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As filed with the Securities and Exchange Commission on August 15, 2008
Registration No. 333-142174
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 4 TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Stallion Oilfield Services, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 1389 | 72-1618455 | ||
(State or other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification No.) |
950 Corbindale, Suite 300
Houston, Texas 77024
(713) 528-5544
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Craig M. Johnson
Chief Executive Officer
950 Corbindale, Suite 300
Houston, Texas 77024
(713) 528-5544
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
Vinson & Elkins L.L.P. First City Tower, Suite 2500 1001 Fannin Street Houston, Texas 77002 (713) 758-2222 Attn: T. Mark Kelly Attn: Christopher S. Collins | Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 (713) 229-1234 Attn: R. Joel Swanson Attn: Felix P. Phillips |
Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, please check the following box. ¨
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
Subject to Completion, dated August 15, 2008
PROSPECTUS
Shares
Common Stock
This is the initial public offering of Stallion Oilfield Services, Inc. common stock. We are offering shares of our common stock and the selling stockholders, including members of our senior management, are offering shares of our common stock in this initial public offering. No public market currently exists for our common stock. We will not receive any of the proceeds from the shares of our common stock sold by the selling stockholders.
We have applied for listing of our common stock on The NASDAQ Stock Market LLC under the symbol “SOFS.” We currently estimate that the initial public offering price will be between $ and $ per share.
We intend to use the net proceeds received by us in this offering to repay our bridge loan facility in full and to repay a portion of our credit facility. An affiliate of Credit Suisse Securities (USA) LLC is the sole lender under our bridge loan facility and affiliates of Lehman Brothers Inc., UBS Securities LLC and Credit Suisse Securities (USA) LLC are lenders under our credit facility and, as such, they will receive substantially all of the net proceeds received by us in this offering. See “Underwriting—Other Relationships/FINRA Rules.”
Investing in our common stock involves risk. See “Risk Factors” beginning on page 12.
Per Share | Total | |||
Public offering price | $ | $ | ||
Underwriting discounts and commissions | $ | $ | ||
Proceeds to the Company (before expenses) | $ | $ | ||
Proceeds to the selling stockholders (before expenses) | $ | $ |
We have granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than shares of common stock in this offering.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
Lehman Brothers, on behalf of the underwriters, expects to deliver the shares on or about , 2008
LEHMAN BROTHERS | CREDIT SUISSE | UBS INVESTMENT BANK |
RAYMOND JAMES
, 2008
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Dealer Prospectus Delivery Obligation
Until , 2008, 25 days after the date of this prospectus, all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
ABOUT THIS PROSPECTUS
You should rely only on the information contained in this prospectus or any free writing prospectus we may authorize to be delivered to you. We and the selling stockholders have not authorized any other person to provide you with information different from that contained in this prospectus. We and the selling stockholders are only offering to sell, and only seeking offers to buy, the common stock in jurisdictions where offers and sales are permitted.
The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock. Our business, financial condition, results of operations and prospects may have changed since that date.
This prospectus includes market share and industry data and forecasts that we obtained from internal company surveys, market research, consultant surveys, publicly available information and industry publications and surveys. We believe the information included in this prospectus from market research, consultant surveys and industry publications and surveys is reliable.
Non-GAAP Financial Measures
The body of accounting principles generally accepted in the United States of America is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, as one that purports to measure historical or future financial performance, financial position or cash flow, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In this prospectus, we disclose EBITDA, a non-GAAP financial measure. EBITDA is calculated as net income (loss) before interest expense, taxes, depreciation and amortization. EBITDA is not a substitute for GAAP measures of earnings and cash flow. EBITDA is included in this prospectus because our management considers it an important supplemental measure of our performance and believes that it is frequently used by security analysts, investors and other interested parties in the evaluation of companies in our industry, some of which present EBITDA when reporting their results.
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This summary highlights selected information in this prospectus, but it does not contain all of the information that you should consider before deciding to invest in our common stock. You should read this entire prospectus carefully, including the “Risk Factors” section and our historical financial statements and pro forma financial data, which are included elsewhere in this prospectus.
Unless otherwise indicated or the context otherwise requires, (i) the information contained in this prospectus assumes that the underwriters’ option to purchase additional shares is not exercised, (ii) the information contained in this prospectus relating to us assumes the completion of the Restructuring as described under the caption “The Restructuring” below and (iii) references in this prospectus to “Stallion,” “we,” “us” and “our” are references to Stallion Oilfield Services, Inc. together with all of its subsidiaries subsequent to the Restructuring and are references to our predecessor entities and their respective subsidiaries prior to the Restructuring.
Our Company
We are a growth-oriented oilfield service company that provides comprehensive wellsite support services and production & logistics services to exploration and production companies and drilling contractors throughout the United States. Our company slogan,Everything but the RigSM, reflects our business strategy of providing a broad and comprehensive range of critical services to support wellsite operations, including onshore and offshore workforce accommodations, surface equipment rental, communications services, solids control, production services, wellsite construction, rig relocation and heavy equipment hauling. Our service offerings are designed to improve living and working conditions at the wellsite, wellsite safety and our customers’ drilling and production operations. We currently focus on oil and natural gas regions within North America that we believe have stable oil and gas drilling activity and which provide attractive long-term potential for growth, including South Texas, the Gulf Coast, ArkLaTex, the Fort Worth Basin, the Permian Basin, the Mid-Continent, Rocky Mountain and Appalachian Basin regions and Prudhoe Bay, Alaska. We also supply offshore workforce accommodations and related equipment for use in the Gulf of Mexico and, to a lesser extent, other international offshore regions. We provide services to a diverse group of over 3,000 customers. The Glossary of Terms included as Appendix A to this prospectus contains a description of some of these regions and a map of these regions appears at the end of the appendix.
Our services span the entire life-cycle of the land-based wellsite—wellsite preparation, rig deployment, drilling activities, production activities and decommissioning. We are typically the first service provider on the wellsite, as we assist in the initial preparation of the wellsite and often haul the rig and related heavy equipment onto the wellsite using our fleet of tractor trucks, trailers, pole trucks and cranes. Throughout the drilling and completion phases of a land-based well, we provide rental equipment and required support services to the wellsite. We also, in some cases, provide continuing support services during the production phase of the well, including the construction of production facilities and well connections to existing pipeline infrastructure. In addition, we manufacture oilfield equipment used in drilling and production activities, including frac tanks and other containment equipment. We frequently are the last service provider to leave the wellsite as we perform production facility disassembly and wellsite restoration, which are the last phases of the wellsite decommissioning process. In addition, our offshore workforce accommodations business serves our offshore customers during many phases of the offshore drilling and production life-cycle.
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Our business is comprised of two segments:
Wellsite Support Services. Through our wellsite support services segment, we offer integral services used by oil and natural gas companies, drilling contractors and other wellsite service providers to support wellsite operations. In 2007, this segment generated pro forma revenue of approximately $222.7 million. See “Unaudited Pro Forma Consolidated Financial Data.” This segment includes the following primary service lines:
• | Workforce accommodations. We provide onshore workforce accommodations in the United States with, as of July 31, 2008, approximately 2,400 transportable units in our inventory. Our fleet of land-based units is designed to accommodate various personnel on wellsite locations before, during and after drilling operations. In addition, we design, manufacture, lease and repair offshore workforce accommodation structures, which include units certified by the U.S. Coast Guard and/or the International Convention for the Safety of Life at Sea, 1974, the paramount international treaty concerning the safety of merchant ships (“SOLAS”). Our workforce accommodation units are specifically configured to provide transportable, comfortable living quarters and functional workspaces. |
• | Surface equipment rental. We provide a variety of surface rental equipment used in and critical to wellsite activities including forklifts, manlifts, power generators, compressors, loaders and water systems. |
• | Communications services. We provide integrated communications services through ourStaRCommTM/SM satellite system that provides wireless communications via intercoms and telephone, fax and internet/data services throughout the wellsite location. |
• | Solids control. We provide customized solids control services, closed-loop mud systems and fluid recovery services to help maximize our customers’ operating efficiency at the wellsite. We provide high-quality shakers, mud conditioners, centrifuges and peripheral backside equipment, as well as solids removal and waste handling coordination services. |
Production & Logistics Services. Through our production & logistics services segment, we offer services that are critical to establish, maintain and decommission the wellsite, position key equipment prior to, during and after drilling operations and provide fluid logistics and services for drilling, completion and production activities. In 2007, this segment generated pro forma revenue of approximately $287.8 million. See “Unaudited Pro Forma Consolidated Financial Data.” This segment includes the following primary service lines:
• | Production services. We provide a fleet of vacuum and winch trucks, frac tanks, saltwater injection wells and other assets used for fluid provision, transportation and disposal services. These specialized assets allow our customers to obtain, move, store and dispose of fluids that are involved in the development and production of the well. In addition, we manufacture oilfield equipment used in drilling and production activities, such as frac tanks and other containment equipment. |
• | Wellsite construction. We provide construction equipment and services to build and reclaim infrastructure at wellsites before, during and after drilling operations. Our services include wellsite clearing, road construction, mat placement, production facility assembly and construction, pipeline installation, pit remediation, production decommissioning and wellsite restoration. We provide services for wellsites in both land and inland marine environments. |
• | Rig relocation and heavy equipment hauling. We provide a fleet of tractor trucks, trailers, pole trucks and cranes used for the demobilization, relocation and mobilization of drilling rigs and related heavy equipment. We maintain a focus on providing reliable, efficient and safe transportation services. |
Wellsite support services and production & logistics services are critical to establish and operate the land-based wellsite. We believe our scale, access to capital and our ability to provide a single supply source for many
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of our customers’ needs are strengths of our business. In addition, we provide offshore workforce accommodations to exploration and production companies in the Gulf of Mexico and, to a lesser extent, other international offshore regions.
Recent Industry Trends
In recent years, our industry has experienced higher demand for oil and natural gas and a constrained oil and natural gas supply, resulting in higher commodity prices and increased drilling activity. We believe this trend of increased natural gas prices and drilling activity, as well as other industry trends reflected below, will benefit us and facilitate implementation of our business strategy:
• | Increase in drilling and developing unconventional resources. The decline of conventional North American oil and natural gas reservoirs is leading to a shift toward the drilling and development of onshore unconventional oil and natural gas resources, including tight sands, shales and coalbed methane. We believe the increased drilling requirements of these unconventional resources will lead to continued drilling activity. |
• | Increase in fluids used in unconventional horizontal well completions. Completions of unconventional horizontal wells in the Barnett Shale region of the Fort Worth Basin require fresh water. The amount of fresh water used for such completions is significantly greater than the amount of fresh water used for completions of vertical wells. Correspondingly, these unconventional horizontal wells also produce significantly greater quantities of saltwater that must be disposed in permitted disposal wells. |
• | Labor shortages and increasing safety concerns. Due to the increase in the demand for labor in the oilfield and offshore, our customers continue to attempt to improve living and working conditions at the wellsite to help retain employees. Our customers also continue to enhance their safety procedures to help reduce injuries and to help ensure compliance with more stringent regulatory requirements. |
• | Increasingly complex technologies. The increasing complexity of technology used in the oil and natural gas development process requires a greater number of technicians on location during drilling and, therefore, additional workforce accommodations. |
• | Geographically dispersed drilling operations. With the shift toward consolidation in the land drilling industry, land crews based in one region may accompany a rig to work on wellsites in geographically dispersed oil and natural gas regions a significant distance away from the home office. This development has resulted in the need for full-time accommodations for multiple shifts of the rig crew. |
• | Environmental sensitivity. In response to increasing regulation and environmental sensitivity, onshore wellsite operators are utilizing closed-loop solids control systems to help reduce onsite discharge of drilling fluids and cuttings in environmentally sensitive areas and when working with oil-based and synthetic drilling fluids. These systems require customized solids control configurations to maximize drilling fluid efficiency. |
• | Outsourcing ancillary services. Some of the services we provide have been historically handled by drilling contractors themselves. In many instances, these services are only ancillary to the primary activity of drilling and completing wells and represent only a minor portion of the total well drilling cost. Many drilling contractors are increasingly electing to outsource these services to suppliers who can provide high-quality and reliable services. |
• | Increased deepwater development activity. Deepwater exploration and production activities are typically complex with long durations and require personnel involved in drilling, production and construction. Growth in these deepwater activities has resulted in the need for more workforce accommodations on offshore platforms. |
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Our Business Strategy
Our business strategy consists of the following core elements:
Establish and maintain a leadership position in our principal operating areas.We intend to continue to build upon our market positions in the areas in which we operate by offering a comprehensive and integrated package of services which allows us to provide our customers with wellsite support services required across their drilling locations. We view the incremental steps in achieving this to include:
• | Deploying our suite of services across existing land-based operating areas. We believe we have developed expertise in specific service lines which can be effectively marketed across the majority of our land-based operating areas. We intend to continue to roll-out our existing services across our current operating areas in an effort to deliver a comprehensive portfolio of services in each region. We believe our established customer base and strong regional relationships will continue to provide a strategic distribution network for our service deployment efforts. |
• | Continue to develop our offshore service offerings. We provide offshore workforce accommodations to exploration and production companies. We intend to expand our manufacturing capabilities and offshore service offerings to meet the growing needs of our customers. |
Extend our operations into new geographic areas.We intend to apply our expertise in wellsite support services and land-based production & logistics services in markets where we currently do not operate and which provide an attractive platform for future growth. We intend to continue to improve the ease with which our clients can use our services from one wellsite location to the next. We expect to support our customers’ entry into other active drilling regions by introducing our service offerings in those regions.
Broaden the suite of services we provide. We have established strong working relationships with our customers which provide us a stable base of operations. We work closely with our customers to define new service offerings that meet specific customer needs in the onshore markets where we operate and also intend to expand our offshore service offerings. We intend to continue to invest in developing or acquiring new high-quality assets and services which add to the breadth and quality of our service portfolio.
Focus on service quality, business performance and safety. Our management team is responsible for assessing our service quality, performance and safety compliance and coordinates with our field offices to help ensure that our quality and performance metrics and safety standards are met at every level of our organization. In addition to our internal safety policies, we adhere to certain external safety regulations, such as certifying certain of our offshore workforce accommodation units with the U.S. Coast Guard and/or SOLAS prior to deployment. We intend to continue to invest in and promote designs, systems and methodologies which improve the reliability, responsiveness, accountability and safety of our operations.
Continue to pursue strategic expansion opportunities.We believe that the markets in which we operate remain fragmented and that there are numerous consolidation opportunities within these markets. We completed 24 acquisitions in 2006 and 2007 and three acquisitions in 2008 and intend to continue pursuing strategic acquisitions which add to the scope and quality of our service portfolio. In evaluating such acquisitions, we consider a number of factors, including enhancing our current service offerings, geographic diversification, synergies with existing operations, financial performance and acquisition costs.
Capitalize on regional experience. One component of our acquisition and growth strategy is to acquire assets located in strategic operating areas that include personnel with strong local leadership and regional experience. We believe that by having the administrative functions previously performed at the regional level centralized in and
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handled by our corporate office, we have enhanced our controls environment and enabled our local management to focus on our customers, our employees and the effective management and deployment of our assets.
Expand our services internationally. Our offshore workforce accommodation business predominantly operates in the Gulf of Mexico. We intend to pursue strategic opportunities to expand our service offerings into other international offshore markets by leveraging our custom product design and existing customer base.
For further information on our business strategy, please read “Business—Our Business Strategy.”
Our Competitive Strengths
We believe our operations benefit from a number of competitive strengths, including the following:
• | Extensive breadth of service throughout the wellsite life-cycle. We provide a broad array of wellsite services throughout each phase of the land-based drilling and production process. This breadth of service strengthens our relationships with our customers and allows us to identify and cross-sell additional services. |
• | Extensive geographic footprint with a strong regional and local presence. Our regional operations are located in some of the most active onshore oil and natural gas drilling regions of the United States, including South Texas, the onshore Gulf Coast, ArkLaTex, the Fort Worth Basin, the Permian Basin, the Mid-Continent, Rocky Mountain and Appalachian Basin regions and Prudhoe Bay, Alaska. Within these regions, there were approximately 1,811 active land drilling rigs as of August 8, 2008. In addition, our products are utilized in certain offshore markets, including the Gulf of Mexico, and, to a lesser extent, other international offshore regions. Within the offshore Gulf of Mexico market, there were approximately 63 active offshore drilling rigs as of August 8, 2008. Our regional managers have developed strong relationships with our customers throughout their regions and are largely responsible for the sales, marketing and delivery of our services. |
• | Large scale of operations. We provide comprehensive land-based wellsite services in our operating areas. Our scale enables us to deliver a comprehensive range of reliable and high-quality wellsite services to our customers. |
• | Experienced management team with proven acquisition track record and control environment. Our senior management team has extensive experience in the oil and natural gas industry, with an average of 23 years of experience. We believe this background provides our management team with an in-depth understanding of our customers’ needs and enhances our ability to deliver customer driven solutions. Our management also has substantial experience in identifying, completing and integrating acquisitions and since our inception through July 31, 2008, we have acquired 37 businesses. We have also implemented a standardized control environment that includes accounting, safety, environmental and maintenance processes and controls. |
• | Leveraged to drilling activity. We believe that favorable supply and demand fundamentals will maintain the current level of drilling for oil and natural gas. Efforts to maintain current levels of production will necessitate continued drilling for the foreseeable future, which will sustain demand for our services. As our package of services typically comprises less than 15% of total drilling expenditures, our business has not historically experienced the pricing volatility experienced by drilling contractors, who represent a much larger portion of total drilling expenditures. |
• | Leadership position in the offshore workforce accommodation business. We provide U.S. Coast Guard and SOLAS certified offshore workforce accommodation units worldwide. We believe our history, our custom design and the quality of our products and services are strengths of our business. |
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Our Challenges
We face a number of challenges in implementing our business strategy. For example:
• | demand for the services we provide will likely be adversely affected by a prolonged substantial reduction in oil and natural gas prices; |
• | higher commodity prices, including fuel and steel prices, could cause our operating expenses to increase, which could negatively impact our margins; |
• | we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties, diminished financial performance or our inability to report financial results and may require a disproportionate amount of our management’s attention; |
• | increased competition in the markets where we operate may result in significant price competition that could have a material adverse effect on our operations; |
• | our ability to broaden the suite of services we provide will be diminished if we encounter difficulties associated with rapid growth and expansion; |
• | establishing and maintaining a leadership position in our principal operating areas may not be possible if we lose key members of our management team; |
• | expansion into new geographic areas, both domestically and internationally, will likely be limited if additional capital is not available to us; and |
• | our ability to focus on service quality, business performance and safety may be negatively impacted by the high rate of employee turnover in our industry and our inability to replace or add personnel. |
For a further discussion of these and other challenges we face, please read “Risk Factors.”
