | |
| |
Cash Flows from Operating Activities: | | | | | | | | | | | | |
| Net income | | $ | 50,440 | | | $ | 35,626 | | | $ | 7,175 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | | 54,981 | | | | 22,119 | | | | 6,361 | |
| Amortization and write-off of deferred financing fees | | | 3,197 | | | | 1,527 | | | | 962 | |
| Stock-based compensation | | | 4,863 | | | | 3,394 | | | | — | |
| Allowance for bad debts | | | 730 | | | | 781 | | | | 219 | |
| Imputed interest | | | — | | | | 355 | | | | — | |
| Deferred taxes | | | 8,017 | | | | 2,215 | | | | — | |
| Minority interest in income of subsidiaries | | | — | | | | — | | | | 488 | |
| Gain on sale of property and equipment | | | (2,323 | ) | | | (2,444 | ) | | | (669 | ) |
| Gain on capillary asset sale | | | (8,868 | ) | | | — | | | | — | |
| Changes in operating assets and liabilities, net of acquisitions: | | | | | | | | | | | | |
| Increase in accounts receivable | | | (30,825 | ) | | | (23,175 | ) | | | (10,656 | ) |
| Increase in inventories | | | (5,375 | ) | | | (2,637 | ) | | | (3,072 | ) |
| Decrease in prepaid expenses and other assets | | | 8,202 | | | | 2,505 | | | | 929 | |
| Increase (decrease) in other assets | | | (4,492 | ) | | | 308 | | | | (936 | ) |
| Increase (decrease) in trade accounts payable | | | 10,732 | | | | (2,337 | ) | | | 2,373 | |
| Increase in accrued interest | | | 5,950 | | | | 11,382 | | | | 324 | |
| Increase (decrease) in accrued expenses | | | 1,508 | | | | 872 | | | | (97 | ) |
| Increase (decrease) in other liabilities | | | 2,700 | | | | (224 | ) | | | (266 | ) |
| Increase in accrued salaries, benefits and payroll taxes | | | 4,031 | | | | 3,392 | | | | 443 | |
| | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 103,468 | | | | 53,659 | | | | 3,578 | |
| | | | | | | | | | | | | |
Cash Flows from Investing Activities: | | | | | | | | | | | | |
| Acquisitions, net of cash acquired | | | (41,000 | ) | | | (526,572 | ) | | | (36,888 | ) |
| Purchase of investment interests | | | (498 | ) | | | — | | | | — | |
| Purchase of property and equipment | | | (113,151 | ) | | | (39,697 | ) | | | (17,767 | ) |
| Deposits on asset commitments | | | (11,488 | ) | | | — | | | | — | |
| Proceeds from sale of capillary assets | | | 16,250 | | | | — | | | | — | |
| Proceeds from sale of property and equipment | | | 12,811 | | | | 6,881 | | | | 1,579 | |
| | | | | | | | | | | | | |
| Net cash used in investing activities | | | (137,076 | ) | | | (559,388 | ) | | | (53,076 | ) |
| | | | | | | | | | | | | |
Cash Flows from Financing Activities: | | | | | | | | | | | | |
| Proceeds from issuance of long-term debt | | | 250,000 | | | | 557,820 | | | | 56,251 | |
| Payments on long-term debt | | | (309,745 | ) | | | (54,030 | ) | | | (28,202 | ) |
| Payments on related party debt | | | — | | | | (3,031 | ) | | | (1,522 | ) |
| Net (repayments) borrowings on lines of credit | | | — | | | | (6,400 | ) | | | 2,527 | |
| Proceeds from issuance of common stock, net of offering costs | | | 100,055 | | | | 46,297 | | | | 15,459 | |
| Proceeds from exercise of options and warrants | | | 3,319 | | | | 6,321 | | | | 1,382 | |
| Tax benefit on stock plans | | | 1,719 | | | | 6,440 | | | | — | |
| Debt issuance costs | | | (7,792 | ) | | | (9,863 | ) | | | (1,821 | ) |
| | | | | | | | | | | | | |
| Net cash provided by financing activities | | | 37,556 | | | | 543,554 | | | | 44,074 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 3,948 | | | | 37,825 | | | | (5,424 | ) |
| Cash and cash equivalents at beginning of year | | | 39,745 | | | | 1,920 | | | | 7,344 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of year | | $ | 43,693 | | | $ | 39,745 | | | $ | 1,920 | |
| | | | | | | | | | | | | |
The accompanying Notes are an integral part of the Consolidated Financial Statements.
56
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements
| |
| NOTE 1 — | NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Organization of Business
Allis-Chalmers Energy Inc. (“Allis-Chalmers”, “we”, “our” or “us”) was incorporated in Delaware in 1913. We provide services and equipment to oil and natural gas exploration and production companies throughout the United States including Texas, Louisiana, New Mexico, Colorado, Oklahoma, Mississippi, Wyoming, Arkansas, West Virginia, offshore in the Gulf of Mexico, and internationally, primarily in Argentina and Mexico. We operate in six sectors of the oil and natural gas service industry: Rental Services; International Drilling; Directional Drilling; Tubular Services; Underbalanced Drilling and Production Services.
The nature of our operations and the many regions in which we operate subject us to changing economic, regulatory and political conditions. We are vulnerable to near-term and long-term changes in the demand for and prices of oil and natural gas and the related demand for oilfield service operations.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Future events and their effects cannot be perceived with certainty. Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts, recoverability of long-lived assets and intangibles, useful lives used in depreciation and amortization, income taxes and valuation allowances. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
Principles of Consolidation
The consolidated financial statements include the accounts of Allis-Chalmers and its subsidiaries. Our subsidiaries at December 31, 2007 are AirComp LLC (“AirComp”), Allis-Chalmers Tubular Services LLC (“Tubular”), Strata Directional Technology LLC (“Strata”), Allis-Chalmers Rental Services LLC (“Rental”), Allis-Chalmers Production Services LLC (“Production”), Allis-Chalmers Management LLC, Allis-Chalmers Holdings Inc., DLS Drilling, Logistics & Services Corporation (“DLS”), DLS Argentina Limited, Tanus Argentina S.A. (“Tanus”), Petro-Rentals LLC (“Petro-Rental”) and Rebel Rentals LLC (“Rebel”). All significant inter-company transactions have been eliminated.
Revenue Recognition
We provide rental equipment and drilling services to our customers at per day, or daywork, and per job contractual rates and recognize the drilling related revenue as the work progresses and when collectibility is reasonably assured. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum and other fees for equipment and other mobilization costs. Mobilization fees and the related costs are deferred and amortized over the contract terms when material. We recognize reimbursements received for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs. Payments from customers for the cost of oilfield rental equipment that is damaged orlost-in-hole are reflected as revenues. We recognized revenue from damaged orlost-in-hole equipment of $12.6 million, $2.4 million and $970,000 for the years ended December 31, 2007, 2006 and 2005, respectively. The Securities and Exchange Commission’s (SEC) Staff Accounting Bulletin (SAB) No. 104,Revenue Recognition In Financial Statements(“SAB No. 104”), provides guidance on the SEC staff’s views on the application of generally accepted accounting principles to selected revenue
57
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
recognition issues. Our revenue recognition policy is in accordance with generally accepted accounting principles and SAB No. 104.
Allowance for Doubtful Accounts
Accounts receivable are customer obligations due under normal trade terms. We sell our services to oil and natural gas exploration and production companies. We perform continuing credit evaluations of its customers’ financial condition and although we generally do not require collateral, letters of credit may be required from customers in certain circumstances.
The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. Significant individual accounts receivable balances which have been outstanding greater than 90 days are reviewed individually for collectibility. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customer’s credit worthiness or other matters affecting the collectibility of amounts due from such customers could have a material effect on the results of operations in the period in which such changes or events occur. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. As of December 31, 2007 and 2006, we had recorded an allowance for doubtful accounts of $1.9 million and $826,000 respectively. Bad debt expense was $1.3 million, $781,000 and $219,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first — in, first — out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.
Property and Equipment
Property and equipment is recorded at cost less accumulated depreciation. Certain equipment held under capital leases are classified as equipment and the related obligations are recorded as liabilities.
Maintenance and repairs, which do not improve or extend the life of the related assets, are charged to operations when incurred. Refurbishments and renewals are capitalized when the value of the equipment is enhanced for an extended period. When property and equipment are sold or otherwise disposed of, the asset account and related accumulated depreciation account are relieved, and any gain or loss is included in operations.
The cost of property and equipment currently in service is depreciated over the estimated useful lives of the related assets, which range from three to twenty years. Depreciation is computed on the straight-line method for financial reporting purposes. Capital leases are amortized using the straight-line method over the estimated useful lives of the assets and lease amortization is included in depreciation expense. Depreciation expense charged to operations was $50.9 million, $20.3 million and $4.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Goodwill, Intangible Assets and Amortization
Goodwill, including goodwill associated with equity method investments, and other intangible assets with infinite lives are not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with finite useful lives are amortized either on a straight-
58
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the write-down is charged against earnings. We perform impairment tests on the carrying value of our goodwill on an annual basis as of December 31st for each of our reportable segments. As of December 31, 2007 and 2006, no impairment was deemed necessary. Increases in estimated future costs or decreases in projected revenues could lead to an impairment of all or a portion of our goodwill in future period.
Impairment of Long-Lived Assets
Long-lived assets, which include property, plant and equipment, and other intangible assets, and certain other assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The impairment loss is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.
Financial Instruments
Financial instruments consist of cash and cash equivalents, accounts receivable and payable, and debt. The carrying value of cash and cash equivalents and accounts receivable and payable approximate fair value due to their short-term nature. We believe the fair values and the carrying value of our debt would not be materially different due to the instruments’ interest rates approximating market rates for similar borrowings at December 31, 2007 and 2006.
Concentration of Credit and Customer Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade accounts receivable. As of December 31, 2007, we have approximately $2.5 million of cash and cash equivalents residing in Argentina. We transact our business with several financial institutions. However, the amount on deposit in six financial institutions exceeded the $100,000 federally insured limit at December 31, 2007 by a total of $13.2 million. Management believes that the financial institutions are financially sound and the risk of loss is minimal.
We sell our services to major and independent domestic and international oil and natural gas companies. We perform ongoing credit valuations of our customers and provide allowances for probable credit losses where appropriate. In 2007 and 2006, one of our customers, Pan American Energy LLC Sucursal Argentina, or Pan American Energy, represented 20.7% and 11.7% of our consolidated revenues, respectively. In 2005 none of our customers accounted for more than 10% of our consolidated revenues. Revenues from Materiales y Equipo Petroleo, or Matyep, represented 3.4%, 8.3% and 94.5% of our international revenues in 2007, 2006 and 2005, respectively. Revenues from Pan American Energy represented 51.0% and 45.6% of our international revenues in 2007 and 2006, respectively.
Debt Issuance Costs
The costs related to the issuance of debt are capitalized and amortized to interest expense using the straight-line method, which approximates the interest method, over the maturity periods of the related debt.
Income Taxes
Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax
59
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
laws and rates in effect in the countries in which operations are conducted and income is earned. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.
The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations and our level of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.
Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in tax rates and changes in prior year tax estimates as returns are filed. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We provide for uncertain tax positions pursuant to FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109(“FIN 48”). Our policy is that we recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits. For United States federal tax purposes, our tax returns for the tax years 2001 through 2006 remain open for examination by the tax authorities. Our foreign tax returns remain open for examination for the tax years 2001 through 2006. Generally, for state tax purposes, our 2002 through 2006 tax years remain open for examination by the tax authorities under a four year statute of limitations, however, certain states may keep their statute open for six to ten years.
It is our intention to permanently reinvest all of the undistributed earnings of ournon-U.S. subsidiaries in such subsidiaries. Accordingly, we have not provided for U.S. deferred taxes on the undistributed earnings of ournon-U.S. subsidiaries. If a distribution is made to us from the undistributed earnings of these subsidiaries, we could be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these undistributed earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.
Stock-Based Compensation
We adopted SFAS No. 123R,Share-Based Payment(“SFAS No. 123R”), effective January 1, 2006. This statement requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their grant-date fair values. Compensation cost for awards granted prior to, but not vested, as of January 1, 2006 would be based on the grant date attributes originally used to value those awards for pro forma purposes under SFAS No. 123,Accounting for Stock-Based Compensation (“SFAS No. 123”). We adopted SFAS No. 123R using the modified prospective transition method, utilizing the Black-Scholes option pricing model for the calculation of the fair value of our employee stock options. Under the modified prospective method, we record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining vesting periods of those awards with no change in historical reported earnings. We estimated forfeiture rates for 2007 and 2006 based on our historical experience.
The Black-Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest is the related U.S. Treasury yield curve for periods within the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero as we have historically not paid dividends and have no current plans to do so in the future. The expected volatility is based on historical volatility of our common stock.
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ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Prior to January 1, 2006, we accounted for our stock-based compensation using Accounting Principle Board Opinion No. 25 (“APB No. 25”). Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. For stock options with exercise prices at or above the market value of the stock on the grant date, we adopted the disclosure-only provisions of SFAS No. 123. We also adopted the disclosure-only provisions of SFAS No. 123 for the stock options granted to our employees and directors. Accordingly, no compensation cost was recognized under APB No. 25. Our net income for the years ended December 31, 2007 and 2006 includes approximately $4.9 million and $3.4 million of compensation costs related to share-based payments, respectively. The tax benefit recorded in association with the share-based payments was $1.7 million and $6.4 million for the years-ended December 31, 2007 and 2006, respectively. As of December 31, 2007 there is $16.3 million of unrecognized compensation expense related to non-vested stock based compensation grants.
Had compensation expense for the options granted been recorded based on the fair value at the grant date for the options, consistent with the provisions of SFAS 123, our net income and net income per common share for the year ended December 31, 2005 would have been decreased to the pro forma amounts indicated below (in thousands, except per share amounts):
| | | | | | | | | |
| | | | | | For the Year Ended
| |
| | | | | | December 31, 2005 | |
| |
| Net income attributed to common stockholders as reported: | | | | | | $ | 7,175 | |
| Less total stock based employee compensation expense determined under fair value based method for all awards net of tax related effects | | | | | | | (4,284 | ) |
| | | | | | | | | |
| Pro-forma net income attributed to common stockholders | | | | | | $ | 2,891 | |
| | | | | | | | | |
| Net income per common share: | | | | | | | | |
| Basic | | | As reported | | | $ | 0.48 | |
| | | | Pro forma | | | $ | 0.19 | |
| Diluted | | | As reported | | | $ | 0.44 | |
| | | | Pro forma | | | $ | 0.18 | |
Options were granted in 2007, 2006 and 2005. See Note 10 for further disclosures regarding stock options. The following assumptions were applied in determining the compensation costs:
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
| Expected dividend yield | | | — | | | | — | | | | — | |
| Expected price volatility | | | 66.21 | % | | | 72.28 | % | | | 84.28 | % |
| Risk-free interest rate | | | 4.8 | % | | | 5.1 | % | | | 5.6 | % |
| Expected life of options | | | 5 years | | | | 7 years | | | | 7 years | |
| Weighted average fair value of options granted at market value | | $ | 12.86 | | | $ | 10.58 | | | $ | 5.02 | |
Segments of an Enterprise and Related Information
We disclose the results of our segments in accordance with SFAS No. 131,Disclosures About Segments Of An Enterprise And Related Information(“SFAS No. 131”). We designate the internal organization that is used by management for allocating resources and assessing performance as the source of our reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers. Please see Note 14 for further disclosure of segment information in accordance with SFAS No. 131.
Income Per Common Share
We compute income per common share in accordance with the provisions of SFAS No. 128,Earnings Per Share(“SFAS No. 128”). SFAS No. 128 requires companies with complex capital structures to present
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ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
basic and diluted earnings per share. Basic earnings per share are computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is similar to basic earnings per share, but presents the dilutive effect on a per share basis of potential common shares (e.g., convertible preferred stock, stock options, etc.) as if they had been converted. Restricted stock grants are legally considered issued and outstanding, but are included in basic and diluted earnings per share only to the extent that they are vested. Unvested restricted stock is included in the computation of diluted earnings per share using the treasury stock method. Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase income per share) are excluded from diluted earnings per share.