Risk Factors
You should carefully consider the matters described under “Risk Factors.” These risks could materially and adversely impact our business, financial condition, operating results and cash flows, which could cause the trading price of our common stock to decline and could result in a partial or total loss of your investment.
The Restructuring
We were formed as a Delaware corporation in June 2006. In connection with this offering, we will succeed to the business and operations of Stallion Oilfield Services, Ltd. (“Stallion Ltd.”), which are described in this prospectus. Prior to the completion of this offering, the limited partner owning 99.9% of Stallion Ltd., Stallion Oilfield Holdings, Ltd., (“Stallion Holdings, Ltd.”) will merge with and into Stallion Oilfield Services, Inc., with Stallion Oilfield Services, Inc. being the surviving corporate parent and owning all of the operating subsidiaries of Stallion Ltd. (the “Restructuring”). The majority owners of Stallion Holdings, Ltd. are C/R Stallion Investment Partnership, L.P. and C/R Energy Coinvestment II, L.P. (together, “Carlyle/Riverstone”) and an affiliate of Craig Johnson, our President, Chief Executive Officer and Chairman of the Board. Since the entities are under common ownership and control, the Restructuring will be accounted for at historical cost. In the
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Restructuring, assuming an initial public offering price of $ , which is the midpoint of the public offering price range set forth on the cover of this prospectus, the partners of Stallion Ltd. will receive an aggregate of shares of our common stock in exchange for all of the Stallion Ltd. partnership interests held by them. Immediately following completion of the Restructuring and prior to this offering, we will have shares of common stock outstanding, % of which will be owned by Carlyle/Riverstone and % of which will be owned by an affiliate of Craig Johnson.
For additional information about the Restructuring, please read “Certain Relationships and Related Party Transactions—The Restructuring.” Please see “Business—Corporate Structure” for a chart depicting our corporate structure following the Restructuring.
Our Executive Offices
Our principal executive offices are located at 950 Corbindale Road, Suite 300, Houston, Texas 77024. Our telephone number is (713) 528-5544. Information contained on or accessible from our website,www.stallionoilfield.com, is not part of this prospectus.
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The Offering
Common stock offered by us | shares or shares if the underwriters exercise in full their option to purchase additional shares of common stock |
Common stock offered by the selling stockholders | shares |
Common stock outstanding after this offering | shares or shares if the underwriters exercise in full their option to purchase additional shares of common stock |
Use of proceeds | We estimate that our net proceeds from this offering, after deducting underwriting discounts and commissions and estimated offering expenses, will be approximately $ million, assuming an initial public offering price of $ , which is the midpoint of the range set forth on the cover page of this prospectus. |
We intend to use the net proceeds we receive from this offering:
• | to repay approximately $252.5 million of indebtedness and prepayment premiums under our $250.0 million bridge loan facility; and |
• | to repay $ million of indebtedness under our credit facility. See “Use of Proceeds.” |
An affiliate of Credit Suisse Securities (USA) LLC is the sole lender under our bridge loan facility and affiliates of Lehman Brothers Inc., UBS Securities LLC and Credit Suisse Securities (USA) LLC are lenders under our credit facility and, as such, they will receive substantially all of the net proceeds received by us in this offering. See “Underwriting—Other Relationships/FINRA Rules.”
We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. The selling stockholders include members of our senior management. See “Principal and Selling Stockholders.” |
We plan to use any net proceeds we receive from the exercise of the underwriters’ option to purchase additional shares of common stock to repay indebtedness under our credit facility.
The NASDAQ Stock Market LLC symbol | “SOFS” |
Risk Factors | See “Risk Factors” beginning on page 12 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock. |
The number of shares of common stock that will be outstanding after the offering includes an aggregate of shares of restricted common stock anticipated to be issued on pricing of this offering to directors, officers and key employees under our 2008 Stock Incentive Plan and excludes an aggregate of shares of common stock reserved and available for future issuance under our 2008 Stock Incentive Plan.
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Summary Historical and Pro Forma Financial Information
The following table sets forth our summary historical consolidated financial and operating data as of the dates and for the periods shown. Our operations are currently conducted by Stallion Ltd., a limited partnership, and its operating subsidiaries. Immediately prior to the closing of this offering, this limited partnership will merge with and into Stallion Oilfield Services, Inc., and we will operate under a corporate parent structure. Stallion Oilfield Services, Inc., the surviving entity of the Restructuring, will serve as the parent holding company under this new structure. The amounts for each historical annual period presented below were derived from our audited consolidated financial statements. The unaudited pro forma consolidated statement of operations data for the year ended December 31, 2007 gives effect to the acquisitions of L.E.G. Rentals, Inc. and Fluid Processors, Inc. (together, “FPI”) (acquired May 31, 2007), the assets of various entities operating under the name Salty’s (together, “Salty’s”) (acquired August 1, 2007) and the assets of Polleyco Construction Services LP (“Polleyco”) (acquired January 1, 2008) as if each was acquired on January 1, 2007. The unaudited pro forma financial information does not purport to represent what our results would have been had the acquisitions of FPI, Salty’s and Polleyco been completed on the indicated date and should not be relied upon as indicative of what our future results may be. Results of FPI, Salty’s and Polleyco are included in our historical results of operations from their respective dates of acquisition. The following information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our consolidated financial statements and related notes and the unaudited pro forma consolidated financial data included elsewhere in this prospectus.
Stallion Oilfield Services Ltd. Historical Consolidated | Stallion Oilfield Services, Inc. Pro Forma Consolidated | |||||||||||||||||||||||||||||||
Year Ended December 31, | Six Months Ended June 30, | Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||||||||
Statement of Operations Data: | (in thousands, except per share amounts) | |||||||||||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||||||||||
Wellsite support services | $ | 6,769 | $ | 15,452 | $ | 73,126 | $ | 162,661 | $ | 215,265 | $ | 97,442 | $ | 126,220 | $ | 222,742 | ||||||||||||||||
Production & logistics services | — | — | — | 77,749 | 211,930 | 74,948 | 162,090 | 287,845 | ||||||||||||||||||||||||
Total revenue | 6,769 | 15,452 | 73,126 | 240,410 | 427,195 | 172,390 | 288,310 | 510,587 | ||||||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||||||
Wellsite support services | 3,108 | 8,695 | 42,281 | 88,029 | 118,029 | 53,512 | 72,001 | 120,293 | ||||||||||||||||||||||||
Production & logistics services | — | — | — | 52,679 | 151,526 | 52,376 | 121,400 | 185,925 | ||||||||||||||||||||||||
Selling, general and administrative | 2,145 | 3,745 | 9,883 | 19,170 | 40,027 | 17,191 | 20,935 | 57,935 | ||||||||||||||||||||||||
Depreciation and amortization | 836 | 1,924 | 7,798 | 30,068 | 62,743 | 24,659 | 36,516 | 72,751 | ||||||||||||||||||||||||
Loss on disposal of assets | 86 | 92 | 499 | 920 | 44 | 979 | (101 | ) | 44 | |||||||||||||||||||||||
Total expenses | 6,175 | 14,456 | 60,461 | 190,866 | 372,369 | 148,717 | 250,751 | 436,948 | ||||||||||||||||||||||||
Operating income | 594 | 996 | 12,665 | 49,544 | 54,826 | 23,673 | 37,559 | 73,639 | ||||||||||||||||||||||||
Interest expense, net | (489 | ) | (917 | ) | (4,565 | ) | (18,919 | ) | (52,874 | ) | (20,581 | ) | (34,558 | ) | (63,555 | ) | ||||||||||||||||
Other income (expense) | — | — | (66 | ) | 71 | 207 | 147 | 374 | 120 | |||||||||||||||||||||||
Income before taxes | 105 | 79 | 8,034 | 30,696 | 2,159 | 3,239 | 3,375 | 10,204 | ||||||||||||||||||||||||
Income tax (expense) benefit(1) | — | — | (598 | ) | (4,927 | ) | (6,410 | ) | (2,345 | ) | (5,805 | ) | 16,817 | |||||||||||||||||||
Net income (loss) | $ | 105 | $ | 79 | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | $ | 894 | $ | (2,430 | ) | $ | 27,021 | ||||||||||||||
Pro forma income tax (unaudited)(1) | $ | 40 | $ | 30 | $ | 3,053 | $ | 11,664 | $ | 820 | $ | 1,231 | $ | 1,283 | ||||||||||||||||||
Pro forma net income (unaudited)(1) | $ | 65 | $ | 49 | $ | 4,981 | $ | 19,032 | $ | 1,339 | $ | 2,008 | $ | 2,092 | ||||||||||||||||||
Earnings per share: | ||||||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||||||||||
Weighted average shares: | ||||||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||||||
Diluted |
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Stallion Oilfield Services Ltd. Historical Consolidated | ||||||||||||||||||||||||||||
Year Ended December 31, | Six Months Ended June 30, | |||||||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||||||
(unaudited) | ||||||||||||||||||||||||||||
Other Financial Data: | (in thousands) | |||||||||||||||||||||||||||
EBITDA(2) | $ | 1,430 | $ | 2,920 | $ | 20,397 | $ | 79,683 | $ | 117,776 | $ | 48,479 | $ | 74,449 | ||||||||||||||
Cash flow provided by operating activities | 144 | 1,734 | 7,087 | 41,124 | 58,264 | 49,463 | 38,701 | |||||||||||||||||||||
Cash flow used in investing activities | (7,536 | ) | (7,142 | ) | (83,462 | ) | (280,164 | ) | (496,785 | ) | (177,880 | ) | (80,816 | ) | ||||||||||||||
Cash flow provided by financing activities | 7,805 | 5,046 | 77,307 | 242,158 | 444,271 | 133,422 | 36,558 | |||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||
Acquisitions, net of cash acquired(3) | 5,608 | 1,158 | 47,191 | 178,045 | 388,091 | 112,839 | 23,377 | |||||||||||||||||||||
Property, plant and equipment | 2,046 | 5,961 | 35,951 | 92,029 | 122,291 | 75,870 | 61,325 |
Stallion Oilfield Services Ltd. Historical Consolidated | ||||||||||||||||||
As of December 31, | As of June 30, | |||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2008 | |||||||||||||
(unaudited) | ||||||||||||||||||
Balance Sheet Data: | (in thousands) | |||||||||||||||||
Cash and cash equivalents | $ | 412 | $ | 50 | $ | 982 | $ | 4,100 | $ | 9,850 | $ | 4,293 | ||||||
Property, plant and equipment | 7,131 | 13,899 | 74,583 | 220,777 | 433,355 | 469,682 | ||||||||||||
Total assets | 16,252 | 24,713 | 123,136 | 446,907 | 975,882 | | 1,032,188 | |||||||||||
Total debt | 11,705 | 18,552 | 67,795 | 257,539 | 724,732 | | 736,116 | |||||||||||
Total partners’ capital | 3,533 | 3,611 | 43,597 | 153,534 | 150,349 | | 179,106 |
(1) | Historically, we were not subject to taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Pro forma net income for the years ended December 31, 2003, 2004, 2005, 2006 and 2007 and the six months ended June 30, 2007 and 2008 includes a provision for taxes on our consolidated income before tax. Pro forma income tax expense has been computed at a blended state and federal tax rate of 38%, which represents the statutory rate, to reflect the pro forma income tax effect on net income (loss) for the periods presented assuming that the Restructuring happened on January 1, 2003. |
(2) | EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors and commercial banks, to assess: |
• | the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; |
• | the ability of our assets to generate cash sufficient to pay interest on our indebtedness; |
• | our operating performance and return on invested capital as compared to those of other companies in the oilfield service industry, without regard to financing methods and capital structure; and |
• | our compliance with certain financial covenants included in our credit facility. |
EBITDA has limitations as an analytical tool and should not be considered an alternative to net income (loss), operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). EBITDA excludes some, but not all, items that affect net income (loss) and operating income and these measures may vary among other companies. Limitations to using EBITDA as an analytical tool include: |
• | EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or capital commitments; |
• | EBITDA does not reflect changes in, or cash requirements necessary to service interest or principal payments on, our debt; |
• | although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and |
• | other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure. |
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The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the most directly comparable GAAP financial measure on a historical basis for each of the indicated periods. |
Year Ended December 31, | Six Months Ended June 30, | ||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||
(unaudited) | |||||||||||||||||||||||
Reconciliation of net income (loss) to EBITDA: | (in thousands) | ||||||||||||||||||||||
Net income (loss) | $ | 105 | $ | 79 | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | $ | 894 | $ | (2,430 | ) | |||||||
Income taxes | — | — | 598 | 4,927 | 6,410 | 2,345 | 5,805 | ||||||||||||||||
Interest expense | 489 | 917 | 4,565 | 18,919 | 52,874 | 20,581 | 34,558 | ||||||||||||||||
Depreciation and amortization | 836 | 1,924 | 7,798 | 30,068 | 62,743 | 24,659 | 36,516 | ||||||||||||||||
EBITDA | $ | 1,430 | $ | 2,920 | $ | 20,397 | $ | 79,683 | $ | 117,776 | $ | 48,479 | $ | 74,449 | |||||||||
(3) | Acquisitions, net of cash acquired, consists only of the cash component of acquisitions. It does not include equity and/or notes issued for acquisitions. |
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An investment in our common stock involves a high degree of risk. You should carefully consider the following risk factors, together with the other information contained in this prospectus, before deciding to invest in our common stock. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline, and you may lose all or part of your investment.
Risks Related to Our Business and Our Industry
Our business depends on domestic drilling activity and spending by the oil and natural gas industry in the United States. Our business may be adversely affected by industry conditions that are beyond our control.
We depend on our customers’ willingness to make expenditures to explore for and to develop and produce oil and natural gas in the United States. Our customers’ willingness to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which management has no control, such as:
• | the supply of and demand for oil and natural gas; |
• | long lead times associated with acquiring equipment and shortages of qualified personnel; |
• | the level of prices, and expectations about future prices, of oil and natural gas; |
• | the cost of exploring for, developing, producing and delivering oil and natural gas; |
• | the expected rates of declining current production; |
• | the discovery rates of new oil and natural gas reserves; |
• | available pipeline, storage and other transportation capacity; |
• | weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area; |
• | domestic and worldwide economic conditions; |
• | political instability in oil and natural gas producing countries; |
• | technical advances affecting energy consumption; |
• | the price and availability of alternative fuels; |
• | the ability of oil and natural gas producers to raise equity capital and debt financing; and |
• | merger and divestiture activity among oil and natural gas producers. |
The level of oil and natural gas exploration and production activity in the United States is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity then existing in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and, therefore, affect demand for the services we provide. A material decline in oil and natural gas prices or drilling activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, a decrease in the development rate of oil and natural gas reserves in our market areas may also have an adverse impact on our business, even in an environment of stronger oil and natural gas prices.
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A decline in or substantial volatility of oil and natural gas prices could adversely affect the demand for our services.
The demand for our services is primarily influenced by current and anticipated oil and natural gas prices and the related level of drilling activity and general production spending in the areas in which we have operations. Volatility or weakness in oil and natural gas prices (or the perception that oil and natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could result in lower demand for our services. As a result, we may experience lower utilization of, and may be forced to lower our rates for, our services and equipment. A decline in oil and natural gas prices or a reduction in drilling and production activities could have a material adverse affect on the demand for our services and our results of operations.
Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. For example, over the last four years, the WTI Cushing crude oil spot price has ranged from a low of $40.71 per bbl on December 10, 2004 to a high of $145.29 per bbl on July 3, 2008. As of August 8, 2008, the WTI Cushing crude oil spot price was $115.20 per bbl. The Henry Hub natural gas spot price has ranged from a low of $3.66 per mcf on September 29, 2006 to a high of $15.39 per mcf on December 13, 2005. As of August 8, 2008, the Henry Hub natural gas spot price was $8.22 per mcf. Producers generally react to declining oil and natural gas prices by reducing expenditures. This has in the past had, and may in the future have, an adverse effect on our business. Mild weather in January 2007 caused some declines in the price of oil and natural gas and we experienced some signs of softer demand for our services in the first quarter and early in the second quarter of 2007. We are unable to predict future oil and natural gas prices or the level of oil and natural gas industry activity. A prolonged low level of activity in the oil and natural gas industry will adversely affect both the demand for our products and services and our financial condition and results of operations.
When land-based rig counts are low, our rig relocation customers may not have a need for our services.
Many of the major United States drilling services contractors have significant capabilities to move their own land-based drilling rigs and related oilfield equipment and to mobilize rigs. When regional rig counts are high, drilling contractors often exceed their own capabilities and contract for additional oilfield equipment hauling and onshore rig mobilization capacity. Our rig relocation business activity is correlated to the onshore rig count; however, the correlation varies over the rig count range. The Baker Hughes U.S. onshore rotary rig count for the week ended August 8, 2008 was 1,901. As rig count declines, some drilling contractors reach a point where all of their oilfield equipment hauling and rig mobilization needs can be met by their own fleets. If one or more of our rig relocation customers decide not to outsource their rig and equipment hauling needs, our revenue attributable to rig relocation may decline much faster than the corresponding rig count. This relationship between our rig relocation business activity and the rig count in the areas where we have rig relocation operations can significantly increase the volatility of our earnings with respect to rig relocation.
Competition within the oilfield service industry may adversely affect our ability to market our services.
The oilfield service industry is competitive and fragmented and includes numerous small companies capable of competing in our markets on a local basis as well as several large companies that possess substantially greater financial and other resources than us. Our larger competitors’ greater resources could allow them to compete more effectively than us. Barriers to entry in many of our areas of operation are minimal and our competitors may offer products and services at a relatively low cost. We believe that the principal competitive factors in the market areas that we serve are quality of product and service, price, availability and technical proficiency. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics, or that better address environmental concerns, than our products and services. Competitive pressures, excess capacity in our industry or other factors also may result in significant price competition that could have a material adverse effect on our results of operations and financial condition. Finally, competition among oilfield service and equipment providers is also affected by each provider’s reputation for safety and quality. If our safety record or the quality of our service declines or we are unable to compete effectively, we may not be able to maintain our competitive position.