The components of basic and diluted earnings per share are as follows (in thousands, except per share amounts):
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
| Numerator: | | | | | | | | | | | | |
| Net income | | $ | 50,440 | | | $ | 35,626 | | | $ | 7,175 | |
| | | | | | | | | | | | | |
| Denominator: | | | | | | | | | | | | |
| Weighted average common shares outstanding excluding nonvested restricted stock | | | 34,158 | | | | 20,548 | | | | 14,832 | |
| Effect of potentially dilutive common shares: | | | | | | | | | | | | |
| Warrants and employee and director stock options and restricted shares | | | 543 | | | | 862 | | | | 1,406 | |
| | | | | | | | | | | | | |
| Weighted average common shares outstanding and assumed conversions | | | 34,701 | | | | 21,410 | | | | 16,238 | |
| | | | | | | | | | | | | |
| Income per common share: | | | | | | | | | | | | |
| Basic | | $ | 1.48 | | | $ | 1.73 | | | $ | 0.48 | |
| | | | | | | | | | | | | |
| Diluted | | $ | 1.45 | | | $ | 1.66 | | | $ | 0.44 | |
| | | | | | | | | | | | | |
| Potentially dilutive securities excluded as anti-dilutive | | | 1,108 | | | | 53 | | | | 599 | |
| | | | | | | | | | | | | |
Reclassification
Certain prior period balances have been reclassified to conform to current year presentation.
New Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (“SFAS 157”). SFAS 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Subsequently, the FASB provided for a one-year deferral of the provisions of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements on a non-recurring basis. We believe that the adoption of SFAS 157 will not have a material impact on our financial position, results of operations or cash flows.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations (“SFAS 141(R)”). This statement retains the fundamental requirements in SFAS No. 141, “Business Combinations” that the acquisition method of accounting be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one or more other businesses or assets at
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ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
the acquisition date and in subsequent periods. This statement replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and any non-controlling interest. Additionally, SFAS 141(R) requires that acquisition-related costs, including restructuring costs, be recognized as expense separately from the acquisition. SFAS 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We will adopt SFAS 141(R) beginning January 1, 2009 and apply to future acquisitions.
In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at the initial recognition of the asset or liability or upon a re-measurement event that gives rise to the new-basis of accounting. All subsequent changes in fair value for that instrument are reported in earnings. SFAS 159 does not affect any existing accounting literature that requires certain assets and liabilities to be recorded at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS 159 is effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. We are currently evaluating the provisions of SFAS 159 and have not yet determined the impact, if any, on our financial statements.
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires (i) that non-controlling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the non-controlling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained non-controlling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. The presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We believe the adoption of SFAS 160 will not have a material impact on our financial position or results of operations.
| |
| NOTE 2 — | POST RETIREMENT BENEFIT OBLIGATIONS |
Medical And Life
Pursuant to the Plan of Reorganization that was confirmed by the Bankruptcy Court after acceptances by our creditors and stockholders and was consummated on December 2, 1988, we assumed the contractual obligation to Simplicity Manufacturing, Inc. (SMI) to reimburse SMI for 50% of the actual cost of medical and life insurance claims for a select group of retirees (SMI Retirees) of the prior Simplicity Manufacturing Division of Allis-Chalmers. The actuarial present value of the expected retiree benefit obligation is determined by an actuary and is the amount that results from applying actuarial assumptions to (1) historical claims-cost data, (2) estimates for the time value of money (through discounts for interest) and (3) the probability of payment (including decrements for death, disability, withdrawal, or retirement) between today and expected date of benefit payments. As of December 31, 2007 and 2006, we have post-retirement benefit obligations of $31,000 and $304,000, respectively.
401(k) Savings Plan
On June 30, 2003, we adopted the 401(k) Profit Sharing Plan (the “Plan”). The Plan is a defined contribution savings plan designed to provide retirement income to our eligible employees. The Plan is intended to be qualified under Section 401(k) of the Internal Revenue Code of 1986, as amended. It is funded by voluntary pre-tax contributions from eligible employees who may contribute a percentage of their eligible
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ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
compensation, limited and subject to statutory limits. The Plan is also funded by discretionary matching employer contributions from us. Eligible employees cannot participate in the Plan until they have attained the age of 21 and completed three-months of service with us. Each participant is 100% vested with respect to the participants’ contributions while our matching contributions are vested over a three-year period in accordance with the Plan document. Contributions are invested, as directed by the participant, in investment funds available under the Plan. Matching contributions of approximately $1.8 million, $735,000 and $114,000 were paid in 2007, 2006 and 2005, respectively.
| |
| NOTE 3 — | ACQUISITIONS AND SALE OF CAPILLARY ASSETS |
On April 1, 2005, we acquired 100% of the outstanding stock of Delta Rental Service, Inc., or Delta, for approximately $4.6 million in cash, 223,114 shares of our common stock and two promissory notes totaling $350,000. The purchase price was allocated to fixed assets and inventory. Delta, located in Lafayette, Louisiana, was a rental tool company providing specialty rental items to the oil and gas industry such as spiral heavy weight drill pipe, test plugs used to test blow-out preventors, well head retrieval tools, spacer spools and assorted handling tools. The results of Delta since the acquisition are included in our Rental Services segment.
On May 1, 2005, we acquired 100% of the outstanding capital stock of Capcoil Tubing Services, Inc., or Capcoil, for approximately $2.7 million in cash, 168,161 shares of our common stock and the payment or assumption of approximately $1.3 million of debt. Capcoil, located in Kilgore, Texas, is engaged in downhole well servicing by providing coil tubing services to enhance production from existing wells. Goodwill of $184,000 and other identifiable intangible assets of $1.4 million were recorded in connection with the acquisition. The results of Capcoil since the acquisition are included in our Production Services segment.
On July 11, 2005, we acquired the compressed air drilling assets of W.T Enterprises, Inc., or W.T., based in South Texas, for $6.0 million in cash. The equipment includes compressors, boosters, mist pumps and vehicles. Goodwill of $82,000 and other identifiable intangible assets of $1.5 million were recorded in connection with the acquisition. The results of the W.T. assets since their acquisition are included in our Underbalanced Drilling segment.
On July 11, 2005, we acquired from M-I L.L.C. (“M-I”) its 45% interest in AirComp and subordinated note in the principal amount of $4.8 million issued by AirComp, for which we paid M-I $7.1 million in cash and issued to M-I a $4.0 million subordinated note bearing interest at 5% per annum. As a result, we now own 100% of AirComp. The results of AirComp are included in our Underbalanced Drilling segment.
Effective August 1, 2005, we acquired 100% of the outstanding capital stock of Target Energy Inc., or Target, for approximately $1.3 million in cash and forgiveness of a lease receivable of approximately $0.6 million. The purchase price was allocated to the fixed assets of Target. The results of Target are included in our directional and horizontal drilling segment as their Measure While Drilling equipment is utilized in that segment.
On September 1, 2005, we acquired the casing and tubing service assets of Patterson Services, Inc. for approximately $15.6 million. These assets are located in Corpus Christi, Texas; Kilgore, Texas; Lafayette, Louisiana and Houma, Louisiana. The results of these assets since their acquisition are included in our Tubular Services segment.
Effective January 1, 2006, we acquired 100% of the outstanding stock of Specialty Rental Tools, Inc., or Specialty, for approximately $95.3 million in cash. In addition, approximately $588,000 of costs were incurred in relation to the Specialty acquisition. Specialty, located in Lafayette, Louisiana, was engaged in the rental of high quality drill pipe, heavy weight spiral drill pipe, tubing work strings, blow-out preventors, choke manifolds and various valves and handling tools for oil and natural gas drilling. The following table
64
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 7,645 | |
| Property and equipment | | | 90,622 | |
| | | | | |
| Total assets acquired | | | 98,267 | |
| | | | | |
| Current liabilities | | | 2,193 | |
| Long-term debt | | | 74 | |
| | | | | |
| Total liabilities assumed | | | 2,267 | |
| | | | | |
| Net assets acquired | | $ | 96,000 | |
| | | | | |
Specialty’s historical property and equipment values were increased by approximately $71.6 million based on third-party valuations. The results of Specialty since the acquisition are included in our Rental Services segment.
Effective April 1, 2006, we acquired 100% of the outstanding stock of Rogers Oil Tools, Inc., or Rogers, based in Lafayette, Louisiana, for a total consideration of approximately $13.7 million, which includes approximately $11.3 million in cash, $1.6 million in our common stock and a $750,000 three-year promissory note. In addition, approximately $380,000 of costs were incurred in relation to the Rogers acquisition. Rogers sells, services and rents power drill pipe tongs and accessories and rental tongs for snubbing and well control applications. Rogers also provides specialized tong operators for rental jobs. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 4,520 | |
| Property and equipment | | | 9,866 | |
| Intangible assets, including goodwill | | | 4,941 | |
| | | | | |
| Total assets acquired | | | 19,327 | |
| | | | | |
| Current liabilities | | | 1,376 | |
| Deferred income tax liabilities | | | 3,760 | |
| Other long-term liabilities | | | 150 | |
| | | | | |
| Total liabilities assumed | | | 5,286 | |
| | | | | |
| Net assets acquired | | $ | 14,041 | |
| | | | | |
Rogers’ historical property and equipment values were increased by approximately $8.4 million based on third-party valuations. Intangible assets include approximately $2.4 million assigned to goodwill, $1.2 million assigned to patents, $1.1 million assigned to customer list and $150,000 assigned to non-compete based on third-party valuations and employment contracts. The amortizable intangibles have a weighted-average useful life of 10.5 years. The results of Rogers since the acquisition are included in our Tubular Services segment.
Effective August 14, 2006, we acquired 100% of the outstanding stock of DLS, based in Argentina, for a total consideration of approximately $114.5 million, which includes approximately $93.7 million in cash, $38.1 million in our common stock, less approximately $17.3 million of debt assigned to us. In addition, approximately $3.4 million of costs were incurred in relation to the DLS acquisition. DLS operates a fleet of 51 rigs, including 20 drilling rigs, 18 workover rigs and 12 pulling rigs in Argentina and one drilling rig in
65
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Bolivia. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 52,033 | |
| Property and equipment | | | 130,389 | |
| Other long-term assets | | | 21 | |
| | | | | |
| Total assets acquired | | | 182,443 | |
| | | | | |
| Current liabilities | | | 34,386 | |
| Long-term debt, less current portion | | | 5,921 | |
| Intercompany note | | | 17,256 | |
| Deferred tax liabilities | | | 6,948 | |
| | | | | |
| Total liabilities assumed | | | 64,511 | |
| | | | | |
| Net assets acquired | | $ | 117,932 | |
| | | | | |
DLS’ historical property and equipment values were increased by approximately $22.7 million based on third-party valuations. The results of DLS since the acquisition are included in our International Drilling segment.
On October 16, 2006, we acquired 100% of the outstanding stock of Petro Rental, based in Lafayette, Louisiana, for a total consideration of approximately $33.6 million, which includes approximately $20.2 million in cash, $3.8 million in our common stock and repaid $9.6 million of existing Petro Rental debt. In addition, approximately $82,000 of costs were incurred in relation to the Petro-Rental acquisition. Petro-Rental provides a variety of production-related rental tools and equipment and services, including wire line services and equipment, land and offshore pumping services and coiled tubing. The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 8,175 | |
| Property and equipment | | | 28,792 | |
| Intangible assets, including goodwill | | | 5,811 | |
| Other long-term assets | | | 2 | |
| | | | | |
| Total assets acquired | | | 42,780 | |
| | | | | |
| Current liabilities | | | 2,135 | |
| Deferred tax liabilities | | | 6,954 | |
| | | | | |
| Total liabilities assumed | | | 9,089 | |
| | | | | |
| Net assets acquired | | $ | 33,691 | |
| | | | | |
Petro Rental’s historical property and equipment values were increased by approximately $13.4 million based on third-party valuations. Intangible assets include approximately $3.6 million assigned to goodwill and $2.2 million assigned to customer relationships based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10 years. The results of Petro-Rental since the acquisition are included in our Production Services segment.
Effective December 1, 2006, we acquired 100% of the outstanding stock of Tanus, based in Argentina, for a total consideration of $2.5 million. In addition, approximately $17,000 of costs were incurred in relation to the Tanus acquisition. Tanus is engaged in the research and manufacturing of additives for the oil, natural gas and water well drilling and completion fluids in Argentina. The following table summarizes the allocation
66
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands).
| | | | | |
| Current assets | | $ | 2,254 | |
| Property and equipment | | | 2 | |
| Goodwill | | | 1,504 | |
| | | | | |
| Total assets acquired | | | 3,760 | |
| Current liabilities | | | 1,243 | |
| | | | | |
| Net assets acquired | | $ | 2,517 | |
| | | | | |
The results of Tanus are reported with DLS under our International Drilling segment.
On December 18, 2006, we acquired substantially all of the assets of Oil & Gas Rental Services, Inc, or OGR, based in Morgan City, Louisiana, for a total consideration of approximately $342.4 million, which includes approximately $291.0 million in cash, and $51.4 million in our common stock. In addition, approximately $3.0 million of costs were incurred in relation to the acquisition of the assets of OGR The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 12,735 | |
| Property and equipment | | | 199,015 | |
| Investments | | | 4,618 | |
| Intangible assets, including goodwill | | | 128,976 | |
| | | | | |
| Total assets acquired | | $ | 345,344 | |
| | | | | |
OGR’s historical property and equipment values were increased by approximately $168.9 million based on third-party valuations. Intangible assets include approximately $106.1 million assigned to goodwill, $22.0 million to customer relations, $831,000 to patents and $35,000 assigned to employment agreements based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 10.1 years. The results of the OGR assets since their acquisition are included in our Rental Services segment.
On June 29 2007, we acquired Coker Directional, Inc., or Coker, for a total consideration of approximately $3.9 million, which includes approximately $3.6 million in cash and a promissory note for $350,000. In addition, approximately $5,000 of costs were incurred in relation to the Coker acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed at the date of the acquisition (in thousands):
| | | | | |
| Property and equipment | | | 3 | |
| Intangible assets, including goodwill | | | 3,902 | |
| | | | | |
| Net assets acquired | | $ | 3,905 | |
| | | | | |
Intangible assets include approximately $1.8 million assigned to goodwill and $2.1 million assigned to customer relationships and non-compete. The amortizable intangibles have a weighted-average useful life of 9.4 years. The results of Coker since the acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.
On July 26, 2007, we acquired Diggar Tools, LLC, or Diggar, for a total consideration of approximately $10.3 million, which includes approximately $6.7 million in cash, a promissory note for $750,000 and payment of approximately $2.8 million of existing Diggar debt. In addition, approximately $29,000 of costs were incurred in relation to the Diggar acquisition. The following table summarizes the preliminary allocation
67
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 1,113 | |
| Property and equipment | | | 7,204 | |
| Intangible assets, including goodwill | | | 2,675 | |
| | | | | |
| Total assets acquired | | | 10,992 | |
| | | | | |
| Current liabilities | | | 622 | |
| | | | | |
| Net assets acquired | | $ | 10,370 | |
| | | | | |
Diggar’s historical property and equipment values were increased by approximately $3.4 million based on third-party valuations. Intangible assets include approximately $2.7 million assigned to goodwill. The results of Diggar since the acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.
On October 23, 2007, we acquired Rebel for a total consideration of approximately $7.3 million, which includes approximately $5.0 million in cash, promissory notes for an aggregate of $500,000, payment of approximately $1.5 million of existing Rebel debt and the deposit of $305,000 in escrow to cover distributions owed under the Rebel Defined Benefit Pension Plan & Trust. In addition, approximately $214,000 of costs were incurred in relation to the Rebel acquisition. The following table summarizes the preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 944 | |
| Land, Property and equipment | | | 8,736 | |
| Intangible assets, including goodwill | | | 1,144 | |
| | | | | |
| Total assets acquired | | | 10,824 | |
| | | | | |
| Current liabilities | | | 218 | |
| Deferred tax liabilities | | | 3,095 | |
| | | | | |
| Total liabilities assumed | | | 3,313 | |
| | | | | |
| Net assets acquired | | $ | 7,511 | |
| | | | | |
Rebel’s historical property and equipment values were increased by approximately $8.5 million based on third-party valuations. Intangible assets include approximately $461,000 assigned to goodwill and $683,000 assigned to customer relations. The amortizable intangibles have a useful life of 15 years. The results of Rebel since the acquisition are included in our Tubular services segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.
On November 1, 2007, we acquired substantially all the assets Diamondback Oilfield Services, Inc. or Diamondback, for a total consideration of approximately $23.1 million in cash. Approximately $89,000 of costs were incurred in relation to the Diamondback acquisition. The following table summarizes the
68
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
preliminary allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired at the date of acquisition (in thousands):
| | | | | |
| Current assets | | $ | 3,350 | |
| Property and equipment | | | 8,701 | |
| Intangible assets, including goodwill | | | 12,232 | |
| Other noncurrent assets | | | 10 | |
| | | | | |
| Total assets acquired | | | 24,293 | |
| | | | | |
| Current liabilities | | | 1,160 | |
| | | | | |
| Net assets acquired | | $ | 23,133 | |
| | | | | |
Diamondback’s historical property and equipment values were increased by approximately $2.0 million based on third-party valuations. Intangible assets include approximately $7.6 million assigned to goodwill, $650,000 assigned to non-compete, $620,000 assigned to trade name and $3.4 million assigned to customer relations based on third-party valuations. The amortizable intangibles have a weighted-average useful life of 13.3 years. The sellers are entitled to a future cash earn-out payment upon the business attaining certain earning objectives. The results of the Diamondback assets since their acquisition are included in our Directional Drilling segment. We do not expect any material differences from the preliminary allocation of the purchase price and the final purchase price allocations.
The acquisitions were accounted for using the purchase method of accounting. The results of operations of the acquired entities since the date of acquisition are included in our consolidated income statement.
On June 29, 2007, we sold our capillary tubing units and related equipment for approximately $16.3 million. We reported a gain of approximately $8.9 million. The assets sold represented a small portion of our Production Services segment.
The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2006 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Rogers, DLS, Petro-Rental and OGR as if the acquisitions occurred as of January 1, 2006, based on the historical results of the acquisitions. The following unaudited pro forma consolidated summary financial information for the year ended December 31, 2005 illustrates the effects of the acquisitions and the related public offerings of debt and equity for Delta, Capcoil, W.T., the minority interest in AirComp, Specialty, Rogers, DLS, Petro-Rental and OGR as if the acquisitions had occurred as of January 1, 2005, based on the historical results of the acquisitions. The historical results for OGR are based on their historical year end of October 31 (in thousands, except per share amounts):
| | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2006 | | | 2005 | |
| |
| Revenues | | $ | 502,418 | | | $ | 346,230 | |
| Operating income | | $ | 93,082 | | | $ | 49,868 | |
| Net income | | $ | 32,358 | | | $ | 1,264 | |
| Net income per common share | | | | | | | | |
| Basic | | $ | 0.96 | | | $ | 0.04 | |
| Diluted | | $ | 0.94 | | | $ | 0.04 | |
69
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Inventories are comprised of the following as of December 31 (in thousands):
| | | | | | | | | |
| | | 2007 | | | 2006 | |
| |
| Manufactured | | | | | | | | |
| Finished goods | | $ | 2,198 | | | $ | 1,476 | |
| Work in process | | | 1,781 | | | | 2,266 | |
| Raw materials | | | 4,464 | | | | 2,638 | |
| | | | | | | | | |
| Total manufactured | | | 8,443 | | | | 6,380 | |
| Hammers | | | 1,434 | | | | 1,016 | |
| Drive pipe | | | 420 | | | | 716 | |
| Rental supplies | | | 2,261 | | | | 1,845 | |
| Chemicals and drilling fluids | | | 3,236 | | | | 2,673 | |
| Rig parts and related inventory | | | 9,985 | | | | 9,762 | |
| Coiled tubing and related inventory | | | 1,014 | | | | 1,627 | |
| Shop supplies and related inventory | | | 5,416 | | | | 4,596 | |
| | | | | | | | | |
| Total inventories | | $ | 32,209 | | | $ | 28,615 | |
| | | | | | | | | |
| |
| NOTE 5 — | PROPERTY AND OTHER INTANGIBLE ASSETS |
Property and equipment is comprised of the following as of December 31 (in thousands):
| | | | | | | | | | | |
| | | Depreciation
| | | | | | |
| | | Period | | 2007 | | | 2006 | |
| |
| Land | | — | | $ | 2,040 | | | $ | 1,810 | |
| Building and improvements | | 15-20 years | | | 6,986 | | | | 5,392 | |
| Transportation equipment | | 3-10 years | | | 26,132 | | | | 22,744 | |
| Drill pipe and rental equipment | | 3-20 years | | | 350,202 | | | | 321,821 | |
| Drilling, workover and pulling rigs | | 20 years | | | 127,725 | | | | 120,517 | |
| Machinery and equipment | | 3-20 years | | | 157,626 | | | | 105,926 | |
| Furniture, computers, software and leasehold improvements | | 3-10 years | | | 5,817 | | | | 3,522 | |
| Construction in progress — equipment | | N/A | | | 27,148 | | | | 2,269 | |
| | | | | | | | | | | |
| Total | | | | | 703,676 | | | | 584,001 | |
| Less: accumulated depreciation | | | | | (77,008 | ) | | | (29,743 | ) |
| | | | | | | | | | | |
| Property and equipment, net | | | | $ | 626,668 | | | $ | 554,258 | |
| | | | | | | | | | | |
The net book value of equipment recorded under capital leases was $285,000 and $1.0 million as of December 31, 2007 and 2006, respectively.
70
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Other intangible assets are as follows as of December 31 (in thousands):
| | | | | | | | | | | |
| | | Amortization
| | | | | | |
| | | Period | | 2007 | | | 2006 | |
| |
| Intellectual property | | 10-20 years | | $ | 1,629 | | | $ | 1,009 | |
| Non-compete agreements | | 3-5 years | | | 2,852 | | | | 4,580 | |
| Customer relationships | | 10-15 years | | | 33,528 | | | | 27,552 | |
| Patents | | 12-15 years | | | 2,560 | | | | 3,327 | |
| Other intangible assets | | 2-10 years | | | 829 | | | | 847 | |
| | | | | | | | | | | |
| Total | | | | | 41,398 | | | | 37,315 | |
| Less: accumulated amortization | | | | | (6,218 | ) | | | (4,475 | ) |
| | | | | | | | | | | |
| Other intangibles assets, net | | | | $ | 35,180 | | | $ | 32,840 | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 2007 | | | 2006 | |
| | | Gross
| | | Accumulated
| | | Gross
| | | Accumulated
| |
| | | Value | | | Amortization | | | Value | | | Amortization | |
| |
| Intellectual property | | $ | 1,629 | | | $ | 410 | | | $ | 1,009 | | | $ | 349 | |
| Non-compete agreements | | | 2,852 | | | | 1,367 | | | | 4,580 | | | | 2,707 | |
| Customer relationships | | | 33,528 | | | | 3,497 | | | | 27,552 | | | | 789 | |
| Patents | | | 2,560 | | | | 423 | | | | 3,327 | | | | 203 | |
| Other intangible assets | | | 829 | | | | 521 | | | | 847 | | | | 427 | |
| | | | | | | | | | | | | | | | | |
| Total | | $ | 41,398 | | | $ | 6,218 | | | $ | 37,315 | | | $ | 4,475 | |
| | | | | | | | | | | | | | | | | |
Amortization expense related to other intangibles was $4.1 million, $1.9 million and $1.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. Future amortization of intangible assets at December 31, 2007 is as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | |
| | | Intangible Amortization by Period | |
| | | Years Ended December 31, | |
| | | | | | | | | | | | | | | 2012 and
| |
| | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | Thereafter | |
| |
| Intellectual property | | $ | 96 | | | $ | 96 | | | $ | 96 | | | $ | 96 | | | $ | 835 | |
| Non-compete agreements | | | 627 | | | | 494 | | | | 291 | | | | 48 | | | | 25 | |
| Customer relationships | | | 3,227 | | | | 3,227 | | | | 3,227 | | | | 3,227 | | | | 17,123 | |
| Patents | | | 202 | | | | 202 | | | | 202 | | | | 202 | | | | 1,329 | |
| Other intangible assets | | | 107 | | | | 90 | | | | 79 | | | | 30 | | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Intangible Amortization | | $ | 4,259 | | | $ | 4,109 | | | $ | 3,895 | | | $ | 3,603 | | | $ | 19,314 | |
| | | | | | | | | | | | | | | | | | | | | |
We had income before income taxes of $41.7 million, $35.9 million and $8.5 million for U.S. tax purposes for the years ended December 31, 2007, 2006 and 2005, respectively. We also had income before income taxes of $37.6 million and $11.1 million reported innon-U.S. countries for the years ended December 31, 2007 and 2006, respectively. We treat the withholding taxes incurred by our U.S. subsidiaries in foreign countries as foreign tax, and we anticipate using those tax payments to offset U.S. tax.
71
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
The income tax provision consists of the following (in thousands):
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
| Current income tax expense: | | | | | | | | | | | | |
| Federal | | $ | 6,814 | | | $ | 5,865 | | | $ | 123 | |
| State | | | 1,053 | | | | 898 | | | | 595 | |
| Foreign | | | 12,959 | | | | 2,442 | | | | 626 | |
| | | | | | | | | | | | | |
| | | | 20,826 | | | | 9,205 | | | | 1,344 | |
| Deferred income tax expense (benefit): | | | | | | | | | | | | |
| Federal | | | 7,081 | | | | (946 | ) | | | — | |
| State | | | 349 | | | | 573 | | | | — | |
| Foreign | | | 587 | | | | 2,588 | | | | — | |
| | | | | | | | | | | | | |
| | | | 8,017 | | | | 2,215 | | | | — | |
| | | | | | | | | | | | | |
| | | $ | 28,843 | | | $ | 11,420 | | | $ | 1,344 | |
| | | | | | | | | | | | | |
We are required to file a consolidated U.S. federal income tax return. We pay foreign income taxes in Argentina related to our International Drilling’s operations and in Mexico related to Tubular’s revenues from Matyep.
The following table reconciles the U.S. statutory tax rate to our actual tax rate:
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
| Statutory income tax rate | | | 35.0 | % | | | 35.0 | % | | | 34.0 | % |
| State taxes, net of federal benefit | | | 1.8 | | | | 2.1 | | | | 6.1 | |
| Valuation allowances | | | — | | | | (57.7 | ) | | | (98.7 | ) |
| Nondeductible items, permanent differences and other | | | (0.4 | ) | | | 44.9 | | | | 74.4 | |
| | | | | | | | | | | | | |
| Effective tax rate | | | 36.4 | % | | | 24.3 | % | | | 15.8 | % |
| | | | | | | | | | | | | |
Significant components of deferred income tax assets as of December 31, were as follows (in thousands):
| | | | | | | | | |
| | | 2007 | | | 2006 | |
| |
| Deferred income tax assets: | | | | | | | | |
| Net future (taxable) deductible items | | $ | 874 | | | $ | 899 | |
| Share-based compensation | | | 1,898 | | | | 578 | |
| Net operating loss carryforwards | | | 2,681 | | | | 1,698 | |
| Foreign tax credits | | | — | | | | 2,420 | |
| A-C Reorganization Trust and Product Liability Trust | | | 4,099 | | | | 5,500 | |
| | | | | | | | | |
| Total deferred income tax assets | | | 9,552 | | | | 11,095 | |
| Deferred income tax liabilities | | | | | | | | |
| Depreciation and amortization | | | (37,795 | ) | | | (28,226 | ) |
| | | | | | | | | |
| Net deferred income tax liabilities | | $ | (28,243 | ) | | $ | (17,131 | ) |
| | | | | | | | | |
| Net current deferred income tax asset | | $ | 1,847 | | | $ | 2,822 | |
| Net noncurrent deferred income tax liability | | | (30,090 | ) | | | (19,953 | ) |
| | | | | | | | | |
| Net deferred income tax liabilities | | $ | (28,243 | ) | | $ | (17,131 | ) |
| | | | | | | | | |
72
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Net future tax-deductible items relate primarily to timing differences. Timing differences are differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that will result in differences between income for tax purposes and income for financial statement purposes in future years.
The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss and tax credit carry forwards if there has been a “change of ownership” as described in Section 382 of the Internal Revenue Code. Such a change of ownership may limit our utilization of our net operating loss and tax credit carryforwards, and could be triggered by a public offering or by subsequent sales of securities by us or our stockholders. This provision has limited the amount of net operating losses available to us currently. Net operating loss carryforwards for tax purposes at December 31, 2007 and 2006 were $7.7 million and $4.9 million, respectively, expiring through 2024.
Prior to 2006, we did not record an asset for the U.S. foreign tax credits as we believed they would not be recoverable based on our taxable income. We now project that all of the U.S. foreign tax credits will be utilized against U.S. income tax.
Our 1988 Plan of Reorganization established the A-C Reorganization Trust to settle claims and to make distributions to creditors and certain stockholders. We transferred cash and certain other property to the A-C Reorganization Trust on December 2, 1988. Payments made by us to the A-C Reorganization Trust did not generate tax deductions for us upon the transfer but generate deductions for us as the A-C Reorganization Trust makes payments to holders of claims and for administrative expenses. The Plan of Reorganization also created a trust to process and liquidate product liability claims. Payments made by the A-C Reorganization Trust to the Product Liability Trust did not generate current tax deductions for us upon the payment but generates deductions for us as the Product Liability Trust makes payments to liquidate claims or incurs administrative expenses. We believe the aforementioned trusts are grantor trusts and therefore we include the income or loss of these trusts in our income or loss for tax purposes. The income or loss of these trusts is not included in our results of operations for financial reporting purposes.
A valuation allowance is established for deferred tax assets when management, based upon available information, considers it more likely than not that a benefit from such assets will not be realized. As of December 31, 2007 and 2006, the valuation allowance was zero.
Approximately $9.7 million and $5.5 million of ad valorem, franchise, income, sales and other tax accruals are included in our accrued expense balances of $20.5 million and $17.0 million as of December 31, 2007 and 2006, respectively.
We adopted the provisions of FIN 48 on January 1, 2007. This interpretation clarifies the accounting for uncertain tax positions and requires companies to recognize the impact of a tax position in their financial statements, if that position is more likely than not of being sustained on audit, based on the technical merits of the position. The adoption of FIN 48 did not have any impact on the total liabilities or stockholders’ equity.
73
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
Our long-term debt consists of the following as of December 31 (in thousands):
| | | | | | | | | |
| | | 2007 | | | 2006 | |
| |
| Senior notes | | $ | 505,000 | | | $ | 255,000 | |
| Bridge loan | | | — | | | | 300,000 | |
| Bank term loans | | | 4,926 | | | | 7,302 | |
| Revolving line of credit | | | — | | | | — | |
| Seller notes | | | 2,350 | | | | 900 | |
| Notes payable to former directors | | | 32 | | | | 32 | |
| Equipment & vehicle installment notes | | | 595 | | | | 3,502 | |
| Insurance premium financing notes | | | 1,707 | | | | 1,025 | |
| Obligations under non-compete agreements | | | 110 | | | | 270 | |
| Capital lease obligations | | | 14 | | | | 414 | |
| | | | | | | | | |
| Total debt | | | 514,734 | | | | 568,445 | |
| Less: current maturities of long-term debt | | | 6,434 | | | | 6,999 | |
| | | | | | | | | |
| Long-term debt | | $ | 508,300 | | | $ | 561,446 | |
| | | | | | | | | |
Our weighted average interest rate for all of our outstanding debt was approximately 8.7% as of December 31, 2007 and 9.8% as of December 31, 2006.
Maturities of debt obligations as of December 31, 2007 are as follows (in thousands):
| | | | | | | | | | | | | |
| | | Debt | | | Capital Leases | | | Total | |
| |
| Year Ending: | | | | | | | | | | | | |
| December 31, 2008 | | $ | 6,420 | | | $ | 14 | | | $ | 6,434 | |
| December 31, 2009 | | | 2,250 | | | | — | | | | 2,250 | |
| December 31, 2010 | | | 700 | | | | — | | | | 700 | |
| December 31, 2011 | | | 350 | | | | — | | | | 350 | |
| December 31, 2012 | | | — | | | | — | | | | — | |
| Thereafter | | | 505,000 | | | | — | | | | 505,000 | |
| | | | | | | | | | | | | |
| Total | | $ | 514,720 | | | $ | 14 | | | $ | 514,734 | |
| | | | | | | | | | | | | |
Senior notes, bank loans and line of credit agreements
On January 18, 2006 and August 14, 2006, we closed on private offerings, to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, of $160.0 and $95.0 million aggregate principal amount of our senior notes, respectively. The senior notes are due January 15, 2014 and bear interest at 9.0%. The proceeds were used to fund the acquisitions of Specialty and DLS, to repay existing debt and for general corporate purposes.
In January 2007, we closed on a private offering, to qualified institutional buyers pursuant to Rule 144A under the Securities Act, of $250.0 million principal amount of 8.5% senior notes due 2017. The proceeds of the senior notes offering, together with a portion of the proceeds of our concurrent common stock offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility which we incurred to finance our acquisition of substantially all the assets of OGR.
74
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
On December 18, 2006, we closed on a $300.0 million senior unsecured bridge loan. The bridge loan was due 18 months after closing and had a weighted average interest rate of 10.6%. The bridge loan, which was repaid on January 29, 2007, was used to fund the acquisition of OGR.