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Fuel prices or disruptions in fuel supplies could have a material adverse effect on us.
Expenditures for fuel represent a major cost of operating our business. Our operations depend on the availability of fuel supplies, and our financial results may be significantly impacted by changes in the cost of fuel. Historically, we have been unable to pass along these increased costs to our customers in the form of higher prices, and we may be unable to do so in the future. Fuel prices and supplies are influenced significantly by international political and economic circumstances, such as increasing demand by developing nations, conflicts or instability in the Middle East or other oil producing regions and diplomatic tensions between the U.S. and oil producing nations, as well as OPEC production curtailments, disruptions of oil imports, environmental concerns, weather, refinery outages or maintenance and other unpredictable events. Increases in fuel prices, high fuel prices or disruptions in fuel supplies could have a material adverse effect on our business, results of operations and financial condition.
We may not be able to manage future growth successfully, to grow successfully through future acquisitions, or to integrate the businesses we do acquire effectively.
Our business strategy has included, and will continue to include, growth through the acquisition of other businesses. In 2006, we acquired 11 businesses for a total purchase consideration of approximately $206.6 million. In 2007, we acquired 13 businesses for a total purchase consideration of approximately $396.2 million, subject to certain purchase price adjustments. In the first six months of 2008, we acquired two businesses for a total initial purchase price of approximately $22.6 million. In addition to the initial purchase price for one of these acquisitions, Polleyco, we may owe up to $12.0 million per year over a three-year period in contingent consideration if certain financial performance targets are met. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets on terms favorable to us. Competition for acquisition opportunities is substantial and may escalate, increasing our cost of making future acquisitions or causing us to refrain from making acquisitions. We may be required to incur substantial indebtedness to finance future acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. Our credit facility and indenture require that we meet certain financial covenants in order to borrow money to fund future acquisitions. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties, diminished financial performance or our inability to report financial results and may require a disproportionate amount of our management’s attention. For example, if we are unable to effectively apply systems and controls to acquired businesses, including internal controls, the availability or timeliness of financial reports could be materially reduced.
We are vulnerable to the potential difficulties associated with rapid growth and expansion.
We have grown rapidly over the last several years through organic growth and acquisitions of other companies. Since our inception through July 31, 2008, we have acquired 37 businesses, 27 of which have been acquired since January 1, 2006. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
• | lack of sufficient executive-level personnel; |
• | increased administrative burden; |
• | increased organizational challenges common to large, expansive operations; and |
• | long lead times associated with acquiring equipment. |
Our operating results could be adversely affected if we do not successfully manage these potential difficulties.
Our operating history may not be sufficient for investors to evaluate our business and prospects.
The historical financial information incorporated herein is not necessarily indicative of the results that would have been achieved had we operated on a fully integrated basis or the results of that may be realized in the
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future. We have a short operating history. In addition, we have grown significantly over the last few years through acquisitions. This may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results. Our future results will depend on our ability to efficiently manage our integrated operations and execute our business strategy.
We may require additional capital in the future, which may not be available to us.
Our acquisition strategy requires significant capital. In addition, our business is capital intensive, requiring specialized equipment and trained personnel to provide our services. We may need to raise additional funds through public or private debt or equity financings. Adequate funds may not be available when needed or may not be available on favorable terms. If funding is insufficient at any time in the future, we may be unable to service our equipment, fund acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business. Our future capital requirements primarily depend on the frequency, timing, size and success of our acquisitions.
We depend on significant customers.
We derive a significant amount of our revenue from exploration and production companies and drilling contractors who are active in our markets. For the year ended December 31, 2007 and the six months ended June 30, 2008, our top ten customers accounted for approximately 31.5% and 31.1%, respectively, of our total revenue. During 2006, Devon Energy Corporation accounted for approximately 10.5% of our total revenue. For the year ended December 31, 2007 and the six months ended June 30, 2008, no customer accounted for more than 10% of our total revenue. Our inability to continue to perform services for a number of our large existing customers could have a material adverse effect on our business and operations.
Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.
We depend to a large extent on the services of some of our executive officers and directors. We may not be able to retain our executive officers and may not be able to enforce the non-compete provisions in their employment agreements. The loss of the services of our executive officers, directors, or other key personnel could disrupt and adversely affect our operations. Please see “Executive Compensation—Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table—Employment Agreements.”
Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could adversely affect our business.
We may not be able to find enough skilled labor to meet our needs, which could limit our growth. The oilfield service business has been cyclical in the past and is heavily influenced by oil and natural gas prices. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. We believe that our success is dependent upon our ability to continue to employ, train and retain skilled personnel. The demand for skilled workers is high, and the supply is limited, particularly in the Rocky Mountain region, which is one of our key regions. It is possible that we will have to raise wage rates to attract workers from other fields and to retain or expand our current work force. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our operating results may be adversely affected. Our inability to employ, train or retain skilled personnel generally could have a material adverse effect on our results of operations.
Our operations are subject to hazards inherent in the oil and natural gas industry.
Through our wellsite construction services, we operate cranes, forklifts, bulldozers and other heavy equipment. In addition, in connection with providing rig logistics services, we transport land-based drilling rigs
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and related equipment through the use of our heavy hauler trucks and trailers, cranes and other trucking and relocation assets. The operation of heavy equipment at the wellsite and the transportation of rigs and related assets may result in accidents, which can cause personal injury, loss of life, suspension of operations, damage to facilities and damage to or destruction of property. These and other operational risks inherent in our industry could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. The frequency and severity of such incidents will affect our operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable, which could cause us to lose customers and substantial revenue.
We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable, and there can be no assurance that insurance will be available to cover any or all of these risks, or, even if available, that it will be adequate or that insurance premiums or other costs will not rise significantly in the future, so as to make such insurance costs prohibitive. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. See “Business—Operating Risks and Insurance.”
We are subject to federal, state and local regulation regarding issues of health, safety and protection of the environment. Under these regulations, we may become liable for penalties, damages or costs of remediation. Any changes in laws and government regulations could increase our costs of doing business.
Our operations are subject to federal, state and local laws and regulations relating to protection of natural resources and the environment, health and safety, waste management, and transportation of waste and other materials. Liability under these laws and regulations could result in cancellation of landbased wellsite or offshore operations, fines and penalties, expenditures for remediation and liability for property damages and personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include assessment of administrative, civil and criminal penalties, revocation of permits and issuance of corrective action orders. As part of our business, we handle, transport and dispose of a variety of fluids and substances used or produced by our customers in connection with their oil and gas exploration and production activities. We also generate and dispose of hazardous waste. The generation, handling, transportation, and disposal of these fluids, substances, and waste are regulated by a number of laws, including the Resource Recovery and Conservation Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and analogous state laws. In addition, some of our offshore workforce accommodation units must be certified by the U.S. Coast Guard before we can supply the units to our customers for use offshore. If we are unsuccessful or are delayed in certifying certain of our accommodation units with the U.S. Coast Guard, our business, operating results and financial condition could be harmed.
Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas and could limit wellsite services opportunities. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred as a result of conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws, and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition. We maintain insurance against some risks associated with underground contamination that may occur as a result of wellsite service activities. However, this insurance is limited to activities at the wellsite, and this insurance may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial
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condition and operations. Please read “Business—Environmental Matters” for more information on the environmental laws and government regulations that are applicable to us.
We have operations located on lands that are regulated by the Bureau of Land Management of the United States Department of Interior and these operations may be subject to long periods of interruption or suspension.
The Bureau of Land Management (the “BLM”) enforces regulations that protect certain animals, such as deer, sage grouse and raptors that inhabit lands in the northern United States, where we have operations. We provide services in these locations and our revenue attributable to these services accounted for 15.8% and 14.4% of our total revenue for the year ended December 31, 2007 and the six months ended June 30, 2008, respectively. We are affected by this enforcement in the following ways: (1) the BLM may deny or delay the granting of permits to us or our customers necessary to conduct operations in these lands and (2) the BLM may restrict access to or seek our relocation from these lands for a period of time. As a result of this enforcement, our operations on these lands have been and may be interrupted or suspended for long periods of time. For example, from mid-November until mid-May, the period during which mule deer roam these lands, certain of our operations cease and go on stand-by. In addition, during April and May of each year, sage grouse nesting occurs and as a result, we are required to relocate our operations for a period of time. If these regulations become more stringent and, as a result, our operations are interrupted or suspended for longer periods of time, we could lose revenue. The loss of revenue that could occur could have a material impact on our financial condition and results of our operation.
Delays in obtaining permits by our customers for their operations or by us for our operations could impair our business.
Our customers’ and our business operations require permits from various governmental agencies, including the BLM and numerous state agencies. The ease of obtaining the necessary permits depends on the type of operation and the state in which the operation will take place. As with all governmental permit processes, permits may not be issued in a timely fashion, or at all, or in a form consistent with our plan of operations. As a result, our operations may be interrupted or suspended for long periods of time, which could cause us to lose revenue and have a material adverse effect on our results of operation.
Our holding company structure makes us dependent on our subsidiaries to meet our financial obligations.
As a holding company, we have no significant assets other than the equity of our subsidiaries. In order to meet financial obligations, we rely exclusively on the cash flow from our subsidiaries. Our operating subsidiaries may be unable to generate sufficient cash flow for us to meet our financial obligations. Substantially all of our operating subsidiaries have guaranteed our 9.75% Senior Notes due February 1, 2015 (the “Senior Notes”), the debt under our credit facility and the debt under our $250.0 million bridge loan facility.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, our business and the trading price of our common stock could be affected as potential shareholders lose confidence in our financial reporting.
Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud and to operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful or that we will be able to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
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Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
We now have, and after this offering will continue to have, a significant amount of indebtedness. As of July 31, 2008, our total debt was $750.6 million, including $1.3 million under promissory notes to sellers of businesses we acquired, $300.0 million in aggregate principal amount under our Senior Notes, $125.0 million under our revolving credit facility, $74.3 million under our Term Loan B and $250.0 million under our bridge loan facility. Following this offering and giving effect to the use of proceeds therefrom, on an as adjusted basis our total debt would have been $ million. Holding all other variables constant, if interest rates on our floating rate debt increased or decreased by 1%, interest expense for the year ended December 31, 2007 and the six months ended June 30, 2008 would have increased or decreased by approximately $2.1 million and $2.5 million, respectively. We will also have the ability to incur substantially more debt. For example, we have the ability to increase our borrowing capacity under our credit facility by $75.0 million. We have a total borrowing capacity of $175.0 million under our revolving credit facility, of which $47.4 million was available as of July 31, 2008.
Our current and future indebtedness could have important consequences to you. For example, it could:
• | impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes; |
• | limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; |
• | limit our ability to borrow funds that may be necessary to operate or expand our business; |
• | prevent us from paying dividends to our stockholders, entering into transactions with affiliates or entering into sale and leaseback transactions that may be beneficial to us; |
• | limit our ability to purchase or acquire property or assets, merge or consolidate with other entities or sell all or substantially all of our assets; |
• | put us at a competitive disadvantage to competitors that have less debt; |
• | increase our vulnerability to interest rate increases; and |
• | hinder our ability to adjust to rapidly changing economic and industry conditions. |
Our existing term credit facility requires us to maintain certain financial ratios and to satisfy certain financial conditions. In addition, our credit facility, bridge loan facility and indenture contain numerous covenants that limit our discretion with respect to business matters, including mergers or acquisitions, paying dividends, repurchasing our common stock, incurring additional debt or disposing of assets. A breach of any of these covenants could result in a default under the agreements. If an event of default were to occur, we and our subsidiary guarantors may not be able to pay our debts or borrow sufficient funds to refinance them. Even if new financing were available, it may not be on terms acceptable to us. As a result of this risk, we could be forced to take actions that we otherwise would not take, or not take actions that we otherwise might take, in order to comply with the covenants in the credit facility, bridge loan facility or the indenture. For example, these restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a discussion of our credit facility, bridge loan facility and indenture.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our
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financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our operations in the Gulf of Mexico and coastal regions of Louisiana and Texas are adversely impacted by the hurricane season, which generally occurs in the second and third calendar quarters of the year.
Hurricanes and the threat of hurricanes during this period will often result in the shut-down of oil and natural gas operations in the Gulf of Mexico, coastal regions and land operations within the hurricane path. Our operations are negatively affected by hurricanes in three ways. First, we may incur significant expenses when we transport our accommodation units and surface and other equipment away from and back to the affected wellsite. Second, during a shut-down period, we are unable to access wellsites and our services are suspended resulting in loss of revenue for this period of time. Third, if we are unsuccessful in transporting our accommodation units and surface equipment away from the storm threatened area, the units and equipment may suffer significant damage resulting in additional expenses incurred to repair or replace the damaged units or equipment. For example, a number of our accommodation units and mats were damaged, displaced or lost during Hurricane Katrina in 2005. A period of approximately 60 days passed before we were able to purchase and deploy new accommodation units and mats in this area, resulting in lost revenue during such time. In addition, a significant amount of our offshore workforce accommodation business is conducted in areas susceptible to hurricanes. The occurrence of a hurricane can therefore create unpredictability in activity and utilization rates and lead to the destruction of our property, which can have a material adverse impact on our business, financial condition, results of operations and cash flow.
We have operations in the Gulf of Mexico where we do not maintain business interruption insurance.
Our offshore workforce accommodation business operates in the Gulf of Mexico and, to a lesser extent, other international offshore regions. We are not insured against interruptions of our offshore operations or business activities. If our operations in these areas are disrupted by severe weather conditions such as hurricanes, or otherwise, we will be unable to recoup the lost revenue resulting from these disruptions. If these operations are disrupted frequently and/or for a significant period of time, we could lose substantial revenue.
Our customers may not maintain insurance against damage to or the loss of the offshore products that they lease from us.
In our offshore workforce accommodation business, our customers are contractually obligated to maintain insurance against property damage to or loss of our workforce accommodation units. However, if our customers do not comply with their insurance obligations and our products sustain damage or are lost, then we may be unable to recover the value of the damaged or lost products. For example, certain of our offshore workforce accommodation units were damaged in the hurricanes that occurred in 2005. Some of our customers failed to maintain insurance against the damage to these units. These damaged products were lost or unusable for a substantial period of time. As a result, we incurred additional costs to repair or replace these units and were not able to earn revenue from these units during this time.
Increasing trucking regulations may increase our costs and negatively impact our results of operations.
Through our rig relocation and heavy equipment hauling business, we operate trucks and loaders. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and
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specifications of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
The contract period during which we provide services to our customers is relatively short, which exposes us to volatility in prices and equipment utilization levels. This volatility may have a material adverse effect on our business.
A significant portion of our revenue is derived by charging our customers for the actual period of time during which we provide services to them. The period of time for which our customers contract with us is usually relatively short, ranging from a few days to several months. The short term of these arrangements exposes us to the risks of a rapid reduction in market prices and equipment utilization and volatility in our revenue. These reductions and volatility may have a material adverse effect on our business. We do not maintain significant backlog and are generally dependent on replacement contracts to sustain and build revenue as jobs are completed.
An increase in the importation of liquefied natural gas, or LNG, as a substitute for oil and natural gas drilling activities may reduce the level of these drilling activities in North America, which may have a material adverse effect on our business.
The importation of LNG is becoming increasingly important as a supply source in order to meet domestic natural gas demand. If the importation of LNG continues to increase, replace or supplement oil and natural gas production as a source for natural gas, then the level of North American drilling activity related to oil and natural gas may decrease. Our services support drilling for oil and natural gas. Consequently, a substantial reduction in oil or natural gas production levels could have a material adverse effect on our business, even in an environment of stronger oil and natural gas prices.
Our non-U.S. operations subject us to additional risks.
We have operations in several international areas, including Mexico, Trinidad and Tobago and Equatorial Guinea, and our business strategy contemplates expansion into international markets. We are subject to the various risks inherent in conducting business operations in locations outside the United States. These risks may include, among other things, foreign currency risk and changes in local laws and policies, including tax regulations. Our operations in these areas increase our exposure to risks of war, terrorist attacks, local economic conditions, political disruptions, civil disturbance and governmental policies that may disrupt our operations, restrict the movement of funds or limit repatriation of profits, and limit access to markets for periods of time.
U.S. laws and policies on foreign trade, taxation and investment may also adversely affect our international operations. In addition, if a dispute arises from our international operations, courts outside the U.S. may have exclusive jurisdiction over the dispute, or we may not be able to subject persons outside the U.S. to the jurisdiction of U.S. courts.
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Local laws and customs in many countries differ significantly from those in the United States. In many countries, particularly in those with developing economies, it is common to engage in business practices that are prohibited by U.S. regulations applicable to us. The U.S. Foreign Corrupt Practices Act prohibits corporations and individuals, including us, our employees and others acting on our behalf, from engaging in certain activities to obtain or retain business or to influence a person working in an official capacity. We are responsible for any violations by our employees, contractors and agents, whether based within or outside the United States, for violations of the U.S. Foreign Corrupt Practices Act. Any such violation, even if prohibited by our policies, could have a material adverse effect on our business. In addition, our non-U.S. competitors that are not subject to the U.S. Foreign Corrupt Practices Act or similar laws may be able to secure business or other preferential treatment in such countries by means that such laws prohibit with respect to us.
Risks Related to this Offering
Certain stockholders’ shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.
After this offering, we will have outstanding shares of common stock. Of these shares, the shares we and the selling stockholders are selling in this offering, or shares if the underwriters exercise in full their option to purchase additional shares, will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”) except for any shares purchased by any of our “affiliates” as defined in Rule 144 under the Securities Act. A total of shares, or shares if the underwriters exercise in full their option to purchase additional shares, will be “restricted securities” (within the meaning of Rule 144 under the Securities Act) or subject to lock-up arrangements. In connection with this offering, we, our officers and directors and substantially all of our existing stockholders (including the selling stockholders) have entered into lock-up agreements under which we and they have agreed not to offer or sell any shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock for an initial period of 180 days from the date of this prospectus without the prior written consent of Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC. Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC may, at any time and without notice, waive any of the terms of these lock-up agreements. See “Underwriting” for a description of these lock-up agreements.