On January 18, 2006, we also executed an amended and restated credit agreement which provided for a $25.0 million revolving line of credit with a maturity of January 2010. Our January 2006 amended and restated credit agreement contained customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the January 2006 amended and restated credit agreement are secured by substantially all of our assets excluding the DLS assets, but including2/3 of our shares of DLS. On April 26, 2007, we entered into a Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $62.0 million, and had a final maturity date of April 26, 2012. On December 3, 2007, we entered into a First Amendment to Second Amended and Restated Credit Agreement, which increased our revolving line of credit to $90.0 million. The amended and restated credit agreement contains customary events of default and financial covenants and limits our ability to incur additional indebtedness, make capital expenditures, pay dividends or make other distributions, create liens and sell assets. Our obligations under the amended and restated credit agreement are secured by substantially all of our assets located in the United States. As of December 31, 2007 and 2006, no amounts were borrowed on the facility but availability is reduced by outstanding letters of credit of $8.4 million and $9.7 million, respectively.
As part of our acquisition of DLS, we assumed various bank loans with floating interest rates based on LIBOR plus a margin and terms ranging from 2 to 5 years. The weighted average interest rates on these loans was 6.7% and 7.0% as of December 31, 2007 and 2006, respectively. The bank loans are denominated in U.S. dollars and the outstanding amount due as of December 31, 2007 and 2006 was $4.9 million and $7.3 million, respectively.
Notes payable
As part of the acquisition of Mountain Compressed Air, Inc., or MCA, in 2001, we issued a note to the sellers of MCA in the original amount of $2.2 million accruing interest at a rate of 5.75% per annum. The note was reduced to $1.5 million as a result of the settlement of a legal action against the sellers in 2003. In March 2005, we reached an agreement with the sellers and holders of the note as a result of an action brought against us by the sellers. Under the terms of the agreement, we paid the holders of the note $1.0 million in cash, and agreed to pay an additional $350,000 on June 1, 2006, and an additional $150,000 on June 1, 2007, in settlement of all claims. As of December 31, 2007 and 2006 the outstanding amounts due were $0 and $150,000, respectively.
In connection with the acquisition of Rogers, we issued to the seller a note in the amount of $750,000. The note bears interest at 5.0% and is due April 3, 2009. In connection with the purchase of Coker, we issued to the seller a note in the amount of $350,000. The note bears interest at 8.25% and is due June, 29, 2008. In connection with the purchase of Diggar, we issued to the seller a note in the amount of $750,000. The note bears interest at 6.0% and is due July 26, 2008. In connection with the purchase of Rebel, we issued to the sellers notes in the amount of $500,000. The notes bear interest at 5.0% and are due October 23, 2008
In 2000 we compensated directors, including current directors Nederlander and Toboroff, who served on the board of directors from 1989 to March 31, 1999 without compensation, by issuing promissory notes totaling $325,000. The notes bear interest at the rate of 5.0%. As of December 31, 2007 and 2006, the principal and accrued interest on these notes totaled approximately $32,000.
We have various rig and equipment financing loans with interest rates ranging from 7.8% to 8.7% and terms of 2 to 5 years. As of December 31, 2007 and 2006, the outstanding balances for rig and equipment financing loans were $595,000 and $3.5 million, respectively.
75
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
In April 2006 and August 2006, we obtained insurance premium financings in the amount of $1.9 million and $896,000 with fixed interest rates of 5.6% and 6.0%, respectively. Under terms of the agreements, amounts outstanding are paid over 10 month and 11 month repayment schedules. The outstanding balance of these notes was approximately $1.0 million as of December 31, 2006. In April 2007 and August 2007, we obtained insurance premium financings in the amount of $3.2 million and $1.3 with fixed interest rates of 5.9% and 5.7%, respectively. Under terms of the agreements, amounts outstanding are paid over 11 month repayment schedules. The outstanding balance of these notes was approximately $1.7 million as of December 31, 2007.
Other debt
In connection with the purchase of Tubular, we agreed to pay a total of $1.2 million to the seller in exchange for a non-compete agreement. Monthly payments of $20,576 were due under this agreement through January 31, 2007. In connection with the purchase of Safco-Oil Field Products, Inc., or Safco, we also agreed to pay a total of $150,000 to the sellers in exchange for a non-compete agreement. We were required to make annual payments of $50,000 through September 30, 2007. In connection with the purchase of Capcoil, we agreed to pay a total of $500,000 to two management employees in exchange for non-compete agreements. We are required to make annual payments of $110,000 through May 2008. Total amounts due under these non-compete agreements as of December 31, 2007 and 2006 were $110,000 and $270,000, respectively.
We also have various capital leases with terms that expire in 2008. As of December 31, 2007 and 2006, amounts outstanding under capital leases were $14,000 and $414,000, respectively.
| |
| NOTE 8 — | COMMITMENTS AND CONTINGENCIES |
We have placed orders for capital equipment totaling $82.7 million to be received and paid for through 2008. Approximately $46.2 million is for drilling and service rigs for our International Drilling segment, $26.0 million is for six new coiled tubing units and related equipment for our Production Services segment, $5.3 million is for rental equipment, principally drill pipe, for our Rental Services segment and $5.2 million is for casing and tubing tools and equipment. The orders are subject to cancellation with minimal loss of prior cash deposits, if any.
We rent office space and certain other facilities and shop yards for equipment storage and maintenance. Facility rent expense for the years ended December 31, 2007, 2006 and 2005 was $2.7 million, $1.6 million and $987,000, respectively.
At December 31, 2007, future minimum rental commitments for all operating leases are as follows (in thousands):
| | | | | |
| Years Ending: | | | | |
| December 31, 2008 | | $ | 2,618 | |
| December 31, 2009 | | | 1,633 | |
| December 31, 2010 | | | 721 | |
| December 31, 2011 | | | 437 | |
| December 31, 2012 | | | 156 | |
| Thereafter | | | 376 | |
| | | | | |
| Total | | $ | 5,941 | |
| | | | | |
| |
| NOTE 9 — | STOCKHOLDERS’ EQUITY |
As of January 1, 2005, in relation to the acquisition of Downhole Injection Services, LLC, or Downhole, we executed a business development agreement with CTTV Investments LLC, an affiliate of ChevronTexaco Inc., whereby we issued 20,000 shares of our common stock to CTTV and further agreed to issue up to an
76
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
additional 60,000 shares to CTTV contingent upon our subsidiaries receiving certain levels of revenues in 2005 from ChevronTexaco and its affiliates. CTTV was a minority owner of Downhole, which we acquired in 2004. Based on the terms of the agreement, no additional shares have been issued.
During 2005, we issued 223,114 and 168,161 shares of our common stock in relation to the Delta and Capcoil acquisitions, respectively (see Note 3).
In August 2005, our stockholders approved an amendment to our certificate of incorporation to increase the authorized number of shares of our common stock from 20 million to 100 million and to increase our authorized preferred stock from 10 million shares to 25 million shares and, we completed a secondary public offering in which we sold 1,761,034 shares for approximately $15.5 million, net of expenses.
We also had options and warrants exercised during 2005. Those exercises resulted in 1,076,154 shares of our common stock being issued for approximately $1.4 million.
During 2006, we issued 125,285, 2.5 million, 246,761 and 3.2 million shares of our common stock in relation to the Rogers, DLS, Petro Rental and OGR asset acquisitions, respectively (see Note 3).
On August 14, 2006 we closed on a public offering of 3,450,000 shares of our common stock at a public offering price of $14.50 per share. Net proceeds from the public offering of approximately $46.3 million were used to fund a portion of our acquisition of DLS.
During 2006, we had options and warrants exercised in 2006, which resulted in 1,851,377 shares of our common stock being issued for approximately $6.3 million. We recognized approximately $3.4 million of compensation expense related to stock options in 2006 that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $6.4 million of tax benefit related to our stock compensation plans.
In January 2007 we closed on a public offering of 6.0 million shares of our common stock at a public offering price of $17.65 per share. Net proceeds from the public offering, together with the proceeds of our concurrent senior notes offering, were used to repay the debt outstanding under our $300.0 million bridge loan facility, which we incurred to finance the OGR acquisition and for general corporate purposes.
We also had restricted stock award grants, and options and warrants exercised during 2007, which resulted in 882,624 shares of our common stock being issued for approximately $3.3 million. We recognized approximately $4.9 million of compensation expense related to share based payments that was recorded as capital in excess of par value (see Note 1). We also recorded approximately $1.7 million of tax benefit related to our stock compensation plans.
In 2000, we issued stock options and promissory notes to certain current and former directors as compensation for services as directors (See Note 7), and our Board of Directors granted stock options to these same individuals. Options to purchase 4,800 shares of our common stock were granted with an exercise price of $13.75 per share. These options vested immediately and may be exercised any time prior to March 28, 2010. As of December 31, 2007, 4,000 of the stock options remain outstanding. No compensation expense has been recorded for these options that were issued with an exercise price equal to the fair value of the common stock at the date of grant.
On May 31, 2001, the Board granted to Leonard Toboroff, one of our directors, an option to purchase 100,000 shares of our common stock at $2.50 per share, exercisable for 10 years from October 15, 2001. The option was granted for services provided by Mr. Toboroff to Oil Quip Rentals, Inc., or Oil Quip, prior to the merger, including providing financial advisory services, assisting in Oil Quip’s capital structure and assisting Oil Quip in finding strategic acquisition opportunities. We recorded compensation expense of $500,000 for the issuance of the option for the year ended December 31, 2001. As of December 31, 2007, all of the stock options have been exercised.
77
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
The 2003 Incentive Stock Plan (“2003 Plan”), as amended, permits us to grant to our key employees and outside directors various forms of stock incentives, including, among others, incentive and non-qualified stock options and restricted stock. The 2003 Plan is administered by the Compensation Committee of the Board, which consists of two or more directors appointed by the Board. The following benefits may be granted under the 2003 Plan: (a) stock appreciation rights; (b) restricted stock; (c) performance awards; (d) incentive stock options; (e) nonqualified stock options; and (f) other stock-based awards. Stock incentive terms are not to be in excess of ten years. The maximum number of shares that may be issued under the 2003 Plan shall be the lesser of 3,000,000 shares and 15% of the total number of shares of common stock outstanding.
The 2006 Incentive Plan (“2006 Plan”), was approved by our stockholders in November 2006. The 2006 Plan is administered by the Compensation Committee of the Board, which consists of two or more directors appointed by the Board. The maximum number of shares of the Company’s common stock, par value $0.01 per share (“Common Stock”), that may be issued under the 2006 Plan is equal to 1,500,000 shares, subject to adjustment in the event of stock splits and certain other corporate events. The 2006 Plan provides for the grant of any or all of the following types of awards: (i) stock options, including incentive stock options and non-qualified stock options; (ii) bonus stock; (iii) restricted stock awards; (iv) performance awards; and (v) other stock-based awards. Except with respect to awards of incentive stock options, all employees, consultants and non-employee directors of the Company and its affiliates are eligible to participate in the 2006 Plan. The term of each Award shall be for such period as may be determined by the Committee; provided, that in no event shall the term of any Award exceed a period of ten (10) years from the date of its grant.
A summary of our stock option activity and related information is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2007 | | | December 31, 2006 | | | December 31, 2005 | |
| | | Shares
| | | Weighted Ave.
| | | Shares
| | | Weighted Ave.
| | | Shares
| | | Weighted Avg.
| |
| | | Under
| | | Exercise
| | | Under
| | | Exercise
| | | Under
| | | Exercise
| |
| | | Option | | | Price | | | Option | | | Price | | | Option | | | Price | |
| |
| Beginning balance | | | 1,350,365 | | | $ | 6.88 | | | | 2,860,867 | | | $ | 5.10 | | | | 1,215,000 | | | $ | 3.20 | |
| Granted | | | 220,000 | | | | 21.83 | | | | 15,000 | | | | 14.74 | | | | 1,695,000 | | | | 6.44 | |
| Canceled | | | (17,334 | ) | | | 8.45 | | | | (54,567 | ) | | | 5.97 | | | | (15,300 | ) | | | 3.33 | |
| Exercised | | | (566,268 | ) | | | 5.86 | | | | (1,470,935 | ) | | | 3.54 | | | | (33,833 | ) | | | 2.80 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Ending balance | | | 986,763 | | | $ | 10.77 | | | | 1,350,365 | | | $ | 6.88 | | | | 2,860,867 | | | $ | 5.10 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
The total intrinsic value of stock options (the amount by which the market price of the underlying stock on the date of exercise exceeds the exercise price of the option) exercised was approximately $6.6 million, $18.8 million and $343,000 during the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, there was approximately $2.4 million of total unrecognized compensation cost related to stock option, with $939,000, $918,000 and $532,000 to be recognized during the years ended December 31, 2008, 2009 and 2010, respectively.
The following table summarizes additional information about our stock options outstanding as of December 31, 2007:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Options Outstanding | | | Options Exercisable | |
| | | | | | | Weighted Average
| | | Weighted
| | | | | | Weighted Average
| | | Weighted
| |
Range of
| | | | | | Remaining
| | | Average
| | | | | | Remaining
| | | Average
| |
Exercise
| | | Number of
| | | Contractual Life
| | | Exercise
| | | Number of
| | | Contractual Life
| | | Exercise
| |
Prices | | | options | | | (in Years) | | | Price | | | options | | | (in Years) | | | Price | |
| |
| $ | 2.75-4.87 | | | | 380,699 | | | | 7.02 | | | $ | 4.14 | | | | 380,699 | | | | 7.02 | | | $ | 4.14 | |
| | 10.85-14.74 | | | | 386,064 | | | | 7.92 | | | | 11.01 | | | | 381,069 | | | | 7.92 | | | | 10.96 | |
| | 16.50-21.95 | | | | 220,000 | | | | 9.59 | | | | 21.83 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2.75-21.95 | | | | 986,763 | | | | 7.95 | | | $ | 10.77 | | | | 761,768 | | | | 7.47 | | | $ | 7.55 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
78
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
The aggregate pretax intrinsic value of stock options outstanding and exercisable was approximately $5.5 million at December 31, 2007. The amount represents the value that would have been received by the option holders had the respective options been exercised on December 31, 2007.
Restricted Stock Awards
In addition to stock options, our 2003 and 2006 Plans allow for the grant of restricted stock awards (“RSA”). A time-lapse RSA is an award of common stock, where each unit represents the right to receive at the end of a stipulated period one unrestricted share of stock with no exercise price. The time-lapse RSA restrictions lapse periodically over an extended period of time not exceeding 10 years. We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is primarily recognized on a straight-line basis over the vesting or service period and is net of forfeitures. A performance-based RSA is an award of common stock, where each unit represents the right to receive one unrestricted share of stock with no exercise price at the attainment of established performance criteria. During 2007, we granted 710,000 performance based RSAs with market conditions. The performance-based RSAs are granted, but not earned and issued until certain annual total shareholder return criteria are attained over the next 3 years. The fair value of the performance-based RSAs were based on third-party valuations.
The following table summarizes activity in our nonvested restricted stock awards:
| | | | | | | | | | | | | | | | | |
| | | December 31, 2007 | | | December 31, 2006 | |
| | | Number
| | | Weighted Ave.
| | | Number
| | | Weighted Ave.
| |
| | | of
| | | Grant Date Fair
| | | of
| | | Grant Date Fair
| |
| | | Shares | | | Value Per Share | | | Shares | | | Value Per Share | |
| |
| Beginning balance | | | 27,000 | | | $ | 18.30 | | | | — | | | $ | — | |
| Granted | | | 996,203 | | | | 17.44 | | | | 27,000 | | | | 18.30 | |
| Vested | | | (30,000 | ) | | | 18.01 | | | | — | | | | — | |
| Forfeited | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | |
| Ending balance | | | 993,203 | | | $ | 17.45 | | | | 27,000 | | | $ | 18.30 | |
| | | | | | | | | | | | | | | | | |
The total fair value of RSA shares that vested during 2007 was approximately $577,000. As of December 31, 2007, there was approximately $13.9 million of total unrecognized compensation cost related to nonvested RSAs, with $6.6 million, $5.0 million, $1.8 million, $278,000 and $208,000 to be recognized during the years ended December 31, 2008, 2009, 2010, 2011 and 2012, respectively.
| |
| NOTE 11 — | STOCK PURCHASE WARRANTS |
In conjunction with the MCA purchase by Oil Quip in February of 2001, MCA issued a common stock warrant for 620,000 shares to a third-party investment firm that assisted us in its initial identification and purchase of the MCA assets. The warrant entitles the holder to acquire up to 620,000 shares of common stock of MCA at an exercise price of $.01 per share over a nine-year period commencing on February 7, 2001.
We issued two warrants (“Warrants A and B”) for the purchase of 233,000 total shares of our common stock at an exercise price of $0.75 per share and one warrant for the purchase of 67,000 shares of our common stock at an exercise price of $5.00 per share (“Warrant C”) in connection with our subordinated debt financing for MCA in 2001. Warrants A and B were paid off on December 7, 2004. Warrant C was exercised during November 2006.
On February 6, 2002, in connection with the acquisition of substantially all of the outstanding stock of Strata, we issued a warrant for the purchase of 87,500 shares of our common stock at an exercise price of $0.75 per share over the term of four years. The warrants were exercised in August of 2005.
In connection with the Strata Acquisition, on February 19, 2003, we issued Energy Spectrum an additional warrant to purchase 175,000 shares of our common stock at an exercise price of $0.75 per share. The warrants were exercised in August of 2005.
79
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
In March 2004, we issued a warrant to purchase 340,000 shares of our common stock at an exercise price of $2.50 per share to Morgan Joseph & Co., in consideration of financial advisory services to be provided by Morgan Joseph pursuant to a consulting agreement. The warrants were exercised in August 2005.
In April 2004, we issued warrants to purchase 20,000 shares of common stock at an exercise price of $0.75 per share to Wells Fargo Credit, Inc., in connection with the extension of credit by Wells Fargo Credit Inc. The warrants were exercised in August 2005.
In April 2004, we completed a private placement of 620,000 shares of common stock and warrants to purchase 800,000 shares of common stock to the following investors: Christopher Engel; Donald Engel; the Engel Defined Benefit Plan; RER Corp., a corporation wholly-owned by director Robert Nederlander; and Leonard Toboroff, a director. The investors invested $1,550,000 in exchange for 620,000 shares of common stock for a purchase price equal to $2.50 per share, and invested $450,000 in exchange for warrants to purchase 800,000 shares of common stock at an exercise of $2.50 per share, expiring on April 1, 2006. A total of 486,557 of these warrants were exercised in 2005 with the remaining portion exercised during 2006.
In May 2004, we issued a warrant to purchase 3,000 shares of our common stock at an exercise price of $4.75 per share to a consultant in consideration of financial advisory services to be provided pursuant to a consulting agreement. The warrants were exercised in May 2004. This consultant was also granted 16,000 warrants in May of 2004 exercisable at $4.65 per share. These warrants were exercised in November of 2005. Warrants for 4,000 shares of our common stock at an exercise price of $4.65 were also issued to this consultant in May 2004 and were exercised in January 2007.
| |
| NOTE 12 — | CONDENSED CONSOLIDATED FINANCIAL INFORMATION |
Set forth on the following pages are the condensed consolidating financial statements of (i) Allis-Chalmers Energy Inc., (ii) its subsidiaries that are guarantors of the senior notes and revolving credit facility and (iii) the subsidiaries that are not guarantors of the senior notes and revolving credit facility (in thousands). Prior to the acquisition of DLS, all of our subsidiaries were guarantors of our senior notes and revolving credit facility, the parent company had no independent assets or operations, the guarantees were full and unconditional and joint and several.
80
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2007
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | | | | | | | | |
| | | Chalmers
| | | | | | Subsidiary
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors | | | Adjustments | | | Total | |
| |
Assets | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 41,176 | | | $ | 2,517 | | | $ | — | | | $ | 43,693 | |
| Trade receivables, net | | | — | | | | 83,126 | | | | 46,973 | | | | (5 | ) | | | 130,094 | |
| Inventories | | | — | | | | 15,699 | | | | 16,510 | | | | — | | | | 32,209 | |
| Intercompany receivables | | | 76,583 | | | | — | | | | — | | | | (76,583 | ) | | | — | |
| Note receivable from affiliate | | | 8,270 | | | | — | | | | — | | | | (8,270 | ) | | | — | |
| Prepaid expenses and other | | | 7,731 | | | | 2,564 | | | | 1,603 | | | | — | | | | 11,898 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total current assets | | | 92,584 | | | | 142,565 | | | | 67,603 | | | | (84,858 | ) | | | 217,894 | |
| Property and equipment, net | | | — | | | | 477,055 | | | | 149,613 | | | | — | | | | 626,668 | |
| Goodwill | | | — | | | | 136,875 | | | | 1,523 | | | | — | | | | 138,398 | |
| Other intangible assets, net | | | 552 | | | | 34,572 | | | | 56 | | | | — | | | | 35,180 | |
| Debt issuance costs, net | | | 14,228 | | | | — | | | | — | | | | — | | | | 14,228 | |
| Note receivable from affiliates | | | 16,380 | | | | — | | | | — | | | | (16,380 | ) | | | — | |
| Investments in affiliates | | | 824,410 | | | | — | | | | — | | | | (824,410 | ) | | | — | |
| Other assets | | | 15 | | | | 4,977 | | | | 16,225 | | | | — | | | | 21,217 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 948,169 | | | $ | 796,044 | | | $ | 235,020 | | | $ | (925,648 | ) | | $ | 1,053,585 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Liabilities and Stockholders’ Equity | | | | | | | | | | | | | | | | | | | | |
| Current maturities of long-term debt | | $ | 32 | | | $ | 4,026 | | | $ | 2,376 | | | $ | — | | | $ | 6,434 | |
| Trade accounts payable | | | — | | | | 16,815 | | | | 20,654 | | | | (5 | ) | | | 37,464 | |
| Accrued salaries, benefits and payroll taxes | | | — | | | | 3,712 | | | | 11,571 | | | | — | | | | 15,283 | |
| Accrued interest | | | 17,709 | | | | 33 | | | | 75 | | | | — | | | | 17,817 | |
| Accrued expenses | | | 1,660 | | | | 7,127 | | | | 11,758 | | | | — | | | | 20,545 | |
| Intercompany payables | | | — | | | | 433,116 | | | | 1,185 | | | | (434,301 | ) | | | — | |
| Note payable to affiliate | | | — | | | | — | | | | 8,270 | | | | (8,270 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total current liabilities | | | 19,401 | | | | 464,829 | | | | 55,889 | | | | (442,576 | ) | | | 97,543 | |
| Long-term debt, net of current maturities | | | 505,750 | | | | — | | | | 2,550 | | | | — | | | | 508,300 | |
| Note payable to affiliate | | | — | | | | — | | | | 16,380 | | | | (16,380 | ) | | | — | |
| Deferred income tax liability | | | 8,658 | | | | 13,809 | | | | 7,623 | | | | — | | | | 30,090 | |
| Other long-term liabilities | | | 31 | | | | 242 | | | | 3,050 | | | | — | | | | 3,323 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total liabilities | | | 533,840 | | | | 478,880 | | | | 85,492 | | | | (458,956 | ) | | | 639,256 | |
| Commitments and contingencies | | | | | | | | | | | | | | | | | | | | |
| Stockholders’ Equity | | | | | | | | | | | | | | | | | | | | |
| Common stock | | | 351 | | | | 3,526 | | | | 42,963 | | | | (46,489 | ) | | | 351 | |
| Capital in excess of par value | | | 326,095 | | | | 167,508 | | | | 74,969 | | | | (242,477 | ) | | | 326,095 | |
| Retained earnings | | | 87,883 | | | | 146,130 | | | | 31,596 | | | | (177,726 | ) | | | 87,883 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total stockholders’ equity | | | 414,329 | | | | 317,164 | | | | 149,528 | | | | (466,692 | ) | | | 414,329 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total liabilities and stock holders’ equity | | $ | 948,169 | | | $ | 796,044 | | | $ | 235,020 | | | $ | (925,648 | ) | | $ | 1,053,585 | |
| | | | | | | | | | | | | | | | | | | | | |
81
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2007
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-Chalmers
| | | | | | Subsidiary
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors | | | Adjustments | | | Total | |
| |
| Revenues | | $ | — | | | $ | 355,172 | | | $ | 215,795 | | | $ | — | | | $ | 570,967 | |
| Cost of revenues | | | | | | | | | | | | | | | | | | | | |
| Direct costs | | | — | | | | 185,617 | | | | 155,833 | | | | — | | | | 341,450 | |
| Depreciation | | | — | | | | 39,659 | | | | 11,255 | | | | — | | | | 50,914 | |
| | | | | | | | | | | | | | | | | | | | | |
| Gross margin | | | — | | | | 129,896 | | | | 48,707 | | | | — | | | | 178,603 | |
| General and administrative | | | 4,349 | | | | 44,439 | | | | 9,834 | | | | — | | | | 58,622 | |
| Gain on capillary asset sale | | | — | | | | (8,868 | ) | | | — | | | | — | | | | (8,868 | ) |
| Amortization | | | 46 | | | | 3,988 | | | | 33 | | | | — | | | | 4,067 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income (loss) from operations | | | (4,395 | ) | | | 90,337 | | | | 38,840 | | | | — | | | | 124,782 | |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | |
| Equity earnings in affiliates, net of tax | | | 102,208 | | | | — | | | | — | | | | (102,208 | ) | | | — | |
| Interest, net | | | (47,677 | ) | | | 2,796 | | | | (1,394 | ) | | | — | | | | (46,275 | ) |
| Other | | | 304 | | | | 336 | | | | 136 | | | | — | | | | 776 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 54,835 | | | | 3,132 | | | | (1,258 | ) | | | (102,208 | ) | | | (45,499 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income before income taxes | | | 50,440 | | | | 93,469 | | | | 37,582 | | | | (102,208 | ) | | | 79,283 | |
| Provision for income taxes | | | — | | | | (16,085 | ) | | | (12,758 | ) | | | — | | | | (28,843 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 50,440 | | | $ | 77,384 | | | $ | 24,824 | | | $ | (102,208 | ) | | $ | 50,440 | |
| | | | | | | | | | | | | | | | | | | | | |
82
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2007
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | Other
| | | | | | | |
| | | Chalmers
| | | | | | Subsidiaries
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | (Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors) | | | Adjustments | | | Total | |
| |
Cash Flows from Operating Activities: | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 50,440 | | | $ | 77,384 | | | $ | 24,824 | | | $ | (102,208 | ) | | $ | 50,440 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | |
| Depreciation & amortization | | | 46 | | | | 43,647 | | | | 11,288 | | | | — | | | | 54,981 | |
| Amortization and write-off of deferred financing fees | | | 3,197 | | | | — | | | | — | | | | — | | | | 3,197 | |
| Stock based compensation | | | 4,863 | | | | — | | | | — | | | | — | | | | 4,863 | |
| Allowance for bad debts | | | — | | | | 730 | | | | — | | | | — | | | | 730 | |
| Equity earnings in affiliates | | | (102,208 | ) | | | — | | | | — | | | | 102,208 | | | | — | |
| Deferred taxes | | | 7,430 | | | | — | | | | 587 | | | | — | | | | 8,017 | |
| Gain on sale of equipment | | | — | | | | (2,182 | ) | | | (141 | ) | | | — | | | | (2,323 | ) |
| Gain on capillary asset sale | | | — | | | | (8,868 | ) | | | — | | | | — | | | | (8,868 | ) |
| Changes in operating assets and liabilities, net of acquisitions: | | | | | | | | | | | | | | | | | | | | |
| Increase in accounts receivables | | | — | | | | (17,823 | ) | | | (13,002 | ) | | | — | | | | (30,825 | ) |
| Increase in inventories | | | — | | | | (4,286 | ) | | | (1,089 | ) | | | — | | | | (5,375 | ) |
| (Increase) Decrease in other current assets | | | (3,003 | ) | | | 12,075 | | | | (870 | ) | | | — | | | | 8,202 | |
| (Increase) decrease in other assets | | | 242 | | | | — | | | | (4,734 | ) | | | — | | | | (4,492 | ) |
| (Decrease) increase in accounts payable | | | (31 | ) | | | 2,234 | | | | 8,529 | | | | — | | | | 10,732 | |
| (Decrease) increase in accrued interest | | | 5,954 | | | | 33 | | | | (37 | ) | | | — | | | | 5,950 | |
| (Decrease) increase in accrued expenses | | | 1,525 | | | | (3,912 | ) | | | 3,895 | | | | — | | | | 1,508 | |
| (Decrease) increase in other liabilities | | | (273 | ) | | | (77 | ) | | | 3,050 | | | | — | | | | 2,700 | |
| Increase in accrued salaries, benefits and payroll taxes | | | — | | | | 355 | | | | 3,676 | | | | — | | | | 4,031 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) by operating activities | | | (31,818 | ) | | | 99,310 | | | | 35,976 | | | | — | | | | 103,468 | |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flows from Investing Activities: | | | | | | | | | | | | | | | | | | | | |
| Acquisitions, net of cash acquired | | | — | | | | (41,000 | ) | | | — | | | | — | | | | (41,000 | ) |
83
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | Other
| | | | | | | |
| | | Chalmers
| | | | | | Subsidiaries
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | (Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors) | | | Adjustments | | | Total | |
| |
| Purchase of investment interests | | | — | | | | (498 | ) | | | — | | | | — | | | | (498 | ) |
| Purchase of property and equipment | | | — | | | | (84,240 | ) | | | (28,911 | ) | | | — | | | | (113,151 | ) |
| Deposits on asset commitments | | | — | | | | — | | | | (11,488 | ) | | | — | | | | (11,488 | ) |
| Notes receivable from affiliates | | | (6,809 | ) | | | — | | | | — | | | | 6,809 | | | | — | |
| Proceeds from sale of capillary assets | | | — | | | | 16,250 | | | | — | | | | — | | | | 16,250 | |
| Proceeds from sale of property and equipment | | | — | | | | 12,666 | | | | 145 | | | | — | | | | 12,811 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) in investing activities | | | (6,809 | ) | | | (96,822 | ) | | | (40,254 | ) | | | 6,809 | | | | (137,076 | ) |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flows from Financing Activities: | | | | | | | | | | | | | | | | | | | | |
| Proceeds from issuance of long-term debt | | | 250,000 | | | | — | | | | — | | | | — | | | | 250,000 | |
| Payments on long-term debt | | | (300,000 | ) | | | (6,587 | ) | | | (3,158 | ) | | | — | | | | (309,745 | ) |
| Accounts receivable from affiliates | | | (8,674 | ) | | | — | | | | — | | | | 8,674 | | | | — | |
| Accounts payable to affiliates | | | — | | | | 7,506 | | | | 1,168 | | | | (8,674 | ) | | | — | |
| Note payable to affiliate | | | — | | | | — | | | | 6,809 | | | | (6,809 | ) | | | — | |
| Proceeds from issuance of common stock, net of offering costs | | | 100,055 | | | | — | | | | — | | | | — | | | | 100,055 | |
| Proceeds from exercise of options and warrants | | | 3,319 | | | | — | | | | — | | | | — | | | | 3,319 | |
| Tax benefit on stock plans | | | 1,719 | | | | — | | | | — | | | | — | | | | 1,719 | |
| Debt issuance costs | | | (7,792 | ) | | | — | | | | — | | | | — | | | | (7,792 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) by financing activities | | | 38,627 | | | | 919 | | | | 4,819 | | | | (6,809 | ) | | | 37,556 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | — | | | | 3,407 | | | | 541 | | | | — | | | | 3,948 | |
| Cash and cash equivalents at beginning of year | | | — | | | | 37,769 | | | | 1,976 | | | | — | | | | 39,745 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | 41,176 | | | $ | 2,517 | | | $ | — | | | $ | 43,693 | |
| | | | | | | | | | | | | | | | | | | | | |
84
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | | | | | | | | |
| | | Chalmers
| | | | | | Subsidiary
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors | | | Adjustments | | | Total | |
| |
Assets | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 37,769 | | | $ | 1,976 | | | $ | — | | | $ | 39,745 | |
| Trade receivables, net | | | — | | | | 62,089 | | | | 33,971 | | | | (294 | ) | | | 95,766 | |
| Inventories | | | — | | | | 13,194 | | | | 15,421 | | | | — | | | | 28,615 | |
| Intercompany receivables | | | 67,909 | | | | — | | | | — | | | | (67,909 | ) | | | — | |
| Note receivable from affiliate | | | 5,502 | | | | — | | | | — | | | | (5,502 | ) | | | — | |
| Prepaid expenses and other | | | 5,703 | | | | 10,200 | | | | 733 | | | | — | | | | 16,636 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total current assets | | | 79,114 | | | | 123,252 | | | | 52,101 | | | | (73,705 | ) | | | 180,762 | |
| Property and equipment, net | | | — | | | | 422,297 | | | | 131,961 | | | | — | | | | 554,258 | |
| Goodwill | | | — | | | | 124,331 | | | | 1,504 | | | | — | | | | 125,835 | |
| Other intangible assets, net | | | 598 | | | | 32,153 | | | | 89 | | | | — | | | | 32,840 | |
| Debt issuance costs, net | | | 9,633 | | | | — | | | | — | | | | — | | | | 9,633 | |
| Note receivable from affiliates | | | 12,339 | | | | — | | | | — | | | | (12,339 | ) | | | — | |
| Investments in affiliates | | | 722,202 | | | | — | | | | — | | | | (722,202 | ) | | | — | |
| Other assets | | | 257 | | | | 4,719 | | | | 22 | | | | — | | | | 4,998 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total assets | | $ | 824,143 | | | $ | 706,752 | | | $ | 185,677 | | | $ | (808,246 | ) | | $ | 908,326 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
Liabilities and Stockholders’ Equity | | | | | | | | | | | | | | | | | | | | |
| Current maturities of long-term debt | | $ | 32 | | | $ | 3,809 | | | $ | 3,158 | | | $ | — | | | $ | 6,999 | |
| Trade accounts payable | | | 31 | | | | 13,510 | | | | 12,125 | | | | — | | | | 25,666 | |
| Accrued salaries, benefits and payroll taxes | | | — | | | | 2,993 | | | | 7,895 | | | | — | | | | 10,888 | |
| Accrued interest | | | 11,755 | | | | — | | | | 112 | | | | — | | | | 11,867 | |