Following the lock-up period, the holders of shares of our common stock will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. The filing of a registration statement in respect of these shares, the exercise of these holders’ registration rights and the sale by these holders of a large number of shares could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.
As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock plans. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups we and certain of our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
Purchasers of common stock will experience immediate and substantial dilution.
Based on an assumed initial public offering price of $ per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the net tangible book value per share of common stock from the initial public offering price, and our pro forma net tangible book value as of June 30, 2008 after giving effect to this offering would be $ per share. You will incur further
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dilution if outstanding options to purchase common stock are exercised. In addition, our certificate of incorporation allows us to issue significant numbers of additional shares. Please read “Dilution” for a complete description of the calculation of net tangible book value.
Our certificate of incorporation, bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
• | limitations on the removal of directors; |
• | the prohibition of stockholder action by written consent; and |
• | limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders. |
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our common stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. These provisions could limit the price that investors might be willing to pay in the future for shares of our common stock.
We are party to a nominating agreement with Carlyle/Riverstone. Please read “Certain Relationships and Related Party Transactions—Nominating Agreement” for additional information about the nominating agreement.
Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our existing credit facility, bridge loan facility and indenture restrict the payment of dividends without the prior written consent of the lenders. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.
There has been no active trading market for our common stock, and an active trading market may not develop.
Prior to this offering, there has been no public market for our common stock. We have applied for listing of our common stock on The NASDAQ Stock Market LLC. We do not know if an active trading market will develop for our common stock or how the common stock will trade in the future, which may make it more difficult for you to sell your shares. Negotiations between the underwriters, the selling stockholders and us will determine the initial public offering price. You may not be able to resell your shares at or above the initial public offering price.
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If our stock price declines after the initial offering, you could lose a significant part of your investment.
In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. The market price of our common stock could similarly be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
• | changes in securities analysts’ recommendations and their estimates of our financial performance; |
• | the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission and those of our competitors; |
• | fluctuations in broader stock market prices and volumes, particularly among securities of oil and natural gas service companies; |
• | changes in market valuations of similar companies; |
• | investor perception of our industry or our prospects; |
• | additions or departures of key personnel; |
• | commencement of or involvement in litigation; |
• | changes in environmental and other governmental regulations; |
• | announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments; |
• | variations in our quarterly results of operations or cash flow or those of other oil and natural gas service companies; |
• | revenue and operating results failing to meet the expectations of securities analysts or investors in a particular quarter; |
• | changes in our pricing policies or pricing policies of our competitors; |
• | future issuances and sales of our common stock; |
• | demand for and trading volume of our common stock; |
• | domestic and worldwide supplies and prices of and demand for oil and natural gas; and |
• | changes in general conditions in the United States economy, financial markets or the oil and natural gas industry. |
The realization of any of these risks and other factors beyond our control could cause the market price of our common stock to decline significantly.
Risk Factors Relating to Our Relationship with Carlyle/Riverstone
Carlyle/Riverstone controls the outcome of stockholder voting and may exercise this voting power in a manner adverse to our other stockholders. Through its representation on the Board of Directors, Carlyle/Riverstone may be able to effect corporate policy that may not be in your best interests.
Prior to this offering, Carlyle/Riverstone holds approximately % of our outstanding common stock. Following this offering, Carlyle/Riverstone will hold approximately % of our outstanding common stock (or % if the underwriters exercise in full their option to purchase additional shares). Accordingly, Carlyle/ Riverstone is in a position to effectively control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of Carlyle/Riverstone may differ from yours, and Carlyle/Riverstone may vote its common stock in a manner that may adversely affect you.
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In addition, we are party to a nominating agreement with Carlyle/Riverstone. Pursuant to this agreement, so long as Carlyle/Riverstone beneficially owns at least 30%, 20% or 10% of our issued and outstanding shares of our common stock, we have agreed to take all corporate action within our power to cause the board of directors at all times to include at least three, two or one member(s), respectively, designated by Carlyle/Riverstone. As discussed below, Carlyle/Riverstone may have interests that differ from your interests. With two or three directors, Carlyle/Riverstone may be able to effect corporate policy that may not be in your best interests.
Two of our directors may have conflicts of interest because they are affiliated with Carlyle/Riverstone.
Two of our directors, John Lancaster and Pierre Lapeyre, are also current directors or officers of Carlyle/Riverstone and its owners. Carlyle/Riverstone also has the right to nominate a third representative to our board of directors. This may create conflicts of interest because these directors have responsibilities to Carlyle/Riverstone and its owners. Their duties as directors or officers of Carlyle/Riverstone and its owners may conflict with their duties as directors of our company. These conflicts may result in these directors not participating in certain decisions regarding business dealings between Carlyle/Riverstone and us and other matters.
Carlyle/Riverstone and its director nominees on our board of directors generally have no obligation to offer us business opportunities.
Affiliates of Carlyle/Riverstone have investments in other oilfield service and energy companies that may compete with us, and Carlyle/Riverstone and its affiliates, other than our company, may invest in other such companies in the future. If an opportunity in the oilfield service industry is presented to a person who is a member of Carlyle/Riverstone or its affiliates, including any of those individuals who also serve as a Carlyle/Riverstone director nominee on our board of directors, no member of Carlyle/Riverstone or any of those individuals has any obligation to communicate or offer the opportunity to us.
The availability of shares of our common stock for future sale could depress our stock price.
Carlyle/Riverstone’s exercise of certain registration rights relating to shares of our common stock and sales of a substantial number of shares of our common stock in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.
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This prospectus contains forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including, among other things, the risk factors discussed in this prospectus and other factors, most of which are beyond our control.
The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this prospectus are forward-looking statements.
Although we believe that the forward-looking statements contained in this prospectus are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this prospectus may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.
Important factors that may affect our expectations, estimates or projections include:
• | a decline in or substantial volatility of oil and natural gas prices, and any related changes in expenditures by our customers; |
• | a decline in oil and natural gas drilling activity in the markets in which we operate; |
• | competition within our industry; |
• | the effects of acquisitions on our business; |
• | changes in customer requirements in markets or industries we serve; |
• | our ability to complete pending acquisitions and integrate acquired businesses; |
• | general economic and market conditions; |
• | our access to current or future financing arrangements; |
• | our ability to replace or add workers at economical rates; |
• | the effects of severe weather on our operations; |
• | our ability to replace or acquire equipment; |
• | political instability in oil and natural gas producing countries; and |
• | environmental and other governmental regulations. |
Our forward-looking statements speak only as of the date of this prospectus. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Please see “Risk Factors.”
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We expect to receive net proceeds from this offering of approximately $ million, assuming an initial public offering price of $ per share and after deducting underwriting discounts and commissions and estimated offering expenses. We will not receive any of the net proceeds from any sale of shares of common stock by any selling stockholders. The selling stockholders include members of our senior management. See “Principal and Selling Stockholders.”
We plan to use our net proceeds from this offering as follows:
• | to repay approximately $252.5 million of indebtedness and prepayment premiums under our $250.0 million bridge loan facility; and |
• | to repay $ million indebtedness under our credit facility. |
We plan to use any net proceeds we receive from the exercise of the underwriters’ option to purchase additional shares of common stock to repay indebtedness under our credit facility.
An affiliate of Credit Suisse Securities (USA) LLC is the sole lender under our bridge loan facility and affiliates of Lehman Brothers Inc., UBS Securities LLC and Credit Suisse Securities (USA) LLC are lenders under our credit facility and, as such, they will receive substantially all of the net proceeds received by us in this offering. See “Underwriting—Other Relationships/FINRA Rules.”
As of July 31, 2008, we had $250.0 million outstanding under our $250.0 million bridge loan facility. Our bridge loan facility matures on August 1, 2012 and interest under our bridge loan facility as of July 31, 2008 was 8.4%. We used the borrowings under our bridge loan facility to fund our acquisition of Salty’s and to repay indebtedness under our credit facility. Our bridge loan facility requires us to pay a prepayment premium of 1% of the amount prepaid if such prepayment is made on or prior to November 1, 2008. If such prepayment is made after November 1, 2008 but on or prior to February 1, 2009 the prepayment premium will be 2% of the amount prepaid. If prepayment is made after February 1, 2009 the prepayment premium will be 3% of the amount prepaid.
Our credit facility consists of a $75.0 million term loan and a $175.0 million revolver. As of July 31, 2008, we had $74.3 million outstanding under our term loan, $125.0 million outstanding under our revolving credit facility and $2.6 million outstanding letters of credit, leaving $47.4 million available for additional borrowing under our credit facility. Our credit facility matures on March 1, 2011 and interest under our credit facility as of July 31, 2008 was 5.1%. We used the borrowings under our credit facility primarily to fund our acquisitions of Shores Energy, Inc., FPI, Patriot Liquid Services, L.P. (“Patriot”), Bayou Tank Services Ltd. (“Bayou Tank”) and Polleyco and to make earnest money deposits for our acquisition of Salty’s.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a description of our outstanding indebtedness, our credit facility and our bridge loan facility.
A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) the net proceeds from this offering by approximately $ , assuming no change in the number of shares offered by us as set forth on the cover page of this prospectus and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
We have not declared or paid any dividends on our common stock, and we do not currently anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant. We are also restricted in our ability to pay dividends under our credit facility, bridge loan facility and indenture.
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We have provided in the table below our capitalization as of June 30, 2008: (1) on an actual basis, and (2) as adjusted for the Restructuring, this offering and the application of the estimated net proceeds from this offering, as if they had occurred on June 30, 2008.
You should read this information in conjunction with our consolidated financial statements and the accompanying notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Use of Proceeds” included elsewhere in this prospectus.
June 30, 2008 | ||||||
Actual | As adjusted | |||||
(in thousands) | ||||||
Cash and cash equivalents(1)(2) | $ | 4,293 | $ | |||
Total long-term debt, including current portion: | ||||||
Borrowings under our revolving credit facility(2) | $ | 110,000 | $ | |||
Term Loan B under our credit facility(2) | 74,250 | |||||
9.75% Senior Notes | 300,000 | |||||
Bridge loan facility | 250,000 | |||||
Other debt and obligations under capital leases | 1,866 | |||||
Total | 736,116 | |||||
Partners’ capital/Stockholders’ equity: | ||||||
Partners’ capital | 179,106 | |||||
Common stock, $.01 par value per share; shares authorized as further adjusted; shares issued and outstanding as further adjusted | ||||||
Retained earnings | ||||||
Total Partners’ capital/Stockholders’ equity(1) | 179,106 | |||||
Total capitalization(1) | $ | 915,222 | $ | |||
(1) | A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) each of additional paid-in capital, total stockholders’ equity and total capitalization by $ , assuming no change in the number of shares offered by us as set forth on the cover page of this prospectus and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. |
(2) | As of July 31, 2008, we had $74.3 million outstanding under our Term Loan B, $125.0 million outstanding under our revolving credit facility and $2.6 million of outstanding letters of credit, resulting in approximately $47.4 million available for additional borrowing under our credit facility. |
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Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Adjusted net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock outstanding. At June 30, 2008, assuming completion of the Restructuring, we had a net negative tangible book value of $240.6 million or $ per share of common stock. After giving effect to the sale of shares of common stock in this offering at an assumed initial public offering price of $ per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at June 30, 2008 would have been $ million or $ per share. This represents an immediate increase in such net tangible book value of $ per share to existing stockholders and an immediate and substantial dilution of $ per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:
Assumed initial public offering price per share | $ | |||||
Adjusted net tangible book value per share as of June 30, 2008(1) | $ | |||||
Increase attributable to new public investors | ||||||
As adjusted net tangible book value per share after this offering | ||||||
Dilution in as adjusted net tangible book value per share to new investors | $ | |||||
(1) | Assuming completion of the Restructuring as of such date. |
A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) our net tangible book value by $ million, the net tangible book value per share, after giving effect to this offering, by $ per share and the dilution in net tangible book value per share to new investors in this offering by $ per share, assuming no change in the number of shares offered by us as set forth on the cover page of this prospectus, and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
The following table summarizes, on the as adjusted basis set forth above as of June 30, 2008, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , the mid-point of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.
Shares Purchased(1) | Total Consideration | Average Price Per Share | ||||||||||||
Number | % | Amount | % | |||||||||||
Existing stockholders(2) | $ | $ | ||||||||||||
New public investors | $ | $ | ||||||||||||
Total | 100.0 | % | $ | 100.0 | % | |||||||||
(1) | The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholders in this offering. |
(2) | With respect to our executive officers, directors and greater-than-10% stockholders, and assuming the exercise of all outstanding warrants and stock options, the number of shares of common stock purchased from us, the total consideration paid to us, and the average price per share paid by all of those affiliated persons, are as follows: |
Shares Purchased | Total Consideration | Average Price Per Share | ||||||||||
Number | % | Amount | % | |||||||||
Affiliated persons | $ | $ |
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As of , 2008, there were shares of our common stock outstanding, held by stockholders. Sales by the selling stockholders in this offering will reduce the number of shares of common stock held by existing stockholders to , or approximately % of the total number of shares of common stock outstanding after this offering, and will increase the number of shares of common stock held by new investors to or approximately % of the total number of shares of common stock outstanding after this offering.
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UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA
For the year ended December 31, 2007
The following pro forma consolidated financial data are based on our historical financial statements included elsewhere in this prospectus.
On May 31, 2007, we acquired all of the issued and outstanding capital stock of FPI for total consideration of approximately $30.5 million. FPI is engaged in the rental of solids control equipment to oil and gas companies and operators at drilling locations principally in the Rocky Mountain region to assist them in separating drill cuttings from drilling fluids.
On August 1, 2007, we acquired substantially all of the operating assets of Salty’s for total consideration of approximately $157.9 million, subject to certain purchase price adjustments. Salty’s provides frac tank rentals and sales and saltwater hauling and disposal services. Salty’s assets include vacuum trucks, frac tanks and saltwater injection wells.
On January 1, 2008, we acquired all of the operating assets of Polleyco for consideration of approximately $12.0 million paid at closing and contingent consideration of up to $36.0 million payable over a three-year period if certain financial performance targets are met. Polleyco provides integrated oilfield services, including well permitting, design and construction of water districts, wellsite construction, site maintenance, fluid logistics solutions and other services to expedite drilling, completion and production activities, to oil and natural gas operators in the Barnett Shale region of the Fort Worth Basin and Fayetteville Shale areas.
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the dates of acquisition of FPI, Salty’s and Polleyco:
FPI | Salty’s | Polleyco | Total | |||||||||
(unaudited) | ||||||||||||
Assets acquired: | (in thousands) | |||||||||||
Cash and cash equivalents | $ | 6,294 | $ | — | $ | — | $ | 6,294 | ||||
Accounts receivable | 2,187 | 6,188 | — | 8,375 | ||||||||
Other current assets | — | 3,212 | — | 3,212 | ||||||||
Deferred tax assets | 7 | — | — | 7 | ||||||||
Property, plant and equipment | 12,541 | 48,874 | 4,359 | 65,774 | ||||||||
Goodwill and other intangibles | 11,646 | 112,601 | 7,661 | 131,908 | ||||||||
Total assets | 32,675 | 170,875 | 12,020 | 215,570 | ||||||||
Liabilities assumed: | ||||||||||||
Accounts payable | 146 | 4,883 | — | 5,029 | ||||||||
Accrued expenses | 1,606 | — | — | 1,606 | ||||||||
Deferred tax liability | 397 | — | — | 397 | ||||||||
Other liabilities | — | 7,190 | — | 7,190 | ||||||||
Asset retirement obligations | — | 892 | — | 892 | ||||||||
Total liabilities assumed | 2,149 | 12,965 | — | 15,114 | ||||||||
Net assets acquired | $ | 30,526 | $ | 157,910 | $ | 12,020 | $ | 200,456 | ||||
The unaudited pro forma consolidated statement of operations data presented below do not reflect the impact of acquisitions that we determined were not individually significant under SEC rules.
The Stallion historical statement of operations for the year ended December 31, 2007 is derived from our audited consolidated financial statements. The Stallion historical statement of operations information includes results of operations of all acquired businesses from their dates of acquisition through December 31, 2007. The
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historical statement of operations of acquired businesses columns represent the statement of operations of the businesses acquired from January 1, 2007 through the dates on which we began consolidating the financial results of such businesses.
The unaudited pro forma consolidated statement of operations data represent management’s determination of purchase accounting adjustments and are based on available information and assumptions that management considers reasonable under the circumstances. The following table presents pro forma consolidated financial data that gives effect to our recently completed acquisitions as if we had owned such businesses on January 1, 2007. The pro forma adjustments, which are based upon information available to us on July 31, 2008 and upon assumptions that we believe were reasonable at that time, are described in the accompanying notes. The historical operations of FPI, Salty’s and Polleyco prior to the actual acquisitions by us were conducted by different management, during different operating conditions and in a different economic environment. The unaudited pro forma consolidated statement of operations data do not purport to represent what our results would have been had the acquisitions described above been completed on the indicated dates or that may be obtained in the future.
The following information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements included elsewhere in this prospectus.