| Accrued expenses | | | 135 | | | | 9,247 | | | | 7,863 | | | | (294 | ) | | | 16,951 | |
| Intercompany payables | | | — | | | | 425,610 | | | | 17 | | | | (425,627 | ) | | | — | |
| Note payable to affiliate | | | — | | | | — | | | | 5,502 | | | | (5,502 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total current liabilities | | | 11,953 | | | | 455,169 | | | | 36,672 | | | | (431,423 | ) | | | 72,371 | |
| Long-term debt, net of current maturities | | | 555,750 | | | | 770 | | | | 4,926 | | | | — | | | | 561,446 | |
| Note payable to affiliate | | | — | | | | — | | | | 12,339 | | | | (12,339 | ) | | | — | |
| Deferred income tax liability | | | 2,203 | | | | 10,714 | | | | 7,036 | | | | — | | | | 19,953 | |
| Other long-term liabilities | | | 304 | | | | 319 | | | | — | | | | — | | | | 623 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total liabilities | | | 570,210 | | | | 466,972 | | | | 60,973 | | | | (443,762 | ) | | | 654,393 | |
| Commitments and contingencies | | | | | | | | | | | | | | | | | | | | |
| Stockholders’ Equity | | | | | | | | | | | | | | | | | | | | |
| Common stock | | | 282 | | | | 3,526 | | | | 42,963 | | | | (46,489 | ) | | | 282 | |
| Capital in excess of par value | | | 216,208 | | | | 167,508 | | | | 74,969 | | | | (242,477 | ) | | | 216,208 | |
| Retained earnings | | | 37,443 | | | | 68,746 | | | | 6,772 | | | | (75,518 | ) | | | 37,443 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total stockholders’ equity | | | 253,933 | | | | 239,780 | | | | 124,704 | | | | (364,484 | ) | | | 253,933 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total liabilities and stock holders’ equity | | $ | 824,143 | | | $ | 706,752 | | | $ | 185,677 | | | $ | (808,246 | ) | | $ | 908,326 | |
| | | | | | | | | | | | | | | | | | | | | |
85
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING INCOME STATEMENTS
For the Year Ended December 31, 2006
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-Chalmers
| | | | | | Subsidiary
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors | | | Adjustments | | | Total | |
| |
| Revenues | | $ | — | | | $ | 241,474 | | | $ | 69,490 | | | $ | — | | | $ | 310,964 | |
| Cost of revenues | | | | | | | | | | | | | | | | | | | | |
| Direct costs | | | — | | | | 134,638 | | | | 50,941 | | | | — | | | | 185,579 | |
| Depreciation | | | — | | | | 16,198 | | | | 4,063 | | | | — | | | | 20,261 | |
| | | | | | | | | | | | | | | | | | | | | |
| Gross margin | | | — | | | | 90,638 | | | | 14,486 | | | | — | | | | 105,124 | |
| General and administrative | | | 2,643 | | | | 30,651 | | | | 2,242 | | | | — | | | | 35,536 | |
| Amortization | | | 46 | | | | 1,801 | | | | 11 | | | | — | | | | 1,858 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income (loss) from operations | | | (2,689 | ) | | | 58,186 | | | | 12,233 | | | | — | | | | 67,730 | |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | |
| Equity earnings in affiliates, net of tax | | | 58,077 | | | | — | | | | — | | | | (58,077 | ) | | | — | |
| Interest, net | | | (19,807 | ) | | | 67 | | | | (597 | ) | | | — | | | | (20,337 | ) |
| Other | | | 45 | | | | 97 | | | | (489 | ) | | | — | | | | (347 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 38,315 | | | | 164 | | | | (1,086 | ) | | | (58,077 | ) | | | (20,684 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income (loss) before income taxes | | | 35,626 | | | | 58,350 | | | | 11,147 | | | | (58,077 | ) | | | 47,046 | |
| Provision for income taxes | | | — | | | | (7,045 | ) | | | (4,375 | ) | | | — | | | | (11,420 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 35,626 | | | $ | 51,305 | | | $ | 6,772 | | | $ | (58,077 | ) | | $ | 35,626 | |
| | | | | | | | | | | | | | | | | | | | | |
86
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW
For the Year Ended December 31, 2006 (unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | Other
| | | | | | | |
| | | Chalmers
| | | | | | Subsidiaries
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | (Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors) | | | Adjustments | | | Total | |
| |
Cash Flows from Operating Activities: | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 35,626 | | | $ | 51,305 | | | $ | 6,772 | | | $ | (58,077 | ) | | $ | 35,626 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | |
| Depreciation & amortization | | | 46 | | | | 17,999 | | | | 4,074 | | | | — | | | | 22,119 | |
| Amortization & write-off of deferred financing fees | | | 1,527 | | | | — | | | | — | | | | — | | | | 1,527 | |
| Stock based compensation | | | 3,394 | | | | — | | | | — | | | | — | | | | 3,394 | |
| Provision for bad debts | | | — | | | | 781 | | | | — | | | | — | | | | 781 | |
| Imputed interest | | | — | | | | 355 | | | | — | | | | — | | | | 355 | |
| Equity earnings in affiliates | | | (58,077 | ) | | | — | | | | — | | | | 58,077 | | | | — | |
| Deferred taxes | | | (619 | ) | | | 247 | | | | 2,587 | | | | — | | | | 2,215 | |
| Gain on sale of equipment | | | — | | | | (2,428 | ) | | | (16 | ) | | | — | | | | (2,444 | ) |
| Changes in operating assets and liabilities, net of acquisitions: | | | | | | | | | | | | | | | | | | | | |
| Increase in accounts receivables | | | — | | | | (23,144 | ) | | | (31 | ) | | | — | | | | (23,175 | ) |
| (Increase) decrease in inventories | | | — | | | | (2,989 | ) | | | 352 | | | | — | | | | (2,637 | ) |
| (Increase) decrease in other current assets | | | (2,482 | ) | | | 4,120 | | | | 867 | | | | — | | | | 2,505 | |
| (Increase) decrease in other assets | | | 296 | | | | 101 | | | | (89 | ) | | | — | | | | 308 | |
| (Decrease) increase in accounts payable | | | (82 | ) | | | 3,587 | | | | (5,842 | ) | | | — | | | | (2,337 | ) |
| (Decrease) increase in accrued interest | | | 11,508 | | | | (45 | ) | | | (81 | ) | | | — | | | | 11,382 | |
| (Decrease) increase in accrued expenses | | | (390 | ) | | | 1,633 | | | | (371 | ) | | | — | | | | 872 | |
| (Decrease) in other liabilities | | | (31 | ) | | | (193 | ) | | | — | | | | — | | | | (224 | ) |
| (Decrease) increase in accrued salaries, benefits and payroll taxes | | | (1,951 | ) | | | 2,780 | | | | 2,563 | | | | — | | | | 3,392 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) by operating activities | | | (11,235 | ) | | | 54,109 | | | | 10,785 | | | | — | | | | 53,659 | |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flows from Investing Activities: | | | | | | | | | | | | | | | | | | | | |
| Acquisitions, net of cash acquired | | | (528,167 | ) | | | 3,649 | | | | (2,054 | ) | | | — | | | | (526,572 | ) |
| Notes receivable from affiliates | | | (585 | ) | | | — | | | | — | | | | 585 | | | | — | |
| Purchase of property and equipment | | | — | | | | (33,930 | ) | | | (5,767 | ) | | | — | | | | (39,697 | ) |
87
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | | | | | | | | | |
| | | Allis-
| | | | | | Other
| | | | | | | |
| | | Chalmers
| | | | | | Subsidiaries
| | | | | | | |
| | | (Parent/
| | | Subsidiary
| | | (Non-
| | | Consolidating
| | | Consolidated
| |
| | | Guarantor) | | | Guarantors | | | Guarantors) | | | Adjustments | | | Total | |
| |
| Proceeds from sale of property and equipment | | | — | | | | 6,730 | | | | 151 | | | | — | | | | 6,881 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) in investing activities | | | (528,752 | ) | | | (23,551 | ) | | | (7,670 | ) | | | 585 | | | | (559,388 | ) |
| | | | | | | | | | | | | | | | | | | | | |
Cash Flows from Financing Activities: | | | | | | | | | | | | | | | | | | | | |
| Proceeds from long-term debt | | | 555,000 | | | | 2,820 | | | | — | | | | — | | | | 557,820 | |
| Payments on long-term debt | | | (42,414 | ) | | | (9,875 | ) | | | (1,741 | ) | | | — | | | | (54,030 | ) |
| Payments on related party debt | | | — | | | | (3,031 | ) | | | — | | | | — | | | | (3,031 | ) |
| Net (payments) borrowings on lines of credit | | | (6,400 | ) | | | — | | | | — | | | | — | | | | (6,400 | ) |
| Accounts receivable from affiliates | | | (16,444 | ) | | | — | | | | — | | | | 16,444 | | | | — | |
| Accounts payable to affiliates | | | — | | | | 16,427 | | | | 17 | | | | (16,444 | ) | | | — | |
| Note payable to affiliate | | | — | | | | — | | | | 585 | | | | (585 | ) | | | — | |
| Proceeds from issuance of common stock, net of offering costs | | | 46,297 | | | | — | | | | — | | | | — | | | | 46,297 | |
| Proceeds from exercise of options and warrants | | | 6,321 | | | | — | | | | — | | | | — | | | | 6,321 | |
| Tax benefit on stock plans | | | 6,440 | | | | — | | | | — | | | | — | | | | 6,440 | |
| Debt issuance costs | | | (9,863 | ) | | | — | | | | | | | | — | | | | (9,863 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net cash provided (used) by financing activities | | | 538,937 | | | | 6,341 | | | | (1,139 | ) | | | (585 | ) | | | 543,554 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | (1,050 | ) | | | 36,899 | | | | 1,976 | | | | — | | | | 37,825 | |
| Cash and cash equivalents at beginning of year | | | 1,050 | | | | 870 | | | | — | | | | — | | | | 1,920 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | 37,769 | | | $ | 1,976 | | | $ | — | | | $ | 39,745 | |
| | | | | | | | | | | | | | | | | | | | | |
| |
| NOTE 13 — | RELATED PARTY TRANSACTIONS |
DLS was acquired from three British Virgin Island corporations. Two of our Directors; Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of the shares of the DLS sellers. DLS’ largest customer is Pan American Energy which is a joint venture by British Petroleum and Bridas Corporation. Alejandro P. Bulgheroni and Carlos A. Bulgheroni, indirectly beneficially own substantially all of the shares of the Bridas Corporation.
We purchased approximately $3.5 million of general oilfield supplies and materials from Ralow Services, Inc., or Ralow in 2007 for our Rental Services segment. Ralow is owned by Brad A. Adams and Bruce A. Adams who are brothers of Burt A. Adams, one of our directors and our former President and Chief Operating Officer. In addition, Brad A. Adams and Bruce A. Adams were employed as officers of Rental during 2007.
88
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
| |
| NOTE 14 — | SEGMENT INFORMATION |
At December 31, 2007, we had six operating segments including: Rental Services, International Drilling, Directional Drilling, Tubular Services, Underbalanced Drilling and Production Services. All of the segments provide services to the energy industry. The revenues, operating income (loss), depreciation and amortization, capital expenditures and assets of each of the reporting segments plus the corporate function are reported below (in thousands):
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
Revenues: | | | | | | | | | | | | |
| Rental Services | | $ | 121,186 | | | $ | 51,521 | | | $ | 5,059 | |
| International Drilling | | | 215,795 | | | | 69,490 | | | | — | |
| Directional Drilling | | | 96,080 | | | | 76,471 | | | | 46,579 | |
| Tubular Services | | | 53,524 | | | | 50,887 | | | | 20,932 | |
| Underbalanced Drilling | | | 50,959 | | | | 43,045 | | | | 25,662 | |
| Production Services | | | 33,423 | | | | 19,550 | | | | 9,790 | |
| | | | | | | | | | | | | |
| Total revenues | | $ | 570,967 | | | $ | 310,964 | | | $ | 108,022 | |
| | | | | | | | | | | | | |
Operating Income (Loss): | | | | | | | | | | | | |
| Rental Services | | $ | 49,139 | | | $ | 26,293 | | | $ | 1,300 | |
| International Drilling | | | 38,839 | | | | 12,233 | | | | — | |
| Directional Drilling | | | 18,848 | | | | 17,666 | | | | 7,389 | |
| Tubular Services | | | 10,744 | | | | 12,544 | | | | 4,994 | |
| Underbalanced Drilling | | | 13,091 | | | | 10,810 | | | | 5,612 | |
| Production Services | | | 10,535 | | | | 2,137 | | | | (99 | ) |
| General corporate | | | (16,414 | ) | | | (13,953 | ) | | | (5,678 | ) |
| | | | | | | | | | | | | |
| Total income from operations | | $ | 124,782 | | | $ | 67,730 | | | $ | 13,518 | |
| | | | | | | | | | | | | |
Depreciation and Amortization Expense: | | | | | | | | | | | | |
| Rental Services | | $ | 26,353 | | | $ | 7,268 | | | $ | 492 | |
| International Drilling | | | 11,288 | | | | 4,074 | | | | — | |
| Directional Drilling | | | 3,063 | | | | 1,464 | | | | 887 | |
| Tubular Services | | | 5,164 | | | | 3,908 | | | | 2,006 | |
| Underbalanced Drilling | | | 3,692 | | | | 3,057 | | | | 1,946 | |
| Production Services | | | 4,919 | | | | 2,005 | | | | 912 | |
| General corporate | | | 502 | | | | 343 | | | | 118 | |
| | | | | | | | | | | | | |
| Total depreciation and amortization expense | | $ | 54,981 | | | $ | 22,119 | | | $ | 6,361 | |
| | | | | | | | | | | | | |
Capital Expenditures: | | | | | | | | | | | | |
| Rental Services | | $ | 34,883 | | | $ | 4,538 | | | $ | 435 | |
| International Drilling | | | 28,911 | | | | 5,770 | | | | — | |
| Directional Drilling | | | 11,177 | | | | 5,128 | | | | 2,922 | |
| Tubular Services | | | 9,250 | | | | 10,980 | | | | 5,207 | |
| Underbalanced Drilling | | | 17,443 | | | | 7,716 | | | | 7,008 | |
| Production Services | | | 10,740 | | | | 5,253 | | | | 1,514 | |
| General corporate | | | 747 | | | | 312 | | | | 681 | |
| | | | | | | | | | | | | |
| Total capital expenditures | | $ | 113,151 | | | $ | 39,697 | | | $ | 17,767 | |
| | | | | | | | | | | | | |
89
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
Goodwill: | | | | | | | | | | | | |
| Rental Services | | $ | 106,382 | | | $ | 106,132 | | | $ | — | |
| International Drilling | | | 1,523 | | | | 1,504 | | | | — | |
| Directional Drilling | | | 16,300 | | | | 4,168 | | | | 4,168 | |
| Tubular Services | | | 6,564 | | | | 6,464 | | | | 3,673 | |
| Underbalanced Drilling | | | 3,950 | | | | 3,950 | | | | 3,950 | |
| Production Services | | | 3,679 | | | | 3,617 | | | | 626 | |
| General corporate | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total goodwill | | $ | 138,398 | | | $ | 125,835 | | | $ | 12,417 | |
| | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | |
| Rental Services | | $ | 454,216 | | | $ | 453,802 | | | $ | 8,034 | |
| International Drilling | | | 235,020 | | | | 185,677 | | | | — | |
| Directional Drilling | | | 82,532 | | | | 28,585 | | | | 20,960 | |
| Tubular Services | | | 88,014 | | | | 74,372 | | | | 45,351 | |
| Underbalanced Drilling | | | 72,401 | | | | 54,288 | | | | 46,045 | |
| Production Services | | | 56,353 | | | | 57,954 | | | | 12,282 | |
| General corporate | | | 65,049 | | | | 53,648 | | | | 4,683 | |
| | | | | | | | | | | | | |
| Total assets | | $ | 1,053,585 | | | $ | 908,326 | | | $ | 137,355 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
Revenues: | | | | | | | | | | | | |
| United States | | $ | 339,476 | | | $ | 231,852 | | | $ | 101,261 | |
| International | | | 231,491 | | | | 79,112 | | | | 6,761 | |
| | | | | | | | | | | | | |
| Total revenues | | $ | 570,967 | | | $ | 310,964 | | | $ | 108,022 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | As of December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
Long Lived Assets: | | | | | | | | | | | | |
| United States | | $ | 655,513 | | | $ | 574,302 | | | $ | 97,390 | |
| International | | | 180,178 | | | | 153,262 | | | | 4,313 | |
| | | | | | | | | | | | | |
| Total long lived assets | | $ | 835,691 | | | $ | 727,564 | | | $ | 101,703 | |
| | | | | | | | | | | | | |
90
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
| |
| NOTE 15 — | SUPPLEMENTAL CASH FLOWS INFORMATION (in thousands) |
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| |
| Interest paid | | $ | 40,363 | | | $ | 8,571 | | | $ | 3,924 | |
| | | | | | | | | | | | | |
| Income taxes paid | | $ | 17,272 | | | $ | 5,796 | | | $ | 676 | |
| | | | | | | | | | | | | |
Other non-cash investing and financing transactions: | | | | | | | | | | | | |
| Insurance premiums financed | | | 4,434 | | | | 2,871 | | | | — | |
| Purchase of equipment financed through assumption of debt or accounts payable | | | — | | | | — | | | | 592 | |
Non-cash investing and financing transactions in connection with acquisitions: | | | | | | | | | | | | |
| Fair value of Property and equipment | | $ | 4,345 | | | $ | 109,632 | | | $ | 1,750 | |
| Fair value of goodwill and other intangibles | | | 350 | | | | 4,010 | | | | — | |
| | | | | | | | | | | | | |
| | | $ | 4,695 | | | $ | 113,642 | | | $ | 1,750 | |
| | | | | | | | | | | | | |
| Value of common stock, issued | | $ | — | | | $ | 94,980 | | | $ | 1,750 | |
| Seller financed note | | | 1,600 | | | | 750 | | | | — | |
| Deferred tax liability | | | 3,095 | | | | 17,662 | | | | — | |
| Accrued expenses | | | — | | | | 250 | | | | — | |
| | | | | | | | | | | | | |
| | | $ | 4,695 | | | $ | 113,642 | | | $ | 1,750 | |
| | | | | | | | | | | | | |
We are named from time to time in legal proceedings related to our activities prior to our bankruptcy in 1988; however, we believe that we were discharged from liability for all such claims in the bankruptcy and believe the likelihood of a material loss relating to any such legal proceeding is remote.