Unaudited Pro Forma Consolidated Financial Data for the year ended December 31, 2007 | ||||||||||||||||||||||||
Stallion historical statement of operations | FPI | Salty’s | Polleyco | Adjustments | Historical Stallion plus acquisitions(1) | |||||||||||||||||||
Statement of Operations: | (in thousands) | |||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||
Wellsite support services | $ | 215,265 | $ | 7,477 | $ | — | $ | — | $ | — | $ | 222,742 | ||||||||||||
Production & logistics services | 211,930 | — | 45,192 | 30,723 | — | 287,845 | ||||||||||||||||||
Total revenue | 427,195 | 7,477 | 45,192 | 30,723 | — | 510,587 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||||||
Wellsite support services | 118,029 | 2,264 | — | — | — | 120,293 | ||||||||||||||||||
Production & logistics services | 151,526 | — | 22,650 | 11,749 | — | 185,925 | ||||||||||||||||||
General and administrative | 40,027 | 1,020 | 11,696 | 5,192 | — | (2) | 57,935 | |||||||||||||||||
Depreciation and amortization | 62,743 | 331 | 3,553 | 660 | 5,464 | (3) | 72,751 | |||||||||||||||||
Loss (gain) on disposal of assets | 44 | — | — | — | — | 44 | ||||||||||||||||||
Total expenses | 372,369 | 3,615 | 37,899 | 17,601 | 5,464 | 436,948 | ||||||||||||||||||
Operating income | 54,826 | 3,862 | 7,293 | 13,122 | (5,464 | ) | 73,639 | |||||||||||||||||
Interest expense | (52,874 | ) | — | (412 | ) | (145 | ) | (10,124 | )(4) | (63,555 | ) | |||||||||||||
Other income (expenses) | 207 | (115 | ) | 28 | — | — | 120 | |||||||||||||||||
Income before income tax | 2,159 | 3,747 | 6,909 | 12,977 | (15,588 | ) | 10,204 | |||||||||||||||||
Income tax (expense) benefit | (6,410 | ) | (1,710 | ) | (316 | ) | (215 | ) | 25,468 | (5) | 16,817 | |||||||||||||
Net income (loss) | $ | (4,251 | ) | $ | 2,037 | $ | 6,593 | $ | 12,762 | $ | 9,880 | $ | 27,021 | |||||||||||
(1) | Represents historical combined statement of operations data for Stallion for the twelve months ended December 31, 2007, plus the historical results of operations of FPI, Salty’s and Polleyco for the twelve months ended December 31, 2007 as if they were acquired on January 1, 2007. |
(2) | There are no general and administrative adjustments that are directly attributable to the FPI, Salty’s or Polleyco acquisitions. Prior to our acquisition of Salty’s, approximately 445 employees of Salty’s, 419 of whom were direct employees and 26 of whom were general and administrative employees, were not provided certain employee benefits. Employee benefits customary in the oilfield services industry are provided to all Stallion full time employees. We determined that the cost of our existing employee benefit programs is approximately $520 per employee per month through an analysis of our total employee benefits |
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costs. Production & logistics services, direct operating and general and administrative expenses for the pro forma period ended December 31, 2007 should be increased $1.1 million and $0.1 million respectively to reflect the on-going expected cost of providing the Stallion employee benefits program to all of the acquired Salty’s employees. |
(3) | Depreciation and amortization reflects adjusted fixed assets and depreciable intangible assets assuming that the acquisitions occurred January 1, 2007. Asset values were determined based upon third party and internal appraisals. We estimated the remaining useful lives and salvage values of all acquired assets and depreciated those assets over their estimated useful lives using depreciation policies that have been consistently applied by us. We have made preliminary determinations of the purchase accounting adjustments for FPI, Salty’s and Polleyco. For purposes of the pro forma consolidated statement of operations, we determined that approximately $10.5 million and $3.9 million of the purchase price related to FPI and Salty’s, respectively, should be assigned to assets having an estimated useful life of eight years and approximately $3.6 million and $28.8 million of the purchase price related to FPI and Salty’s, respectively, should be assigned to intangible assets having an estimated useful life of approximately six years. We estimated that approximately $4.4 million of the purchase price of Polleyco should be assigned to assets having an estimated useful life of approximately seven years and approximately $7.7 million should be assigned to intangible assets having an estimated useful life of eight years. |
(4) | For purposes of this pro forma financial data we have assumed that the acquisition of FPI was funded with a $30.5 million advance under our credit facility at the rate in effect on May 31, 2007 of LIBOR plus 2.00%, which was 7.32%, and that the acquisition occurred on January 1, 2007. We have assumed that the Salty’s acquisition price of approximately $157.9 million was funded with an advance under our bridge loan facility at the rate in effect on August 1, 2007 of LIBOR plus 4.50%, which was 9.32%, and that the acquisition occurred on January 1, 2007. We have assumed that the Polleyco acquisition price of approximately $12.0 million was funded with an advance under our credit facility at the rate in effect on January 1, 2008 of LIBOR plus 2.00%, which was 5.09%, and that the acquisition occurred on January 1, 2007. |
(5) | Historically, we were not subject to income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Pro forma net income (loss) for the year ended December 31, 2007 includes a provision for income taxes on our consolidated income before tax that has been computed at a blended state and federal rate of 38%, which represents the statutory rate, to reflect the pro forma income tax effect on net income (loss) for the year ended December 31, 2007 assuming that the Restructuring occurred on January 1, 2007. As a result of the Restructuring, we will record deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. For purposes of this pro forma, we estimated that our non current net deferred tax liability would have been approximately $9.1 million as of January 1, 2007, resulting primarily from accelerated depreciation taken by Stallion Ltd. and its subsidiaries. As a result, we will recognize a one-time tax benefit of approximately $20.7 million to properly reflect our deferred tax liability resulting from the Restructuring. |
We acquired Polleyco on January 1, 2008. The purchase price of Polleyco was $12.0 million paid at closing with contingent consideration of up to $36.0 million payable over a three-year period if certain financial performance targets are met. No pro forma disclosure is provided with respect to Polleyco for the six months ended June 30, 2008 as it is included in our results of operation from January 1, 2008.
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SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected historical consolidated financial and operating data as of the dates and for the periods shown. The amounts for each historical annual period presented below were derived from our audited consolidated financial statements. The following information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Unaudited Pro Forma Consolidated Financial Data” and our consolidated financial statements and related notes included elsewhere in this prospectus.
Year Ended December 31, | Six Months Ended June 30, | |||||||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||||||
(unaudited) | ||||||||||||||||||||||||||||
Statement of Operations Data: | (in thousands) | |||||||||||||||||||||||||||
Revenue: | ||||||||||||||||||||||||||||
Wellsite support services | $ | 6,769 | $ | 15,452 | $ | 73,126 | $ | 162,661 | $ | 215,265 | $ | 97,442 | $ | 126,220 | ||||||||||||||
Production & logistics services | — | — | — | 77,749 | 211,930 | 74,948 | 162,090 | |||||||||||||||||||||
Total revenue | 6,769 | 15,452 | 73,126 | 240,410 | 427,195 | 172,390 | 288,310 | |||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||
Wellsite support services | 3,108 | 8,695 | 42,281 | 88,029 | 118,029 | 53,512 | 72,001 | |||||||||||||||||||||
Production & logistics services | — | — | — | 52,679 | 151,526 | 52,376 | 121,400 | |||||||||||||||||||||
Selling, general and administrative | 2,145 | 3,745 | 9,883 | 19,170 | 40,027 | 17,191 | 20,935 | |||||||||||||||||||||
Depreciation and amortization | 836 | 1,924 | 7,798 | 30,068 | 62,743 | 24,659 | 36,516 | |||||||||||||||||||||
Loss (gain) on disposal of assets | 86 | 92 | 499 | 920 | 44 | 979 | (101 | ) | ||||||||||||||||||||
Total expenses | 6,175 | 14,456 | 60,461 | 190,866 | 372,369 | 148,717 | 250,751 | |||||||||||||||||||||
Operating income | 594 | 996 | 12,665 | 49,544 | 54,826 | 23,673 | 37,559 | |||||||||||||||||||||
Interest expense, net | (489 | ) | (917 | ) | (4,565 | ) | (18,919 | ) | (52,874 | ) | (20,581 | ) | (34,558 | ) | ||||||||||||||
Other income (expense) | — | — | (66 | ) | 71 | 207 | 147 | 374 | ||||||||||||||||||||
Income before income taxes | 105 | 79 | 8,034 | 30,696 | 2,159 | 3,239 | 3,375 | |||||||||||||||||||||
Income tax expense(1) | — | — | (598 | ) | (4,927 | ) | (6,410 | ) | (2,345 | ) | (5,805 | ) | ||||||||||||||||
Net income (loss) | $ | 105 | $ | 79 | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | $ | 894 | $ | (2,430 | ) | ||||||||||||
Pro forma income tax (unaudited)(1) | $ | 40 | $ | 30 | $ | 3,053 | $ | 11,664 | $ | 820 | $ | 1,231 | $ | 1,283 | ||||||||||||||
Pro forma net income (unaudited)(1) | $ | 65 | $ | 49 | $ | 4,981 | $ | 19,032 | $ | 1,339 | $ | 2,008 | $ | 2,092 | ||||||||||||||
Earnings (loss) per share: | ||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||||||
Weighted average shares: | ||||||||||||||||||||||||||||
Basic | ||||||||||||||||||||||||||||
Diluted | ||||||||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||
EBITDA(2) | $ | 1,430 | $ | 2,920 | $ | 20,397 | $ | 79,683 | $ | 117,776 | $ | 48,479 | $ | 74,449 | ||||||||||||||
Cash flow provided by operating activities | 144 | 1,734 | 7,087 | 41,124 | 58,264 | 49,463 | 38,701 | |||||||||||||||||||||
Cash flow used in investing activities | (7,536 | ) | (7,142 | ) | (83,462 | ) | (280,164 | ) | (496,785 | ) | (177,880 | ) | (80,816 | ) | ||||||||||||||
Cash flow provided by financing activities | 7,805 | 5,046 | 77,307 | 242,158 | 444,271 | 133,422 | 36,558 | |||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||
Acquisitions, net of cash acquired(3) | 5,608 | 1,158 | 47,191 | 178,045 | 388,091 | 112,839 | 23,377 | |||||||||||||||||||||
Property, plant and equipment | 2,046 | 5,961 | 35,951 | 92,029 | 122,291 | 75,870 | 61,325 |
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As of December 31, | As of June 30, 2008 | |||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | ||||||||||||||
(unaudited) | ||||||||||||||||||
Balance Sheet Data: | (in thousands) | |||||||||||||||||
Cash and cash equivalents | $ | 412 | $ | 50 | $ | 982 | $ | 4,100 | $ | 9,850 | $ | 4,293 | ||||||
Property, plant and equipment | 7,131 | 13,899 | 74,583 | 220,777 | 433,355 | 469,682 | ||||||||||||
Total assets | 16,252 | 24,713 | 123,136 | 446,907 | 975,882 | 1,032,188 | ||||||||||||
Total debt | 11,705 | 18,552 | 67,795 | 257,539 | 724,732 | 736,116 | ||||||||||||
Total partners’ capital | 3,533 | 3,611 | 43,597 | 153,534 | 150,349 | 179,106 |
(1) | Historically, we were not subject to taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Pro forma net income for the years ended December 31, 2003, 2004, 2005, 2006, 2007 and the six months ended June 30, 2007 and 2008 includes a provision for taxes on our consolidated income before tax. Pro forma income tax expense has been computed at a blended state and federal tax rate of 38%, which represents the statutory rate, to reflect the pro forma income tax effect on net income (loss) for the periods presented assuming that the Restructuring happened on January 1, 2003. |
(2) | EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors and commercial banks, to assess: |
• | period-to-period comparisons of the financial performance of our assets without regard to financing methods, capital structures, tax status or historical cost basis; |
• | our operating performance and return on invested capital as compared to those of other companies in the oilfield service industry, without regard to financing methods, tax status and capital structure; and |
• | our compliance with certain financial covenants included in our credit facility and our ability to incur debt under our indenture, which are based in significant part on EBITDA. |
EBITDA has limitations as an analytical tool and should not be considered an alternative to net income (loss), operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income (loss) and operating income and these measures may vary among other companies. Limitations to using EBITDA as an analytical tool include: |
• | EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or capital commitments; |
• | EBITDA does not reflect changes in, or cash requirements necessary to service interest or principal payments, on our debt; |
• | although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and |
• | other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure. |
The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the most directly comparable GAAP financial measure, net income (loss), on a historical basis for each of the periods indicated. |
Year ended December 31, | Six Months Ended June 30, | ||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||
Reconciliation of Net income (loss) to | (unaudited) | ||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Net income (loss) | $ | 105 | $ | 79 | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | $ | 894 | $ | (2,430 | ) | |||||||
Income taxes | — | — | 598 | 4,927 | 6,410 | 2,345 | 5,805 | ||||||||||||||||
Interest expense | 489 | 917 | 4,565 | 18,919 | 52,874 | 20,581 | 34,558 | ||||||||||||||||
Depreciation and amortization | 836 | 1,924 | 7,798 | 30,068 | 62,743 | 24,659 | 36,516 | ||||||||||||||||
EBITDA | $ | 1,430 | $ | 2,920 | $ | 20,397 | $ | 79,683 | $ | 117,776 | $ | 48,479 | $ | 74,449 | |||||||||
(3) | Acquisitions, net of cash acquired, consist only of the cash component of acquisitions. It does not include equity and/or notes issued for acquisitions. |
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MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and the related notes included within this prospectus. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about our business and the oilfield service industry. These forward-looking statements involve risks and uncertainties that may be beyond our control. Our actual results could differ materially from the results indicated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and natural gas, the level of oil and natural gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties, as well as those factors discussed elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.
Overview
We provide wellsite support services and production & logistics services to exploration and production companies and drilling contractors that conduct drilling and production activities throughout the United States. Our company slogan, Everything but the Rig, reflects our business strategy of providing a broad and comprehensive range of critical services to support wellsite operations, including onshore and offshore workforce accommodations, surface equipment rental, communications services, solids control, production services, wellsite construction, rig relocation and heavy equipment hauling.
We currently focus on oil and natural gas regions within North America that we believe have attractive long-term potential for growth, including South Texas, the Gulf Coast, ArkLaTex, the Fort Worth Basin, the Permian Basin, the Mid-Continent, Rocky Mountain and Appalachian Basin regions and Prudhoe Bay, Alaska. We also supply offshore workforce accommodations and related equipment for use in the Gulf of Mexico and, to a lesser extent, other international offshore regions. We manage our operations from 74 field service offices located throughout our operating regions.
We operate in two business segments:
• | Wellsite Support Services. As of July 31, 2008, our wellsite support services segment includes: (1) workforce accommodations, with a fleet of approximately 2,400 transportable accommodation units designed to accommodate various personnel on wellsite locations before, during and after drilling operations, (2) surface equipment rentals used in wellsite activities, including forklifts, manlifts, power generators, compressors, loaders and water systems, (3) our StaRComm satellite system, and (4) solids control, which includes closed-loop mud systems and customized fluid recovery services. For the year ended December 31, 2007 and the six months ended June 30, 2008, revenue relating to our wellsite support services segment was $215.3 million and $126.2 million, respectively. |
• | Production & Logistics Services. Our production & logistics services segment includes: (1) production services, which includes frac tank rentals, saltwater injection wells, water logistics and the manufacture of frac tanks and other containment equipment, (2) wellsite construction, which includes wellsite clearing, road construction, mat placement, production facility assembly and construction, pipeline installation, pit remediation, production decommissioning, and wellsite restoration and (3) land rig relocation and heavy equipment hauling, through which we operate a fleet of tractor trucks, trailers, pole trucks and cranes used for the demobilization, relocation and mobilization of drilling rigs and related heavy equipment. For the year ended December 31, 2007 and the six months ended June 30, 2008, revenue relating to our production & logistics services segment was $211.9 million and $162.1 million, respectively. |
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Our customers include exploration and production companies and drilling contractors that conduct drilling and production activities throughout the United States and offshore in the Gulf of Mexico, and, to a lesser extent, in international offshore regions. Please read “Business—Customers” for additional information about our customers. The primary factor influencing demand for our services is the level of drilling and production activity of our customers, which in turn, depends on current and anticipated future oil and natural gas prices, production depletion rates and the resultant levels of cash flow generated and allocated by our customers to their drilling and production budgets. As a result, demand for our services and products can be cyclical.
The following tables summarize average United States and International drilling rig activity, as measured by Baker Hughes Incorporated, a large public oilfield services company (“BHI”), U.S. well service rig count, as measured by Weatherford International, Ltd. and the Association of Energy Service Companies (“WFT/AESC”) and historical commodity prices as provided by Bloomberg L.P. (“Bloomberg”):
Year Ended December 31, | Six Months Ended June 30, | |||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2008 | |||||||
BHI United States Rotary Rig Count: | ||||||||||||
United States Land | 924 | 1,095 | 1,290 | 1,559 | 1,695 | 1,755 | ||||||
United States Offshore | 108 | 97 | 93 | 90 | 73 | 62 | ||||||
Total United States | 1,032 | 1,192 | 1,383 | 1,649 | 1,768 | 1,817 | ||||||
WFT/AESC United States Workover Rig Count: | ||||||||||||
United States | 1,967 | 2,064 | 2,222 | 2,364 | 2,388 | 2,533 | ||||||
Total United States Rotary and Workover | 2,999 | 3,256 | 3,605 | 4,013 | 4,156 | 4,350 | ||||||
BHI International Rotary Rig Count: | ||||||||||||
International Land | 544 | 594 | 643 | 656 | 720 | 769 | ||||||
International Offshore | 226 | 242 | 265 | 269 | 286 | 296 | ||||||
Total International | 770 | 836 | 908 | 925 | 1,006 | 1,065 | ||||||
Source: Baker Hughes Incorporated and Weatherford International, Ltd. and Association of Energy Service Companies |
AVERAGE OIL AND NATURAL GAS PRICES
Period | Average Daily Closing Henry Hub Spot Natural Gas Price ($/mcf) | Average Daily Closing WTI Cushing Spot Oil Price ($/bbl) | ||||
01/01/03 – 12/31/03 | $ | 5.49 | $ | 31.06 | ||
01/01/04 – 12/31/04 | 5.90 | 41.51 | ||||
01/01/05 – 12/31/05 | 8.89 | 56.59 | ||||
01/01/06 – 12/31/06 | 6.73 | 66.09 | ||||
01/01/07 – 12/31/07 | 6.97 | 72.23 | ||||
01/01/08 – 06/30/08 | 10.03 | 111.14 | ||||
Source: Bloomberg |
We believe that U.S. drilling rig and workover rig counts are a good indication of spending by our customers in the oil and natural gas industry for exploration and development of new and existing hydrocarbon reserves. We believe the international drilling rig activity is similarly relevant to our offshore workforce
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accommodation business. Spending levels for these activities are a primary driver of our business, and we believe that our customers tend to invest more in these activities when oil and natural gas prices are at or trending toward higher levels.
How We Generate Our Revenue
Most of our revenue is based upon a charge for the actual period of time the service or rental is provided to our customer, usually a few days, several weeks or a few months. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and equipment utilization and volatility in our revenue.
We generate a majority of our revenue from our wellsite support services and production & logistics services by charging our customers a rig-up charge plus a daily rental rate based on the type of equipment used. The rig-up charge is a flat fee generally payable in connection with the initial set up of workforce accommodation units and connection of these units to water, utilities and sewer systems. The rig-up charges, demobilization charges and daily rates are determined by regional price quotes or, in some cases, a competitive bid process and depend upon the type of service to be performed, the equipment and personnel required for the particular job and the market conditions in the region in which the service is performed. We also charge customers for additional services requested while our equipment is on location, including water delivery, general service calls, repairs and waste disposal.
In our construction services business, we install mats at the wellsite where required by the nature of the terrain or requested to help reduce the environmental impact of wellsite activities. In these instances, we generally submit bids based on a 30, 60 or 90 day mat rental period, with an additional daily rental rate if the mats are used beyond this period.
In our rig relocation and heavy equipment hauling business, we generally bid a turnkey price which may vary by region, type of rig and the distance the rig is transported.
In our production services business, we transport frac tanks, fresh water, completion fluids, produced water, drilling mud and other fluids to and from our customer’s wellsites. We also dispose of these fluids as well as fluids transported by third parties. Customers are generally charged fees for these services based on the volume of fluids transported and disposed. We also generate revenue from the manufacture and sale of frac tanks and other containment equipment which are used in drilling and production activities.
In addition, we generate revenue from the manufacture, sale, lease and repair of workforce accommodation units through our offshore workforce accommodation business.
Our operating costs are comprised primarily of labor, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. With a reduced pool of workers in the industry, it is possible that we will have to raise wage rates to attract workers from other fields and retain or expand our current work force. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and relates to the number of trucks and other equipment in our fleet, employee payroll and safety record. Selling, general and administrative (“SG&A”) expenses were $40.0 million for the twelve months ended December 31, 2007 and $20.9 million for the six months ended June 30, 2008. As a percentage of revenue, the portion of labor expenses included in our SG&A expenses was 6.6%, 4.0% and 5.2% in 2005, 2006 and 2007, respectively, and 3.1% for the six months ended June 30, 2008. Approximately 23.6% of SG&A are expenses related to our field-level office personnel and other overhead, which are necessary for operations.
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How We Evaluate Our Operations
Our management utilizes a variety of financial and operational measurements to analyze and monitor the performance of our services. These measurements include the following:
• | operating income per operating segment (each segment is further analyzed by field office and/or region for trending and to improve overall segment profitability); |
• | material and labor expenses as a percentage of revenue; |
• | EBITDA; |
• | EBIT; |
• | revenue and EBITDA per employee; |
• | return on capital employed; and |
• | safety performance rates. |
We manage our operations through two operating segments. Each segment is further analyzed across seven operating regions. Our operating regions include one or more field service offices, depending on the level of activity and the size of the region. The data generated in each of our operating regions using the foregoing measurement tools is an important part of our operational analysis. We apply these measurement tools to monitor operations separately for each of our operating regions and to analyze trends to determine our relative performance in each region. By comparing our operations on an operating region basis, we can identify and react to trends in the geographic areas in which we operate to improve productivity and margins. We seek to have strong centralized financial analysis and control to allocate our resources and local decision-making and flexibility in the delivery of services to maximize customer satisfaction.
Trends Impacting Our Business
In recent years, our industry has experienced higher demand for oil and natural gas and a constrained oil and natural gas supply which factors have resulted in higher commodity prices and increased drilling activity. We believe this trend of increased prices and drilling activity, as well as other industry trends reflected below, benefit us and facilitate implementation of our business strategy:
• | Increase in drilling and developing unconventional resources. The decline of conventional North American oil and natural gas reservoirs is leading to a shift toward the drilling and development of onshore unconventional oil and natural gas resources, including tight sands, shales and coalbed methane, that require more wells to be drilled and maintained and are also characterized by high decline rates. We believe the increased drilling requirements of these unconventional resources will lead to continued drilling activity. |
• | Increase in fluids used in unconventional horizontal well completions. Completions of unconventional horizontal wells in the Barnett Shale region of the Fort Worth Basin require fresh water. The amount of fresh water used for such completions is significantly greater than the amount of fresh water used for completions of vertical wells. Correspondingly, these unconventional horizontal wells also produce significantly greater quantities of saltwater that must be disposed in permitted disposal wells. |
• | Labor shortages and increasing safety concerns. Due to the increase in rig count and the corresponding increase in demand for labor in the oilfield and offshore, our customers continue to attempt to improve living and working conditions at the wellsite to help retain employees. We believe our workforce accommodations solutions and custom configurations for crew quarters have generally improved living and working conditions at the wellsite resulting in better employee morale and reduced turnover. Our customers also continue to enhance their safety procedures to help reduce injuries and to help ensure compliance with more stringent regulatory requirements. We supply equipment designed to improve |
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onshore wellsite safety and productivity. For example, our extended-reach forklifts eliminate the need to manually roll drill pipe across pipe racks reducing hazards such as pinched fingers or falls. Our manlifts are used to safely place crew members under the rig floor during rig-up and rig-down of wellhead pressure control equipment. Also, our light plants provide safe lighting conditions for night time operations at the wellsite. In addition, offshore workforce accommodations are increasingly required to meet safety standards of the United States Coast Guard and/or the international safety standards of SOLAS. |
• | Increasingly complex technologies. The development of unconventional oil and natural gas resources is driving the need for complex, new technologies to help increase recovery rates, lower production costs and accelerate field development both onshore and offshore. The increasing complexity of technology used in the oil and natural gas development process requires additional technicians on location during drilling and, therefore, additional workforce accommodations. In particular, the increasing trend of pursuing horizontal and directional wells, as indicated in the chart below, as opposed to vertical wells requires additional expertise on location and, typically, longer drilling times. In some cases, up to six to nine workforce accommodation units are used during a drilling project, an increase over traditional utilization levels. Workforce accommodations are required for the company-man (oil and natural gas operator representative), the rig tool pusher (drilling rig supervisor), the rig crew (which typically includes 12-14 persons), a directional driller, a mud engineer, a safety engineer, solids control service personnel (between one and five persons), and other company and service personnel as necessary. |
• | Geographically dispersed drilling operations. Before the consolidation of land-based drilling contractors that began in earnest in the 1990’s, most drilling contractors were regional operators serving an area within a radius of approximately 100 to 200 miles from their home office. Most personnel working at the wellsite would drive to and from the wellsite on a daily basis. With the shift toward industry consolidation, land crews based in one region may now be sent along with a rig to work on wellsites in geographically dispersed oil and natural gas regions significant distances away. This development has resulted in the need for full-time accommodations for multiple shifts of the rig crew. Additionally, the increasing pursuit of unconventional resources has resulted in increasingly remote drilling locations that do not have adequate infrastructure. These remote locations require accommodation units and other equipment and services of the type provided by us. |
• | Increased environmental sensitivity. Continued sensitivity to the environmental impact of drilling and production activities has resulted in increasing regulation of the oil and natural gas industry. Normal onshore wellsite operations use an earthen pit to temporarily store drilling fluids and cuttings. When drilling in environmentally sensitive areas such as marshes or when drilling with oil-based or other synthetic drilling fluids, however, wellsite operations must use closed-loop solids control systems, which require zero discharge of drilling fluids and cuttings at the wellsite. In order to help reduce drill cuttings and fluids disposal costs, operators require customized solids control configurations that |
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attempt to maximize drilling fluid efficiency. Additionally, in some areas of the Rocky Mountains, federal regulators have mandated a reduction of long-term environmental impacts at drilling locations. In some cases, this has required the use of mats in place of traditional scraping by earth moving equipment to preserve prairie sage brush recoverability after wellsite operations cease. We believe that continued sensitivity to the environmental impact of wellsite operations will enhance the demand for our solids control and construction services. |
• | Outsourcing ancillary services. Some of the services we provide have been historically handled by drilling contractors themselves. In many instances, these services are only ancillary to the primary activity of drilling and completing wells and represent only a minor portion of the total well drilling cost. Many drilling contractors are increasingly electing to outsource these services to suppliers who can provide high-quality and reliable services. |
• | Increased deepwater development activity. Advances in subsea exploration and production technology allow oil and natural gas companies to pursue reserves that have historically been considered too remote or uneconomical to exploit, particularly in deepwater regions. In addition to the growth in offshore drilling activity, these advanced technologies require a greater number of technicians during drilling, production and construction activity. We believe these technological advances are leading to significant growth in offshore drilling and production engineering projects. These advances have resulted in the need for significantly greater offshore workforce accommodations. |
• | Increased competition and low barriers to entry. Barriers to entry in many of our areas of operation are minimal and our competitors may offer products and services at a relatively low cost, increasing the amount of competition we face. Additionally, the presence of numerous small companies capable of competing in our markets and several large companies that possess substantially greater financial and other resources than us contributes to the increased competition in our industry. |
Growth Opportunities
We intend to capitalize on emerging trends in the United States oil and natural gas industry through the execution of a growth strategy focused on internal growth opportunities complemented by strategic acquisitions. We also intend to analyze expansion opportunities in international markets.
• | Internal Growth Opportunities. We plan to continue to roll-out our existing services across our current operating regions in an effort to deliver a comprehensive service portfolio in each region where we operate. Additionally, we seek to continue to invest in the development of new assets and services based on customer demand to supplement the breadth and quality of our service portfolio. We also intend to continue expanding our operations into new domestic geographic regions to provide our service offerings to existing customers in markets that we have not historically served, as well as to attract new customers in these markets. We believe our established customer base and strong regional relationships will continue to provide a distribution network for deployment of our services. |
• | Acquisitions. We believe that our segment of the oilfield service industry has historically experienced underinvestment. Consequently, most of our competitors are smaller operators offering a limited set of wellsite support services. As a result of the fragmented nature of our markets, we believe that there are numerous consolidation opportunities within these markets. We intend to continue to leverage our proven capabilities of identifying, executing on and integrating acquisitions to further differentiate our service portfolio and grow our business. |
• | International Expansion. In 2007, we established a subsidiary in The Netherlands, which we believe will provide a base for us to capitalize on strategic growth opportunities in international offshore markets. |
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Strategic Acquisitions
From inception through July 31, 2008, we have completed 37 acquisitions as part of our acquisition and expansion program as reflected in the table below:
Entity | Acquisition Date | Service Sector | Location | |||
Aero Oilfield Services, Inc. | 12/02 | workforce accommodations | South Texas | |||
Ray’s Mobile Homes, Ltd | 4/03 | workforce accommodations | South Texas | |||
Gator Services, Inc. | 10/03 | workforce accommodations | ArkLaTex | |||
Rebel Testers, Inc. | 2/04 | workforce accommodations | (assets relocated) | |||
Stallion Rentals, L.P. | 1/05 | surface equipment rentals | East Texas | |||
Envirotech, Inc. | 1/05 | workforce accommodations | Wyoming | |||
Double-D Enterprises, Inc. | 1/05 | surface equipment rentals | Wyoming | |||
Separation Services, Inc. | 1/05 | solids control | Gulf Coast | |||
Bob’s Equipment Rental, Inc. | 6/05 | workforce accommodations | Wyoming | |||
GL Trucking & Rental, Inc. | 9/05 | workforce accommodations | North Dakota | |||
Trail Blazer Hot Shot, Inc. | 1/06 | surface equipment rentals | Mid-Continent | |||
Pioneer RSC, LP | 2/06 | solids control | Gulf Coast | |||
BLR Construction Companies, L.L.C. | 3/06 | wellsite construction | Gulf Coast | |||
Rental One, LLC | 3/06 | surface equipment rentals | Gulf Coast | |||
Oilfield Heavy Haulers, LLC | 3/06 | rig logistics/trucking | Gulf Coast | |||
R&G Crane & Rigging & Trucking, LLC | 3/06 | rig logistics/trucking | East Texas | |||
Bowie Dozer Service, Inc. | 5/06 | wellsite construction | Fort Worth Basin | |||
Abbeville Offshore Quarters, Inc. | 8/06 | offshore workforce accommodations | Gulf Coast/ International | |||
G&N Rentals | 9/06 | surface equipment rentals | North Dakota | |||
Erlandson Construction Company | 11/06 | wellsite construction | Fort Worth Basin | |||
Norton Transport, Inc. | 12/06 | rig logistics/trucking | East Texas/Fort Worth Basin | |||
Suttee Enterprises | 2/07 | surface equipment rentals | Oklahoma | |||
La Mission Rentals | 2/07 | workforce accommodations | West Texas | |||
The Waterline Company, LLC | 3/07 | wellsite construction | Fort Worth Basin | |||
Shores Energy, Inc. | 4/07 | rig logistics/trucking | Oklahoma | |||
Fluid Processors, Inc. | 5/07 | solids control | Wyoming | |||
Central Holdings, Inc. | 6/07 | wellsite construction | Gulf Coast | |||
Burns Services, LLC | 6/07 | workforce accommodations | ArkLaTex | |||
Rowan Alaska Camps | 6/07 | workforce accommodations | Prudhoe Bay, Alaska | |||
Patriot Liquid Services, L.P. | 7/07 | production services | Fort Worth Basin | |||
Bayou Tank Services, Ltd. | 7/07 | production services | East Texas | |||
Salty’s Entities | 8/07 | production services | Fort Worth Basin/ArkLaTex | |||
Twin B Enterprises | 9/07 | production services | East Texas | |||
A&B Construction and Painting, Inc. | 10/07 | wellsite construction | Wyoming | |||
Polleyco Construction Services LP | 1/08 | wellsite construction | Fort Worth Basin/ArkLaTex | |||
Mile High Oilfield Services | 6/08 | workforce accommodations | Utah | |||
J-M Oil Company, Inc. | 7/08 | production services | Appalachian Basin |
We intend to continue to develop or acquire new high-quality, strategic assets and services which add to the scope and quality of our service portfolio. Since our inception through July 31, 2008, we have invested an aggregate of approximately $692.0 million in acquisitions.
We evaluate our acquisitions based on a number of factors including: market region, service line, asset quality, customers, management, service and safety quality and financial performance. We base our valuations on several factors including: revenue multiples, EBITDA multiples, asset value, earnings accretion and strategic value.
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The following is a description of some of the strategic acquisitions that expanded our service offerings and geographic reach:
Expansion of Service Offerings
Workforce Accommodations and Surface Equipment Rental. In April 2003, we acquired the assets of Ray’s Mobile Homes, Ltd. (“Ray’s Mobile Homes”). Ray’s Mobile Homes was engaged in the business of providing workforce accommodations, sewer and water systems, trash containers and other related equipment to wellsites in South Texas. With this acquisition, we entered the workforce accommodations and surface equipment rental business.
Solids Control. In January 2005, we acquired Separation Services, Inc. (“SSI”), a Texas company engaged in customized solids control services to oil and natural gas companies and drilling contractors at wellsite locations. With this acquisition, we entered into the solids control business. In August 2007, we changed the name of SSI to Stallion Solids Control, Inc.
Wellsite Construction. In March 2006, we acquired BLR Construction Companies, L.L.C. (“BLR”). BLR provides customers with experienced personnel and high-quality equipment, specializing in location construction, pipeline construction, marine services, production facility construction, crew services, heavy equipment and trucking services, remediation services, production decommissioning and vegetation control. BLR also provides inland marine wellsite construction services. With this acquisition, we moved into the wellsite construction business. In August 2007, we changed the name of BLR to Stallion Oilfield Construction, LLC (“Stallion Oilfield Construction”).
Logistics. In March 2006, we acquired the assets of Oilfield Heavy Haulers (“OHH”). OHH provides heavy-duty drilling rig trucking and hauling services to the oilfield. OHH’s assets included a fleet of cranes, rig-hauling trucks, trailers and loaders specifically designed for the oil and natural gas industry. With this acquisition, we entered the rig relocation and heavy equipment hauling business. In August 2007, we changed the name of OHH to Stallion Heavy Haulers.
Production Services. In July 2007, we purchased the assets of Patriot and Bayou Tank and in August 2007 we purchased the assets of Salty’s. Patriot provides saltwater injection wells, frac tank rental and vacuum trucks. Bayou Tank leases frac tanks to, and performs other oilfield-related services for, oilfield, refining and industrial customers. Salty’s provides frac tank rentals and sales and saltwater hauling and disposal services. With these acquisitions, we entered the production services business.
Integrated Services. In January 2008, we purchased the assets of Polleyco for consideration of approximately $12.0 million paid at closing and contingent consideration of up to $36.0 million payable over a three-year period if certain financial performance targets are met. Polleyco provides integrated oilfield services, including wellsite permitting, design and construction of water districts, wellsite construction, site maintenance, fluid logistics solutions and other services to expedite drilling, completion, and production activities, to oil and natural gas operators in the Barnett Shale region of the Fort Worth Basin and Fayetteville Shale areas.
Expansion of Geographic Reach
Rocky Mountains Expansion. In January 2005, we acquired the assets of Envirotech, Inc. (“Envirotech”), a company engaged in the rental of workforce accommodations, water systems, sewer systems and other related equipment. This acquisition provided a platform for expansion into the Rocky Mountain region, which is a region currently experiencing high levels of drilling activity.
Williston Basin Expansion. In September 2005, we acquired the assets of GL Trucking & Rental, Inc. (“GL Trucking”). GL Trucking provides integrated drilling support services for the Williston Basin, which is located in parts of North and South Dakota, Montana and Canada and surrounding areas. Its assets included over 100 workforce accommodation units, significant heavy equipment hauling capacity, loaders and equipment setting cranes. This acquisition extended our geographic footprint in the Rocky Mountains and brought our services to the Williston Basin.
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Fort Worth Basin Expansion. In May 2006, we acquired the assets of Bowie Dozer Service, Inc. (“Bowie”). Bowie is an oilfield construction company that provides location construction and heavy equipment services for rig sites in the Fort Worth Basin. The purchased assets included dozers, loaders, graders, backhoes, trackhoes and rollers. This acquisition provided a platform for us to expand into the Fort Worth Basin, an active natural gas producing area.
Gulf of Mexico. In August 2006, we acquired all of the outstanding capital stock of Abbeville Offshore Quarters, Inc. (“AOQ”). AOQ provides offshore workforce accommodations, sewage treatment units, water systems, and other rental support equipment for use in the Gulf of Mexico oil and natural gas industry and, to a lesser extent, other international offshore regions. In August 2007, we changed the name of AOQ to Stallion Offshore Quarters, Inc.