We are involved in various other legal proceedings in the ordinary course of business. The legal proceedings are at different stages; however, we believe that the likelihood of material loss relating to any such legal proceeding is remote.
| |
| NOTE 17 — | SUBSEQUENT EVENTS |
On January 23, 2008, we entered into an Agreement and Plan of Merger with Bronco Drilling Company, Inc., or Bronco, whereby Bronco will become a wholly-owned subsidiary of Allis-Chalmers. The merger agreement, which was approved by our Board of Directors and the Board of Directors of Bronco, provides that the Bronco stockholders will receive aggregate merger consideration with a value of approximately $437.8 million, consisting of (a) $280.0 million in cash and (b) shares of our common stock, par value $0.01 per share, having an aggregate value of approximately $157.8 million. The number of shares of our common stock to be issued will be based on the average closing price of our common stock for the ten-trading day period ending two days prior to the closing. Completion of the merger is conditioned upon, among other things, adoption of the merger agreement by Bronco’s stockholders and approval by our stockholders of the issuance of shares of our common stock to be used as merger consideration.
In order to finance some or all of the cash component of the merger consideration, the repayment of outstanding Bronco debt and transaction expenses, we expect to incur debt of up to $350.0 million. We intend to obtain up to $350.0 million from either (1) a permanent debt financing of up to $350.0 million or (2) if the permanent debt financing cannot be consummated prior to the closing date of the merger, the draw down under a senior unsecured bridge loan facility in an aggregate principal amount of up to $350.0 million to be arranged by RBC Capital Markets Corporation and Goldman Sachs Credit Partners L.P., acting as joint lead arrangers and joint bookrunners. We executed a commitment letter, dated January 28, 2008, with Royal Bank of Canada and Goldman Sachs who have each, subject to certain conditions, severally committed to provide
91
ALLIS-CHALMERS ENERGY INC.
Notes to Consolidated Financial Statements — (Continued)
50% of the loans under the senior unsecured bridge facility to us. This commitment for the bridge loan facility will terminate on July 31, 2008, if we have not drawn the bridge facility by such date and the merger is not consummated by such date. The commitment may also terminate prior to July 31, 2008, if the merger is abandoned or a material condition to the merger is not satisfied or we breach our obligations under the commitment letter. We may use the proceeds of the bridge facility to finance the cash component of the merger consideration, repay outstanding Bronco debt and pay transaction expenses.
On January 29, 2008, Burt A. Adams resigned as our President and Chief Operating Officer, effective February 28, 2008. Mr. Adams will remain as a member of our Board of Directors. On January 29, 2008, Mark C. Patterson was elected our Senior Vice-President — Rental Services. On January 29, 2008, Terrence P. Keane was elected our Senior Vice-President — Oilfield Services.
On January 31, 2008, we entered into an agreement with BCH Ltd., or BCH, to invest $40.0 million in cash in BCH in the form of a 15% Convertible Subordinated Secured debenture. The debenture is convertible, at any time, at our option into 49% of the common equity of BCH. At the end of two years, we have the option to acquire the remaining 51% of BCH from its parent, BrazAlta Resources Corp., or BrazAlta, based on an independent valuation from a mutually acceptable investment bank. BCH is a Canadian-based oilfield services company engaged in contract drilling operations exclusively in Brazil.
On February 15, 2008, through our DLS subsidiary in Argentina, we entered into a $25.0 million import finance facility with a bank. Borrowings under this facility will be used to fund a portion of the purchase price of the new drilling and service rigs ordered for our international drilling operation. The facility is available for borrowings until December 31, 2008. Each drawdown shall be repaid over four years in equal semi-annual instalments beginning one year after each disbursement with the final principal payment due not later than March 15, 2013. Interest is payable every six months. The import finance facility is unsecured and contains customary events of default and financial covenants and limits DLS’ ability to incur additional indebtedness, make capital expenditures, create liens and sell assets.
| |
| NOTE 18 — | SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) (in thousands, except per share amounts) |
| | | | | | | | | | | | | | | | | |
| | | First
| | | Second
| | | Third
| | | Fourth
| |
| | | Quarter | | | Quarter | | | Quarter | | | Quarter | |
Year 2007 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 135,900 | | | $ | 143,362 | | | $ | 147,881 | | | $ | 143,824 | |
| Operating income | | | 31,470 | | | | 41,474 | | | | 31,148 | | | | 20,690 | |
| Net income | | $ | 12,165 | | | $ | 19,504 | | | $ | 12,987 | | | $ | 5,784 | |
| | | | | | | | | | | | | | | | | |
| Income per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.38 | | | $ | 0.56 | | | $ | 0.37 | | | $ | 0.17 | |
| | | | | | | | | | | | | | | | | |
| Diluted | | $ | 0.37 | | | $ | 0.55 | | | $ | 0.37 | | | $ | 0.16 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | First
| | | Second
| | | Third
| | | Fourth
| |
| | | Quarter | | | Quarter | | | Quarter | | | Quarter | |
Year 2006 | | | | | | | | | | | | | | | | |
| Revenues | | $ | 47,911 | | | $ | 61,383 | | | $ | 86,772 | | | $ | 114,898 | |
| Operating income | | | 8,856 | | | | 16,108 | | | | 19,336 | | | | 23,430 | |
| Net income | | $ | 4,423 | | | $ | 9,594 | | | $ | 11,253 | | | $ | 10,356 | |
| | | | | | | | | | | | | | | | | |
| Income per common share: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.26 | | | $ | 0.53 | | | $ | 0.52 | | | $ | 0.41 | |
| | | | | | | | | | | | | | | | | |
| Diluted | | $ | 0.23 | | | $ | 0.50 | | | $ | 0.50 | | | $ | 0.40 | |
| | | | | | | | | | | | | | | | | |
92
| |
| ITEM 9. | CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
| ITEM 9A. | CONTROLS AND PROCEDURES |
| |
| (a) | Evaluation Of Disclosure Controls And Procedures |
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Exchange ActRules 13a-15(e) and15d-15(e)), as of December 31, 2007. Based on their evaluation, they have concluded that our disclosure controls and procedures as of the end of the period covered by this report were adequate to ensure that (1) information required to be disclosed by us in the reports filed or furnished by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (2) such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures as of December 31, 2007 were effective at reaching a reasonable level of assurance of achieving the desired objective.
| |
| (b) | Management’s Report on Internal Control Over Financial Reporting |
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange ActRule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our company. 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 our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and 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 our financial statements. Our evaluation did not include companies which were acquired during fiscal year 2007, since, under SEC guidelines, acquisitions do not have to evaluated until twelve months after the acquisition date.
In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2007, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, 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.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, and concluded that, as of December 31, 2007, our internal controls over financial reporting are effective based on these criteria.
Management Report on Internal Control Over Financial Reporting.
Our Management Report on Internal Controls Over Financial Reporting can be found in Item 8 of this report. UHY LLP, an independent registered public accounting firm, has issued a report on our internal control over financial reporting as of December 31, 2007, which can be found in Item 8 of this report.
93
| |
| (c) | Change in Internal Control Over Financial Reporting. |
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| |
| ITEM 9B. | OTHER INFORMATION |
None.
PART III
| |
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Pursuant to General Instructions G(3), information on directors and executive officers of Allis-Chalmers will be filed in an amendment to this Annual Report onForm 10-K or incorporated by reference from our Definitive Proxy Statement for the 2008 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2007.
| |
| ITEM 11. | EXECUTIVE COMPENSATION |
Pursuant to General Instructions G(3), information on executive compensation will be filed in an amendment to this Annual Report onForm 10-K or incorporated by reference from our Definitive Proxy Statement for the 2008 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2007.
| |
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTER |
Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report onForm 10-K or incorporated by reference from our Definitive Proxy Statement for the 2008 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2007.
| |
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Pursuant to General Instruction G(3), information on security ownership of certain beneficial owners and management will be filed in an amendment to this Annual Report onForm 10-K or incorporated by reference from our Definitive Proxy Statement for the 2008 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2007.
| |
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Pursuant to General Instruction G(3), information on principal accountant fees and services will be filed in an amendment to this Annual Report onForm 10-K or incorporated by reference from our Definitive Proxy Statement for the 2008 annual meeting of stockholders within 120 days of the end of our fiscal year ending December 31, 2007.
94
PART IV
| |
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a)(1) Financial Statements
Consolidated Balance Sheets as of December 31, 2007 and 2006.
Consolidated Statements of Operations as of December 31, 2007, 2006 and 2005.
Consolidated Statement of Stockholders’ Equity as of December 31, 2007, 2006, 2005 and 2004.
Consolidated Statements of Cash Flows as of December 31, 2007, 2006 and 2005.
Notes to Consolidated Financial Statements.
(2) Financial Statement Schedules
Schedule II — Valuation and Qualifying Accounts
(3) Exhibits
The exhibits listed on the accompanying Exhibit Index or incorporated by reference into this annual report onForm 10-K.
| |
| (2) | Financial Statement Schedule: |
Schedule II — Valuation and Qualifying Accounts
Allis-Chalmers Energy Inc.
Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | | |
| | | | | | Additions
| | | | | | | |
| | | Balance at
| | | Charged to
| | | | | | Balance at
| |
| | | Beginning
| | | Costs and
| | | | | | End of
| |
Description | | of Period | | | Expense | | | Deductions | | | Period | |
| | | (In thousands) | |
| |
Year Ended December 31, 2007: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 826 | | | | 1,309 | | | | (211 | ) | | | 1,924 | |
| Deferred tax assets valuation allowance | | | — | | | | — | | | | — | | | | — | |
Year Ended December 31, 2006: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 383 | | | | 781 | | | | (338 | ) | | | 826 | |
| Deferred tax assets valuation allowance | | | 27,131 | | | | — | | | | (27,131 | ) | | | — | |
Year Ended December 31, 2005: | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts | | | 265 | | | | 219 | | | | (101 | ) | | | 383 | |
| Deferred tax assets valuation allowance | | | 30,367 | | | | — | | | | (3,236 | ) | | | 27,131 | |
95
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 6, 2008.
/s/ MUNAWAR H. HIDAYATALLAH
Munawar H. Hidayatallah
Chief Executive Officer and Chairman
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, this report has been signed on the date indicated by the following persons on behalf of the registrant and in the capacities indicated.
| | | | | | | |
Name | | Title | | Date |
| |
| | | | | |
/s/ MUNAWAR H. HIDAYATALLAH
Munawar H. Hidayatalla | | Chairman and Chief Executive Officer (Principal Executive Officer) | | March 6, 2008 |
| | | | | |
/s/ VICTOR M. PEREZ
Victor M. Perez | | Chief Financial Officer
(Principal Financial Officer) | | March 6, 2008 |
| | | | | |
/s/ BRUCE SAUERS
Bruce Sauers | | Chief Accounting Officer
(Principal Accounting Officer) | | March 6, 2008 |
| | | | | |
/s/ BURT A. ADAMS
Burt A. Adams | | Director | | March 6, 2008 |
| | | | | |
Ali H. M. Afdhal | | Director | | March 6, 2008 |
| | | | | |
/s/ ALEJANDRO P. BULGHERONI
Alejandro P. Bulgheroni | | Director | | March 6, 2008 |
| | | | | |
Carlos A. Bulgheroni | | Director | | March 6, 2008 |
| | | | | |
/s/ VICTOR F. GERMACK
Victor F. Germack | | Director | | March 6, 2008 |
| | | | | |
/s/ JAMES M. HENNESSY
James M. Hennessy | | Director | | March 6, 2008 |
| | | | | |
/s/ JOHN E. MCCONNAUGHY, JR.
John E. McConnaughy, Jr. | | Director | | March 6, 2008 |
| | | | | |
/s/ ROBERT E. NEDERLANDER
Robert E. Nederlander | | Director | | March 6, 2008 |
| | | | | |
Zane Tankel | | Director | | March 6, 2008 |
| | | | | |
/s/ LEONARD TOBOROFF
Leonard Toboroff | | Director | | March 6, 2008 |
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EXHIBIT INDEX
| | | | | |
Exhibit | | Description |
| |
| | 2 | .1 | | First Amended Disclosure Statement pursuant to Section 1125 of the Bankruptcy Code, dated September 14, 1988, which includes the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 (incorporated by reference to Registrant’s Current Report onForm 8-K dated December 1, 1988). |
| | 2 | .2 | | Reorganization Trust Agreement dated September 14, 1988 by and between Registrant and John T. Grigsby, Jr., Trustee (incorporated by reference to Exhibit D of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report onForm 8-K dated December 1, 1988). |
| | 2 | .3 | | Agreement and Plan of Merger dated as of May 9, 2001 by and among Registrant, Allis-Chalmers Acquisition Corp. and Oil Quip Rentals, Inc. (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report onForm 8-K filed May 15, 2001). |
| | 2 | .4 | | Stock Purchase Agreement dated February 1, 2002 by and between Registrant and Jens H. Mortensen, Jr. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed February 21, 2002). |
| | 2 | .5 | | Stock Purchase Agreement dated February 1, 2002 by and among Registrant, Energy Spectrum Partners LP, and Strata Directional Technology, Inc. (incorporated by reference to Exhibit 2.10 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2001). |
| | 2 | .6 | | Stock Purchase Agreement dated August 10, 2004 by and among Allis-Chalmers Corporation and the investors named thereto (incorporated by reference to Exhibit 10.37 to the Registration Statement onForm S-1 (Registration No. 118916) filed on September 10, 2004). |
| | 2 | .7 | | Amendment to Stock Purchase Agreement dated August 10, 2004 (incorporated by reference to Exhibit 10.38 to the Registration Statement onForm S-1 (Registration No. 118916) filed on September 10, 2004). |
| | 2 | .8 | | Addendum to Stock Purchase Agreement dated September 24, 2004 (incorporated by reference to Exhibit 10.55 to Registrant’s Current Report onForm 8-K filed on September 30, 2004). |
| | 2 | .9 | | Asset Purchase Agreement dated November 10, 2004 by and among AirComp LLC, a Delaware limited liability company, Diamond Air Drilling Services, Inc., a Texas corporation, and Marquis Bit Co., L.L.C., a New Mexico limited liability company, Greg Hawley and Tammy Hawley, residents of Texas and Clay Wilson and Linda Wilson, residents of New Mexico (incorporated by reference to the Current Report onForm 8-K filed on November 15, 2004). |
| | 2 | .10 | | Purchase Agreement and related Agreements by and among Allis-Chalmers Corporation, Chevron USA, Inc., Dale Redman and others dated December 10, 2004 (incorporated by reference to Exhibit 10.63 to the Registrant’s Current Report onForm 8-K filed on December 16, 2004). |
| | 2 | .11 | | Stock Purchase Agreement dated April 1, 2005, by and among Allis-Chalmers Energy Inc., Thomas Whittington, Sr., Werlyn R. Bourgeois and SAM and D, LLC. (incorporated by reference to Exhibit 10.51 to the Registrant’s Current Report onForm 8-K filed on April 5, 2005). |
| | 2 | .12 | | Stock Purchase Agreement effective May 1, 2005, by and among Allis-Chalmers Energy Inc., Wesley J. Mahone, Mike T. Wilhite, Andrew D. Mills and Tim Williams (incorporated by reference to Exhibit 10.51 to the Registrant’s Current Report onForm 8-K filed on May 6, 2005). |
| | 2 | .13 | | Purchase Agreement dated July 11, 2005 among Allis-Chalmers Energy Inc., Mountain Compressed Air, Inc. and M-I, L.L.C. (incorporated by reference to Exhibit 10.42 to the Registrant’s Current Report onForm 8-K filed on July 15, 2005). |
| | 2 | .14 | | Asset Purchase Agreement dated July 11, 2005 between AirComp LLC, W.T. Enterprises, Inc. and William M. Watts (incorporated by reference to Exhibit 10.43 to the Registrant’s Current Report onForm 8-K filed on July 15, 2005). |
| | 2 | .15 | | Asset Purchase Agreement by and between Patterson Services, Inc. and Allis-Chalmers Tubular Services, Inc. (incorporated by reference to Exhibit 10.44 to the Registrant’s Current Report onForm 8-K filed on September 8, 2005). |
97
| | | | | |
Exhibit | | Description |
| |
| | 2 | .16 | | Stock Purchase Agreement dated as of December 20, 2005 between the Registrant and Joe Van Matre (incorporated by reference to Exhibit 10.33 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2005). |
| | 2 | .17 | | Stock Purchase Agreement, dated as of April 27, 2006, by and among Bridas International Holdings Ltd., Bridas Central Company Ltd., Associated Petroleum Investors Limited, and the Registrant. (incorporated by reference to Exhibit 2.3 to the Registrant’s Quarterly Report onForm 10-Q for the quarter ended March 31, 2006). |
| | 2 | .18 | | Stock Purchase Agreement, dated as of October 17, 2006, by and between Allis-Chalmers Production Services, Inc. and Randolph J. Hebert (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on October 19, 2006). |
| | 2 | .19 | | Asset Purchase Agreement, dated as of October 25, 2006, by and between Allis-Chalmers Energy Inc. and Oil & Gas Rental Services, Inc. (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on October 26, 2006). |
| | 2 | .20 | | Agreement and Plan of Merger by and among the Registrant, Bronco Drilling Company, Inc. and Elway Merger Sub, Inc., dated as of January 23, 2008 (incorporated by reference to Exhibit 2.1 to the Registrant’sForm 8-K filed on January 24, 2008). |
| | 3 | .1 | | Amended and Restated Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2001). |
| | 3 | .2 | | Certificate of Designation, Preferences and Rights of theSeries A 10% Cumulative Convertible Preferred Stock($.01 Par Value) of Registrant (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report onForm 8-K filed February 21, 2002). |
| | 3 | .3 | | Amended and Restated By-laws of Registrant (incorporated by reference to Exhibit 3.3. to the Registrant’s Annual Report ofForm 10-K for the year ended December 31, 2001). |
| | 3 | .4 | | Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on June 9, 2004 (incorporated by reference to Exhibit 3.3 to the Registrant’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004). |
| | 3 | .5 | | Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on January 5, 2005 (incorporated by reference to Exhibit 3.5 to the Registrant’s Current Report onForm 8-K filed January 11, 2005). |
| | 3 | .6 | | Certificate of Amendment of Certificate of Incorporation filed with the Delaware Secretary of State on August 16, 2005 (incorporated by reference to Exhibit 3.5 to the Registrant’s Current Report onForm 8-K filed August 17, 2005). |
| | 4 | .1 | | Specimen Stock Certificate of Common Stock of Registrant (incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004). |
| | 4 | .2 | | Registration Rights Agreement dated as of March 31, 1999, by and between Allis-Chalmers Corporation and the Pension Benefit Guaranty Corporation (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report onForm 10-Q for the quarter ended June 30, 1999). |
| | 4 | .3 | | Registration Rights Agreement dated April 2, 2004 by and between Registrant and the Stockholder signatories thereto (incorporated by reference to Exhibit 10.43 to Amendment No. 1 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2003). |
| | 4 | .4 | | Registration Rights Agreement dated as of January 29, 2007 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report onForm 8-K filed on January 29, 2007). |
| | 4 | .5 | | Registration Rights Agreement dated as of January 18, 2006 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report onForm 8-K filed on January 24, 2006). |
| | 4 | .6 | | Registration Rights Agreement dated as of August 14, 2006 by and among the Registrant, the guarantors listed on Schedule A thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on August 14, 2006). |
98
| | | | | |
Exhibit | | Description |
| |
| | 4 | .7 | | Indenture dated as of January 18, 2006 by and among the Registrant, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report onForm 8-K filed on January 24, 2006). |
| | 4 | .8 | | First Supplemental Indenture dated as of August 11, 2006 by and among Allis-Chalmers GP, LLC, Allis-Chalmers LP, LLC, Allis-Chalmers Management, LP, Rogers Oil Tool Services, Inc., the Registrant, the other Guarantors (as defined in the Indenture referred to therein) and Wells Fargo Bank, N.A (incorporated by reference to Exhibit 4.2 to the Registrant’sForm 8-K filed on August 14, 2006). |
| | 4 | .9 | | Second Supplemental Indenture dated as of January 23, 2007 by and among Petro-Rentals, Incorporated, the Registrant, the other Guarantor parties thereto and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on January 24, 2007). |
| | 4 | .10 | | Indenture, dated as of January 29, 2007, by and among the Registrant, the Guarantors named therein and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report onForm 8-K filed on January 29, 2007). |
| | 4 | .11 | | Form of 9.0% Senior Note due 2014 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Registrant’s Current Report onForm 8-K filed on January 24, 2006). |
| | 4 | .12 | | Form of 8.5% Senior Note due 2017 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Registrant’s Current Report onForm 8-K filed on January 29, 2007). |
| | 10 | .1 | | Amended and Restated Retiree Health Trust Agreement dated September 14, 1988 by and between Registrant and Wells Fargo Bank (incorporated by reference toExhibit C-1 of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report onForm 8-K dated December 1, 1988). |
| | 10 | .2 | | Amended and Restated Retiree Health Trust Agreement dated September 18, 1988 by and between Registrant and Firstar Trust Company (incorporated by reference toExhibit C-2 of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report onForm 8-K dated December 1, 1988). |
| | 10 | .3 | | Product Liability Trust Agreement dated September 14, 1988 by and between Registrant and Bruce W. Strausberg, Trustee (incorporated by reference to Exhibit E of the First Amended and Restated Joint Plan of Reorganization dated September 14, 1988 included in Registrant’s Current Report onForm 8-K dated December 1, 1988). |
| | 10 | .4* | | Allis-Chalmers Savings Plan (incorporated by reference to Registrant’s Annual Report onForm 10-K for the year ended December 31, 1988). |
| | 10 | .5* | | Allis-Chalmers Consolidated Pension Plan (incorporated by reference to Registrant’s Annual Report onForm 10-K for the year ended December 31, 1988). |
| | 10 | .6 | | Agreement dated as of March 31, 1999 by and between Registrant and the Pension Benefit Guaranty Corporation (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report onForm 10-Q for the quarter ended June 30, 1999). |
| | 10 | .7 | | Letter Agreement dated May 9, 2001 by and between Registrant and the Pension Benefit Guarantee Corporation (incorporated by reference to Registrant’s Quarterly Report onForm 10-Q for the quarter ended March 31, 2002). |
| | 10 | .8 | | Termination Agreement dated May 9, 2001 by and between Registrant, the Pension Benefit Guarantee Corporation and others (incorporated by reference to Registrant’s Current Report onForm 8-K filed on May 15, 2002). |
| | 10 | .9* | | Executive Employment Agreement, dated April 1, 2007, by and between the Registrant and Munawar H. Hidayatallah (incorporated by reference to Exhibit 10.3 to the Registrant’sForm 8-K filed on November 6, 2007). |
| | 10 | .10* | | Executive Employment Agreement, effective April 3, 2007, by and between the Registrant and Victor M. Perez (incorporated by reference to Exhibit 10.4 to the Registrant’sForm 8-K filed on November 6, 2007). |
99
| | | | | |
Exhibit | | Description |
| |
| | 10 | .11* | | Executive Employment Agreement, effective July 1, 2007, by and between the Registrant and Terrence P. Keane (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on July 24, 2007). |
| | 10 | .12* | | Executive Employment Agreement, dated December 3, 2007, by and between the Registrant and Theodore F. Pound III (incorporated by reference to Exhibit 10.2 to the Registrant’sForm 8-K filed on December 6, 2007). |
| | 10 | .13* | | Executive Employment Agreement, effective July 1, 2007, by and between the Registrant and David K. Bryan (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on July 13, 2007). |
| | 10 | .14* | | Employment Agreement, dated December 18, 2006, by and between the Registrant and Burt A. Adams (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report onForm 8-K filed on December 19, 2006). |
| | 10 | .15* | | Executive Employment Agreement, effective January 1, 2008, by and between the Registrant and Mark C. Patterson (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on February 25, 2008). |
| | 10 | .16 | | Purchase Agreement dated as of January 12, 2006 by and among Allis-Chalmers Energy Inc, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on January 24, 2006). |
| | 10 | .17 | | Purchase Agreement dated as of August 8, 2006 by and between the Registrant, the guarantors listed on Schedule B thereto and RBC Capital Markets Corporation (incorporated by reference to Exhibit 10.4 to the Registrant’sForm 8-K filed on August 14, 2006). |
| | 10 | .18 | | Purchase Agreement dated as of January 24, 2007 by and among Allis-Chalmers Energy Inc., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on January 29, 2007). |
| | 10 | .19 | | Amended and Restated Credit Agreement dated as of January 18, 2006 by and among Allis-Chalmers Energy Inc., as borrower, Royal bank of Canada, as administrative agent and Collateral Agent, RBC Capital Markets, as lead arranger and sole bookrunner, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report onForm 8-K filed on January 24, 2006). |
| | 10 | .20 | | First Amendment to Amended and Restated Credit Agreement dated as of August 8, 2006, by and among the Registrant, the guarantors named thereto and Royal Bank of Canada (incorporated by reference to Exhibit 10.3 to the Registrant’sForm 8-K filed on August 14, 2006). |
| | 10 | .21 | | Senior Unsecured Bridge Loan Agreement, dated December 18, 2006, by and among the Registrant, Royal Bank of Canada, as administrative agent, RBC Capital Markets Corporation, as exclusive lead arranger and sole bookrunner, and the guarantors and institutional lenders named thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report onForm 8-K filed on December 19, 2006). |
| | 10 | .22 | | Strategic Agreement dated July 1, 2003 between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.13 to the Registrant’s Quarterly Report onForm 10-Q filed on December 29, 2006). |
| | 10 | .23 | | Amendment No. 1 dated May 18, 2005 to Strategic Agreement between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.14 to the Registrant’s Quarterly Report onForm 10-Q filed on December 29, 2006). |
| | 10 | .24 | | Amendment No. 2 dated January 1, 2006 between Pan American Energy LLC Sucursal Argentina and DLS Argentina Limited Sucursal Argentina (incorporated by reference to Exhibit 10.15 to the Registrant’s Quarterly Report onForm 10-Q filed on December 29, 2006). |
| | 10 | .25 | | Investor Rights Agreement, dated December 18, 2006, by and between the Registrant and Oil & Gas Rental Services, Inc. (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report onForm 8-K filed on December 19, 2006). |
100
| | | | | |
Exhibit | | Description |
| |
| | 10 | .26 | | Investors Rights Agreement dated as of August 18, 2006 by and among the Registrant and the investors named on Exhibit A thereto (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on August 14, 2006). |
| | 10 | .27* | | 2003 Incentive Stock Plan (incorporated by reference to Exhibit 4.12 to the Registrant’s Current Report onForm 8-K filed August 17, 2005). |
| | 10 | .28* | | Form of Option Certificate issued pursuant to 2003 Incentive Stock Plan (incorporated by reference to Exhibit 10.41 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2003). |
| | 10 | .29* | | 2006 Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .30* | | Form of Employee Restricted Stock Agreement pursuant to the Registrant’s 2006 Incentive Plan (incorporated by reference to Exhibit 10.2 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .31* | | Form of Employee Nonqualified Stock Option Agreement pursuant to the Registrant’s 2006 Incentive Plan (incorporated by reference to Exhibit 10.3 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .32* | | Form of Employee Incentive Stock Option Agreement pursuant to the Registrant’s 2006 Incentive Plan (incorporated by reference to Exhibit 10.4 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .33* | | Form of Non-Employee Director Restricted Stock Agreement pursuant to the Registrant’s 2006 Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .34* | | Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Registrant’s 2006 Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant’sForm 8-K filed on September 18, 2006). |
| | 10 | .35* | | Form of Performance Award Agreement pursuant to the Registrants’ 2006 Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’sForm 8-K filed on November 6, 2007). |
| | 10 | .36 | | Second Amended and Restated Credit Agreement, dated as of April 26, 2007, by and among the Registrant, as borrower, Royal Bank of Canada, as administrative agent and collateral agent, RBC Capital Markets, as lead arranger and sole bookrunner, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on May 10, 2007). |
| | 10 | .37 | | First Amendment to Second Amended and Restated Credit Agreement, dated as of December 3, 2007, by and among the Registrant, the guarantors named thereto, Royal Bank of Canada and the lenders named thereto (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on December 6, 2007). |
| | 10 | .38 | | Amended and Restated Guaranty, dated April 26, 2007, by each of the guarantors named thereto in favor of Royal Bank of Canada, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’sForm 8-K filed on May 10, 2007). |
| | 10 | .39 | | Amended and Restated Pledge and Security Agreement, dated April 26, 2007, by the Registrant in favor of Royal Bank of Canada, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.3 to the Registrant’sForm 8-K filed on May 10, 2007). |
| | 10 | .40 | | Credit Agreement, dated January 31, 2008, among the Registrant, as lender, BCH Ltd., as borrower, and BCH Energy do Brasil Servicos de Petroleo Ltda., as guarantor (incorporated by reference to Exhibit 10.1 to the Registrant’sForm 8-K filed on February 6, 2008). |
| | 10 | .41 | | Option to Purchase and Governance Agreement, dated January 31, 2008, among the Registrant, BrazAlta Resources Corp. and BCH Ltd. (incorporated by reference to Exhibit 10.2 to the Registrant’sForm 8-K filed on February 6, 2008). |
| | 10 | .42 | | Subordination Agreement, dated January 31, 2008, among the Registrant, Standard Bank PLC, BCH Ltd., BCH Energy do Brasil Servicos de Petroleo Ltda. and BrazAlta Resources Corp. (incorporated by reference to Exhibit 10.3 to the Registrant’sForm 8-K filed on February 6, 2008). |
101
| | | | | |
Exhibit | | Description |
| |
| | 10 | .43 | | Form of Convertible Subordinated Secured Debenture (incorporate by reference to Schedule E to Exhibit 10.1 to the Registrant’sForm 8-K filed on February 6, 2008). |
| | 10 | .44* | | Agreement, dated April 1, 2007, by and between the Registrant and David Wilde (incorporated by reference to Exhibit 99.1 to the Registrant’sForm 8-K filed on April 3, 2007). |
| | 21 | .1 | | Subsidiaries of Registrant. |
| | 23 | .1 | | Consent of UHY LLP. |
| | 31 | .1 | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 31 | .2 | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 32 | .1 | | Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| | |
| * | | Compensation Plan or Agreement |
102