Alaska. In June 2007, we acquired certain assets of Rowan Drilling Company, Inc. and Rowan Companies, Inc. The purchased assets included accommodation units, ancillary yard equipment and remote wellsite services. This acquisition provided a platform for us to expand into the Prudhoe Bay field in Alaska, an active oil and natural gas producing area.
Appalachian Basin. In July 2008, we acquired the assets of J-M Oil Company, Inc. (“J-M Oil”) and related entities for a purchase price of approximately $3.5 million. J-M Oil provides saltwater disposal, fluid handling and site construction services to its customers. Its assets include saltwater injection wells, vacuum trucks, frac tanks, tractors, bulldozers and backhoes. This acquisition provided a platform for expansion in the Appalachian Basin, which is a region currently experiencing high levels of drilling activity.
Items Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable to our results of operations in the future for the reasons discussed below.
Changes in Our Legal Structure
We were formed as a Delaware corporation in June 2006. Our operations have historically been conducted by Stallion Ltd., a Texas limited partnership, and its operating subsidiaries. Pursuant to an agreement and plan of merger, Stallion Holdings, Ltd. will be merged with and into Stallion Oilfield Services, Inc. immediately prior to the closing of this offering with Stallion Oilfield Services, Inc. as the surviving parent company. Since the entities are under common ownership and control, the Restructuring will be accounted for at historical cost. Following this offering, we will report our results of operations and financial condition as a corporation on a consolidated basis. For more information about the restructuring, please see “Certain Relationships and Related Party Transactions—The Restructuring.”
Historically, we were not subject to federal or state income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Our combined financial statements included in this prospectus include a pro forma adjustment for income taxes calculated at a statutory rate of 38% resulting in a pro forma net income adjusted for income taxes. In 2005, 2006 and 2007, Stallion Ltd. made capital distributions to its partners to fund tax obligations resulting from the partners being taxed on their proportionate share of Stallion Ltd.’s taxable income. As a result of the Restructuring, we will record deferred tax assets and liabilities to reflect net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial and tax reporting purposes. Giving effect to the Restructuring, as of June 30, 2008, we estimate that our noncurrent net deferred tax liability would have been approximately $9.1 million, resulting primarily from accelerated depreciation taken by Stallion Ltd. and its subsidiaries. Following this offering, we will incur income taxes under our new corporate structure and our consolidated financial statements will reflect the actual impact of income taxes.
Public Company Expenses
We believe that our selling, general and administrative expenses will increase as a result of becoming a public company following this offering. We currently anticipate that our total annual selling, general and administrative expenses following the completion of this offering will increase by approximately $3.0 million to
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$5.0 million. This increase will be due to the cost of tax return preparations, accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees, which we expect to incur after the completion of this offering. Our consolidated financial statements following this offering will reflect the impact of these increased expenses and will affect the comparability of our financial statements with periods prior to the completion of this offering.
Acquisitions
Since our inception through July 31, 2008, we have completed 37 acquisitions as part of our acquisition and expansion program. Following this offering, we intend to continue pursuing strategic acquisitions. Our consolidated financial statements included elsewhere in this prospectus do not reflect the results of operations of businesses we acquired or will acquire following the date of those financial statements.
Critical Accounting Policies and Estimates
Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. A complete summary of these policies is included in Note 1 of the notes to our historical consolidated financial statements. The following is a discussion of our critical accounting policies and estimates.
Critical Accounting Policies
We have identified below accounting policies that are of particular importance in the presentation of our financial position, results of operations and cash flow and which require the application of significant judgment by management.
Property, Plant and Equipment. Property, plant and equipment, including renewals and betterments, are stated at cost, while maintenance and repairs are expensed as incurred. We review our assets for impairment when events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the estimated future cash flow, on an undiscounted basis, is less than the assets’ carrying amount. If impairment is indicated, an impairment charge is recorded based on an estimate of future discounted cash flow.
Self-Insured Risk Accruals. We are partially self-insured for certain losses relating to workers’ compensation, automobile, general liability insurance claims and health plan coverage. We maintain accruals to cover the self-insured risks, which are based on third-party data and historical claims history.
Revenue Recognition. We recognize revenue when it is realized and earned. We consider revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collection is reasonably assured. Delivery is not considered to have occured until the customer takes title and assumes the risks and rewards of ownership, which is generally on the date of shipment. Generally, we provide our services over a relatively short period of time pursuant to short-term arrangements at pre-determined service rates or on a project bid basis. Revenue from rental agreements is recognized over the rental period, and revenue from service agreements is recognized when services have been rendered. Certain of our operations recognize revenue related to wellsite construction using the percentage-of-completion method determined by the ratio of costs incurred to total estimated costs at completion. All known or anticipated losses on contracts are recognized in full when such losses become apparent. Our percentage-of-completion contracts typically range from two to six months in duration.
In our wellsite support services segment we charge our customers a rig-up/rig-down charge in connection with the initial set up or takedown of workforce accommodation units and for the connection or disconnection of these units to or from water, power and sewer systems. Revenue related to rig-up/rig-down charges is recognized upon completion of the service. We recognize revenue when it is earned and realized. We consider revenue earned and realized when the services are performed, collection of the relevant receivables is reasonably assured, persuasive evidence of the arrangement exists and the price is fixed and determinable.
Income Taxes. We account for income taxes based upon Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, deferred tax assets and liabilities are
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recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.
Historically, we were not subject to federal or state income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Our income tax expense will be comprised of current and deferred tax expense. These taxes added together provide an indication of an effective rate of income tax.
Critical Accounting Estimates
The preparation of our financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet dates and the amounts of revenue and expenses recognized during the reporting periods. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates.
Impairment of Long-Lived Assets and Goodwill. Our review for potential impairment of property, plant and equipment requires us to estimate undiscounted future cash flow. Actual impairment charges are recorded using an estimate of discounted future cash flow. The determination of future cash flow requires us to estimate rates and utilization in future periods and such estimates can change based on market conditions, technological advances in industry or changes in regulations governing the industry. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used in operations is measured by a comparison of the carrying amount of an asset to estimated undiscounted cash flow expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flow, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of carrying amount or the fair value less anticipated cost to sell, and they would no longer be depreciated.
We have adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires us to annually test goodwill and intangible assets with indefinite useful lives recorded in business combinations for potential impairment. All of our intangible assets other than goodwill are subject to amortization. This requires us to estimate the fair values of our assets and liabilities at the reporting unit level. Therefore, considerable judgment, similar to that described above in connection with our estimation of the fair value of an acquired company, is required to assess goodwill and certain other intangible assets for impairment.
Goodwill and Other Intangible Assets. The initial recording of goodwill and other intangibles requires estimation of the fair value of assets and liabilities using fair value measurements, which include quoted market price, present value techniques (estimate of future cash flows), and other valuation techniques. Additionally, SFAS No. 142 requires goodwill and other intangible assets to be reviewed for possible impairment on an annual basis, or if circumstances indicate that an impairment may exist. Determining fair value and implied fair value is subjective and often involves the use of estimates and assumptions. These estimates and assumptions could have a significant impact on the recording of intangible assets, whether or not an impairment charge is recognized and also the magnitude of the impairment charge. Our estimates of fair value are primarily determined using present value techniques of projected cash flows. This approach uses significant assumptions such as multi-year sales projections with associated expenses. We have performed impairment analyses on our goodwill, which indicated as of December 31, 2007 an impairment charge was not appropriate. No events have occurred since December 31, 2007 which would cause us to reevaluate goodwill.
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Allowance for Doubtful Accounts. We extend credit to our customers based on an evaluation of their financial condition, and generally, we do not require collateral nor do we charge interest on our accounts receivable. We estimate our allowance for doubtful accounts based on an analysis of historical collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial position of significant customers and (2) a decline in commodity prices that could affect our entire customer base. If these factors are less favorable than those projected by management or if our historical experience is materially different from our future experience, additional allowances may be required.
Litigation and Other Risk Reserves. We estimate required reserves related to litigation and insurance deductibles based on the facts and circumstances specific to the litigation and insurance claims and our past experience with similar claims. The actual outcome of litigated and insured claims could differ significantly from estimated amounts. Any such accruals are based on certain assumptions developed using third-party and historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual settlements.
Depreciation and Amortization. In order to depreciate and amortize our property, plant and equipment and our intangible assets with finite lives, we estimate the useful lives and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry.
Fair Value of Assets Acquired and Liabilities Assumed. We estimate the value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the oil and natural gas industry or changes in regulations governing that industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property, plant and equipment, and the resulting amount of goodwill, if any. To finalize purchase accounting, for significant acquisitions we utilize the services of independent valuation specialists to assist in the determination of the fair value of acquired assets. These estimates are revised during an allocation period as necessary when, and if, information becomes available to further define and quantify the value of the assets acquired and liabilities assumed. To the extent additional information to refine the original allocation becomes available during the allocation period, the allocation of the purchase price is adjusted. If information becomes available after the allocation period, those items are reflected in operating results.
Income Taxes. Our income tax expense includes local, state and federal income taxes. We account for tax ramifications using SFAS No. 109 “Accounting for Income Tax.” Under SFAS No. 109, we record deferred income tax assets and liabilities based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measure tax expense using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in tax rate is recognized in income in the period of the change. Furthermore, SFAS No. 109 requires a valuation allowance for any net deferred income tax assets which we believe are likely to not be used through future operations. If our estimates and assumptions related to our deferred tax position change in the future, we may be required to record additional valuation allowances against our deferred tax assets and our effective tax rate may increase, which could result in a material adverse effect on our financial position, results of operations and cash flow.
Stock-Based Compensation. In December 2004, the FASB issued SFAS No. 123R, “Share-based Payment,” which revises SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123R requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award, with limited exceptions. The fair value of the award must be re-measured at each reporting date through the settlement date, with changes in fair value recognized as compensation expense of the period. SFAS No. 123R requires that we use an option-pricing model, adjusted for the unique characteristics of those instruments, to determine fair value as of the grant date of the stock options. In so doing, we use an option-pricing model (Black-Scholes), which requires various assumptions as to interest rates, volatility, dividend yields and expected lives of stock-based awards.
Cash Flow Estimates. Our estimates of future cash flow are based on the most recent available market and operating data for the applicable asset or reporting unit at the time we made the estimate. Our cash flow estimates are used for asset impairment analyses.
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The following table describes estimates, assumptions and methods regarding critical accounting estimates used to prepare our consolidated financial statements. We consider an estimate to be critical if it is subjective and if changes in the estimate using different assumptions would result in a material impact on our financial position or results of operations:
Description | Estimates/Assumptions Used | Variability in Accounting | Historical Results | |||
Revenue Recognition | We recognize revenue when it is realizable and earned as services are performed. We defer unearned revenue until earned.
| There is a risk that we may not record revenue in the proper period.
| We did not record material adjustments resulting from revenue recognition issues for the years ended December 31, 2005, 2006 and 2007 or the six months ended June 30, 2007 and 2008.
| |||
On uncompleted contracts, we estimate the revenue to be recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion.
| There is a risk that management’s estimate of total costs at completion is incorrect, and that the result could materially impact our financial position and results of operations. | With the purchase of AOQ and BLR in 2006, revenue recognition on uncompleted contracts became a significant management estimate. If total estimated costs at completion had increased or decreased by 1%, revenue recognized utilizing the percentage of completion method for the year ended December 31, 2007 and the six months ended June 30, 2008 would be overstated or understated by approximately $40,000 and $33,000, respectively.
| ||||
Impairment of Long-lived Assets |
We evaluate the recoverability of assets periodically, but at least annually for goodwill and intangible assets with indefinite lives, by reviewing operational performance and expected cash flows. Our management estimates future cash flows for this purpose and for intangible assets, discounts these cash flows at an applicable rate. |
There is a risk that management’s estimates of future performance may not approximate actual performance or that rates used for discounting cash flows are not consistent with the actual discount rates. Our assets could be overstated if impairment losses are not identified in a timely manner. |
We tested goodwill for impairment for each of the years ended December 31, 2005, 2006 and 2007, and management determined that goodwill was not impaired. No events have occurred since December 31, 2007 that would cause us to reevaluate goodwill. A significant decline in expected future cash flow as a result of lower revenue, could result in an impairment charge. For example, a change of 1% in discounted cash flows would not result in an impairment of goodwill. |
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Description | Estimates/Assumptions Used | Variability in Accounting | Historical Results | |||
Allowance for Doubtful Accounts |
We estimate the recoverability of receivables on an individual basis based upon historical experience and management’s judgment. |
There is a risk that management may not detect uncollectible accounts in the correct accounting period. |
Bad debt expense has been less than 1% of revenue for each of the years ended December 31, 2005, 2006 and 2007. For the six months ended June 30, 2007 and 2008, bad debt expense was $1.1 million and $0.6 million, respectively. If bad debt expense had increased by 1% for the year ended December 31, 2007 and the six months ended June 30, 2008, net income would have declined by $4.3 million and $2.9 million, respectively. | |||
Litigation and Self-Insured Risk Reserves |
We estimate our reserves related to litigation and self-insured risk based on facts and circumstances specific to the litigation and self-insured risk claims and our past experiences with similar claims. |
There is a risk that the actual outcome of litigation and/or self insured claims could differ significantly from our estimates. |
Expense related to litigation and self-insured risk has been less than 1% of revenue for each of the years ended December 31, 2005, 2006 and 2007 and the six months ended June 30, 2007 and 2008. If this expense had increased by 1% for the year ended December 31, 2007 and the six months ended June 30, 2008, net income would have declined by $4.3 million and $2.9 million, respectively. |
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Index to Financial Statements
Description | Estimates/Assumptions Used | Variability in Accounting | Historical Results | |||
Property, Plant and Equipment |
Our management estimates useful lives of depreciable equipment and salvage values. The depreciation method used is generally the straight-line method, except for furniture and office equipment which is depreciated on an accelerated basis. |
GAAP permits various depreciation methods to recognize the use of assets. Use of a different depreciation method or different depreciable lives could result in materially different results. The estimated useful lives are consistent with industry averages. There is a risk that the asset’s useful life used for our depreciation calculation will not approximate the actual useful life of the asset. |
We evaluate property, plant and equipment for impairment when there are indicators of impairment. There have been no impairment charges related to our long-term assets during the years ended December 31, 2005, 2006 and 2007. Depreciation expense for the year ended December 31, 2007 and the six months ended June 30, 2008 represented 13.7% and 11.7% of the average depreciable asset base for those periods, respectively. An increase in depreciation relative to the depreciable base of 1%, from 11.7% to 12.7% at June 30, 2008 and from 13.7% to 14.7% at December 31, 2007, would have reduced net income by approximately $5.2 million and $3.7 million, respectively. | |||
In April 2008, we adjusted the estimated useful lives of certain vehicles from two to three years and certain rental equipment from a range of 10-15 years to a range of 15-20 years. The change in estimated useful lives resulted in a decrease in depreciation expense of approximately $1.7 million for the three and six months ended June 30, 2008. |
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Index to Financial Statements
Description | Estimates/Assumptions Used | Variability in Accounting | Historical Results | |||
Valuation Allowance for Income Taxes |
We apply the provisions of SFAS No. 109 to account for income taxes. Differences between depreciation methods used for financial reporting purposes compared to tax purposes as well as other items, including loss carry forwards and valuation allowances against deferred tax assets require management’s judgment related to the realizability of deferred tax accounts. |
There is a risk that estimates related to the use of loss carry forwards and the realizability of deferred tax accounts may be incorrect, and that the result could materially impact our financial position and results of operations. In addition, future changes in tax laws could result in additional valuation allowances. |
Historically, we have not had to record a valuation allowance to reflect that our deferred tax assets would not be utilized through future operations. Deferred income tax assets totaled $0.6 million and $0.5 million at December 31, 2007 and June 30, 2008, respectively. We have not recorded a valuation allowance since we believe that the deferred tax asset is realizable. If we were required to record a valuation allowance it would affect our net income on a dollar for dollar basis. | |||
Stock-Based Compensation | We have adopted the provisions of SFAS No. 123R which requires that we measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of those instruments on their grant date. The fair value of these instruments must be re-evaluated at each reporting date through the settlement date with changes in fair value recognized as compensation expense of the period. | GAAP permits the use of various models to determine the fair value of stock options and the variables used for the model are subjective. We have estimated the value of stock grants in accordance with conventional valuation techniques including but not limited to net book value and comparable company multiples of EBITDA as applicable. The use of different assumptions or a different model may have a material impact on our results of operations and related disclosures. | Historically, restricted equity in Stallion Holdings, Ltd. was issued to Stallion Value, L.P. (“Stallion Value”) in conjunction with equity contributions. Stallion Value has granted certain of our employees units representing limited partnership interests in Stallion Value. We have not granted stock options to employees. In the year ended December 31, 2007 and the six months ended June 30, 2008, we had no compensation expense from stock grants. |
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Results of Operations
Prior to 2003, we did not have significant operations. We began our strategic acquisition and expansion program early in 2003 and operated in one business segment, wellsite support services, which at that time consisted only of our workforce accommodations and surface equipment rental business. In 2005, with our acquisition of Stallion Solids Control, we established our solids control service line, which is part of our wellsite support services operating segment. In March 2006, we established our second operating segment, production & logistics services, when we acquired Stallion Heavy Haulers and Stallion Oilfield Construction. In August 2006, we substantially augmented our wellsite support services segment and entered the offshore workforce accommodation business by acquiring Stallion Offshore Quarters. In July and August of 2007, we entered the production services business with our acquisitions of the assets of Patriot, Bayou Tank and Salty’s.
When we acquire a business or make capital expenditures we immediately integrate those newly acquired assets into the operations of one of the business units in our existing operating segments for financial accounting purposes. We do not generally maintain separate accounting records of those acquisitions; rather we evaluate them based upon the overall results of the business units into which they were integrated. Please read “—Overview—How We Evaluate Our Operations.”
The following table sets forth our results of operations for the periods indicated. Our results of operations between the periods presented vary significantly primarily due to the number of acquisitions made during the presented periods and the relative timing of the acquisitions during those periods. All acquisitions are included in our historical results of operations from their respective dates of acquisition. See the notes to our historical consolidated financial statements for more detail.
Year ended December 31, | Variance 2005 to 2006 | Variance 2006 to 2007 | Six Months Ended June 30, | Variance 2007 to 2008 | |||||||||||||||||||||||||||||||||||||
2005 | 2006 | 2007 | $ | % | $ | % | 2007 | 2008 | $ | % | |||||||||||||||||||||||||||||||
Statement of Operations Data: | (dollars in thousands) | (unaudited) | |||||||||||||||||||||||||||||||||||||||
Revenue: | |||||||||||||||||||||||||||||||||||||||||
Wellsite support services | $ | 73,126 | $ | 162,661 | $ | 215,265 | $ | 89,535 | 122.4 | % | $ | 52,604 | 32.3 | % | $ | 97,442 | $ | 126,220 | $ | 28,778 | 29.5 | % | |||||||||||||||||||
Production & logistics services | 77,749 | 211,930 | 77,749 | — | 134,181 | 172.6 | % | 74,948 | 162,090 | 87,142 | 116.3 | % | |||||||||||||||||||||||||||||
Total revenue | 73,126 | 240,410 | 427,195 | 167,284 | 228.8 | % | 186,785 | 77.7 | % | 172,390 | 288,310 | 115,920 | 67.2 | % | |||||||||||||||||||||||||||
Expenses: | |||||||||||||||||||||||||||||||||||||||||
Wellsite support services | 42,281 | 88,029 | 118,029 | 45,748 | 108.2 | % | 30,000 | 34.1 | % | 53,512 | 72,001 | 18,489 | 34.6 | % | |||||||||||||||||||||||||||
Production & logistics services | — | 52,679 | 151,526 | 52,679 | — | 98,847 | 187.6 | % | 52,376 | 121,400 | 69,024 | 131.8 | % | ||||||||||||||||||||||||||||
Selling, general and administrative | 9,883 | 19,170 | 40,027 | 9,287 | 94.0 | % | 20,857 | 108.8 | % | 17,191 | 20,935 | 3,744 | 21.8 | % | |||||||||||||||||||||||||||
Depreciation and amortization | 7,798 | 30,068 | 62,743 | 22,270 | 285.6 | % | 32,675 | 108.7 | % | 24,659 | 36,516 | 11,857 | 48.1 | % | |||||||||||||||||||||||||||
Loss (gain) on disposal of assets | 499 | 920 | 44 | 421 | 84.4 | % | (876 | ) | -95.2 | % | 979 | (101 | ) | (1,080 | ) | -110.3 | % | ||||||||||||||||||||||||
Total expenses | 60,461 | 190,866 | 372,369 | 130,405 | 215.7 | % | 181,503 | 95.1 | % | 148,717 | 250,751 | 102,034 | 68.6 | % | |||||||||||||||||||||||||||
Operating income | 12,665 | 49,544 | 54,826 | 36,879 | 291.2 | % | 5,282 | 10.7 | % | 23,673 | 37,559 | 13,886 | 58.7 | % | |||||||||||||||||||||||||||
Interest expense, net | (4,565 | ) | (18,919 | ) | (52,874 | ) | (14,354 | ) | 314.4 | % | 33,955 | 179.5 | % | (20,581 | ) | (34,558 | ) | (13,977 | ) | 67.9 | % | ||||||||||||||||||||
Other income (expense) | (66 | ) | 71 | 207 | 137 | NM | 136 | 191.5 | % | 147 | 374 | 227 | 154.4 | % | |||||||||||||||||||||||||||
Income before income tax | 8,034 | 30,696 | 2,159 | 22,662 | 282.1 | % | (28,537 | ) | -93.0 | % | 3,239 | 3,375 | 136 | 4.2 | % | ||||||||||||||||||||||||||
Income tax (expense) benefit | (598 | ) | (4,927 | ) | (6,410 | ) | (4,329 | ) | NM | 1,483 | 30.1 | % | (2,345 | ) | (5,805 | ) | (3,460 | ) | 147.5 | % | |||||||||||||||||||||
Net income (loss) | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | $ | 18,333 | 246.5 | % | $ | (30,020 | ) | -116.5 | % | $ | 894 | $ | (2,430 | ) | $ | (3,324 | ) | -371.8 | % | |||||||||||||||
NM-denotes not meaningful.
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Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007
Revenue.
Consolidated revenue for the six months ended June 30, 2008 increased $115.9 million, or 67.2%, compared to the same period of 2007. For the six months ended June 30, 2008, our wellsite support services segment comprised approximately 43.8% of our total revenue compared to approximately 56.5% for the same period of 2007. Our production & logistics services segment became more significant in the second half of 2007 as a result of acquisitions made and organic growth of this segment. For the six months ended June 30, 2008, production & logistic services comprised approximately 56.2% of our total revenue compared to 43.5% of our total revenue for the same period in 2007. The revenue increase by operating segment was as follows:
Wellsite Support Services—Segment revenue increased $28.8 million, or 29.5%, to $126.2 million for the six months ended June 30, 2008 compared to the same period of 2007. The increase in segment revenue resulted principally from acquisitions made during the twelve months ended June 30, 2008 combined with organic growth through approximately $46.2 million in capital expenditures during that twelve month period. In addition, the increase in revenue also resulted from improving utilization of our assets and modest improvement in our pricing compared to the second quarter of 2007.
Production & Logistics Services—Segment revenue increased $87.1 million, or 116.3%, for the six months ended June 30, 2008 compared to the same period of 2007 principally as a result of our acquisitions of Bayou Tank, Patriot Liquid Services and the Salty’s group of entities in July and August 2007.
Operating Expense.
Our operating expense for the six months ended June 30, 2008 increased $102.0 million, or 68.6%, compared to the first six months of 2007.
Expenses directly related to the operation of each of our operating segments include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of our equipment. For the six months ended June 30, 2008, these expenses increased $87.5 million, or 82.6%, compared to the same period of 2007. The increase in these costs by operating segment was as follows:
Wellsite Support Services—Direct segment operating cost increased $18.5 million, or 34.6%, for the six months ended June 30, 2008 compared to the same period in 2007 as a result of acquisitions made subsequent to June 30, 2007. Direct operating expenses as a percentage of segment revenue increased from 54.9% for the first six months of 2007 to 57.0% for the same period in 2008. The increase in these costs as a percentage of revenue resulted principally from increased operating cost in 2008, especially labor and fuel costs which have increased 34.6% and 97.2%, respectively.
Production & Logistics Services—Direct segment operating costs increased $69.0 million to $121.4 million for the six months ended June 30, 2008 from $52.4 million in the same period of 2007 principally due to the acquisitions of Bayou Tank, Patriot Liquid Services and the Salty’s group of entities in July and August 2007. As a percentage of segment revenue, direct segment operating costs were 74.9% for the six months ended June 30, 2008 compared to 69.9% for the six months ended June 30, 2007, principally as a result of increased head count and operations within this segment resulting from the acquisitions completed during the twelve-month period ended June 30, 2008. Increased operating costs, principally the cost of fuel in our fluids hauling operations and the cost of steel at our manufacturing facility, have also resulted in lower operating margins in this segment.
Selling, General and Administrative Expense.
Selling, general and administrative expense consists primarily of salaries and other related expenses for our sales, marketing, administrative, finance, information technology and human resources functions. For the six
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months ended June 30, 2008, selling, general and administrative expenses increased $3.7 million, or 21.8%, compared to the same period in 2007. This increase was primarily due to (i) the acquisitions that we made subsequent to June 30, 2007, which added field support personnel who are accounted for in selling, general and administrative expenses and (ii) an increase in our corporate headcount during the same period. As a percentage of revenue, selling, general and administrative expenses decreased from 10.0% for the six months ended June 30, 2007 to 7.3% for the six months ended June 30, 2008.
Depreciation and Amortization Expense.
Effective April 1, 2008, we changed the estimated useful lives of certain vehicles from two years to three years and certain rental equipment from 10 – 15 years to 15 – 20 years to more closely approximate the actual service lives of those assets that have been placed in service to date. The change in estimated useful lives was based upon a change in the estimated future benefits we expect to receive from those assets and information available regarding those benefits. The change in estimated useful lives resulted in a decrease in depreciation expense of approximately $1.7 million for the six months ended June 30, 2008. The change in estimated useful lives has been accounted for prospectively beginning April 1, 2008.
Depreciation and amortization expense for the six months ended June 30, 2008 increased 48.1%, or $11.9 million, compared to the same period in 2007. The increase in depreciation and amortization expense was the result of additional equipment and intangible assets acquired through capital expenditures and acquisitions which more than offset the effect of the change in estimated useful lives of certain autos and rental equipment mentioned above. As a percentage of revenue, depreciation and amortization expense was 14.3% for the six months ended June 30, 2007 compared to 12.7% for the same period of 2008.
Interest Expense.
Interest expense was $34.6 million for the six months ended June 30, 2008 compared to $20.6 million for the same period in 2007. Included in interest expense for the six months ended June 30, 2007 is $4.8 million of unamortized deferred debt issuance cost related to our Term B Loan that was retired using a portion of the proceeds from the issuance of our 9.75% Senior Notes in January 2007. An increase in the average amount of debt outstanding in the six months ended June 30, 2008 versus the six months ended June 30, 2007 contributed to the increase in interest expense. This increase in debt resulted from: debt incurred in connection with acquisitions completed and capital expenditures made in 2007 and 2008 and the amendment and restatement of our credit facility in late June 2007, which increased our revolving credit facility from $125 million to $175 million and added a new $75 million Term B Loan.
The weighted average interest rate on our outstanding debt decreased from 9.6% at June 30, 2007 to 8.0% at June 30, 2008. The decrease in our weighted average interest rate is principally related to lower rates of interest charged by our banks. We expect that future interest expense may increase as a consequence of the increased level of debt and changes in our debt. Our actual interest expense will depend in part on the prevailing interest rates and our revolving credit balances, which in turn will depend on our available cash flow from operations.
Income Tax Expense.
We are not subject to federal or state income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Our income tax expense is comprised of current and deferred tax expense. These taxes added together provide an indication of an effective rate of income tax. Our tax expense was $2.3 million and $5.8 million for the six months ended June 30, 2007 and 2008, respectively. Because we do not file a consolidated income tax return, our effective tax rate of 172.0% for the six months ended June 30, 2008 results principally from operating losses created by our corporate overhead which cannot be utilized to offset operating profit generated by our taxable “C” corporations. The State of Texas margin tax resulted in an approximate 27.8% increase in our effective tax rate. Following this offering and the Restructuring, we will incur income taxes due to our status as a “C” corporation.
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Index to Financial Statements
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenue.
Our revenue for the year ended December 31, 2007 increased $186.8 million, or 77.7%, compared to the same period of 2006. For the year ended December 31, 2007 our wellsite support services segment comprised approximately 50.4% of our total revenue compared to approximately 67.7% for the same period of 2006. Our production & logistics services segment became more significant in 2007 as a result of acquisitions made in mid-third quarter 2007 and organic growth of this segment. For the year ended December 31, 2007, production & logistic services comprised approximately 49.6% of our total revenue compared to 32.3% in 2006. The revenue increase by operating segment was as follows:
Wellsite Support Services—Segment revenue increased $52.6 million, or 32.3%, to $215.3 million for the year ended December 31, 2007 compared to the same period of 2006. The increase in segment revenue resulted principally from acquisitions made in 2007 combined with organic growth as we executed our capital expenditures program.
Production & Logistics Services—Segment revenue increased $134.2 million, or 172.6%, for the year ended December 31, 2007 compared to the same period of 2006 as a result of our acquisitions of Stallion Heavy Haulers and Stallion Oilfield Construction in March 2006. Our production services acquisitions accounted for approximately $38.8 million of the increased revenue. The remainder of the increase resulted from organic growth combined with the other 2007 acquisitions that are accounted for in this segment.
Operating Expense.
Our operating expense for the year ended December 31, 2007 increased $181.5 million, or 95.1%, compared to the same period of 2006.
Expenses directly related to the operation of each of our operating segments include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of our equipment. The decreased utilization in both of our operating segments resulted in our fixed operating expenses comprising a relatively larger percentage of our cost thereby reducing our operating margins. For the year ended December 31, 2007, these expenses increased 91.6%, or $128.8 million, compared to the same period of 2006. The increase in these costs by operating segment was as follows:
Wellsite Support Services—Direct segment operating cost increased $30.0 million, or 34.1%, for the year ended December 31, 2007 compared to the same period in 2006 principally as a result of acquisitions made subsequent to December 31, 2006. Direct operating expenses as a percentage of segment revenue increased from 54.1% for the year 2006 to 54.8% for the year 2007. The increase in these costs as a percentage of revenue resulted principally from our fixed operating expenses making up a relatively larger percentage of our cost, thereby reducing our operating margins.
Production & Logistics Services—Our acquisition of Stallion Heavy Haulers and Stallion Oilfield Construction in March 2006 marked the establishment of our production & logistics services operating segment. Direct segment operating costs increased $98.8 million for the year ended December 31, 2007 from $52.7 million in the same period of 2006 due to adding segment operations in 2006. As a percentage of segment revenue, direct segment operating costs were 71.5% for the year ended December 31, 2007 compared to 67.8% for the year ended December 31, 2006, principally as a result of cost associated with our productions services entities that were acquired in the third quarter of 2007.
Selling, General and Administrative Expense.
Selling, general and administrative expense consists primarily of salaries and other related expenses for our sales, marketing, administrative, finance, information technology and human resources functions. For the year
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ended December 31, 2007, selling, general and administrative expenses increased $20.9 million, or 108.8%, compared to the same period of 2006. This increase was primarily due to (i) the acquisitions that we made subsequent to December 31, 2006, which added field support personnel who are accounted for in selling, general and administrative expenses and (ii) an increase in our corporate headcount supporting the increased field operations. Additional costs were incurred for outside consulting services for accounting, tax and information technology in connection with integration of acquired companies into our business network. As a percentage of revenue, selling, general and administrative expenses increased from 8.0% for the year ended December 31, 2006 to 9.4% for the year ended December 31, 2007.
Depreciation and Amortization Expense.
Depreciation and amortization expense for the year ended December 31, 2007 increased 108.7%, or $32.7 million, compared to the same period of 2006. The increase in depreciation and amortization expense was the result of additional equipment and intangible assets acquired through capital expenditures and acquisitions. As a percentage of revenue, depreciation and amortization expense was 14.7% for the year ended December 31, 2007 compared to 12.5% for the same period of 2006.
Interest Expense.
Interest expense was $52.9 million for year ended December 31, 2007 compared to $18.9 million for the same period of 2006. Included in interest expense for the year ended December 31, 2007 is $4.8 million of unamortized deferred debt issuance cost related to our Term Loan B that was retired with a portion of the proceeds from the issuance of our 9.75% Senior Notes in January 2007. In 2006, we also expensed $1.6 million of unamortized debt issuance cost related to our 2005 credit facility. Additionally in 2007, an increase in the average amount of debt outstanding contributed to the increase in interest expense. This increase in debt resulted from debt incurred in connection with acquisitions, capital expenditures made in 2006 and 2007, our issuance of $300.0 million of 9.75% Senior Notes in January 2007 and the amendment and restatement of our credit facility increasing availability under our revolving credit facility from $125.0 million to $175.0 million, the issuance of a new $75.0 million Term Loan B in late June 2007 and the closing of our bridge loan facility on August 1, 2007.
The weighted average interest rate on our outstanding debt increased from 7.8% at December 31, 2006 to 8.5% at December 31, 2007. The increase in our weighted average interest rate is principally related to the issuance of our $300.0 million 9.75% Senior Notes in January 2007 and the placement of our bridge loan facility in August 2007. As a consequence of the increased level of debt and changes in debt structure resulting from the issuance of the notes, the amendment and restatement of our credit facility and the issuance of our bridge loan facility, we expect interest expense to continue to increase. Our actual interest expense will depend in part on our revolving credit balances, which in turn will depend on our available cash flow from operations.
Income Tax Expense.
We are not subject to federal or state income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Our income tax expense is comprised of current and deferred tax expense. These taxes added together provide an indication of an effective rate of income tax. Tax expense for the year ended December 31, 2007 was $6.4 million or 296.9% of income before tax compared to $4.9 million, or 16.1% of income before tax for the year of 2006. Because we do not file a consolidated income tax return, our 2007 effective tax rate results principally from operating losses created by our corporate overhead which cannot be utilized to offset operating profit generated by our taxable “C” corporations. Also, Texas law now provides for the taxation of entities organized as partnerships. As a result of that change, we anticipate that our on-going tax rate will increase from historical rates that existed prior to the institution of the State of Texas margin tax.
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Index to Financial Statements
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Revenue.
Our revenue for the year ended December 31, 2006 increased $167.3 million, or 228.8%, over the year ended December 31, 2005. The increase by operating segment was as follows:
Wellsite Support Services—Segment revenue increased $89.5 million, or 122.4%, to $162.7 million for the year ended December 31, 2006, compared to the same period of 2005. The increase in segment revenue resulted principally from acquisitions made subsequent to January 1, 2006 combined with organic growth as a result of our capital expenditures program. In addition, we have seen modest improvement in our pricing.
Production & Logistics Services—Our acquisition of Stallion Heavy Haulers and Stallion Oilfield Construction in March 2006 established our production & logistics services operating segment. Segment revenue increased $77.7 million for the year ended December 31, 2006 from none in the same period of 2005 due to adding the additional segment operations in 2006.
Operating Expense.
Our operating expense for the year ended December 31, 2006 increased $130.4 million, or 215.7%, over the year ended December 31, 2005.
Expenses directly related to the operation of each of our operating segments include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of our equipment. For the year ended December 31, 2006, these expenses increased 232.8%, or $98.4 million, compared to the same period of 2005. The increase in these costs by operating segment was as follows:
Wellsite Support Services—Direct segment operating cost increased $45.7 million, or 108.2%, for the twelve-month period ended December 31, 2006 compared to the same period in 2005 as a result of acquisitions made during the period. Direct operating expenses as a percentage of segment revenue decreased from 57.8% for the year ended December 31, 2005 to 54.1% for the year ended December 31, 2006. The decrease in these costs as a percentage of revenue resulted principally from improved pricing and a more favorable mix of higher margin services.
Production & Logistics Services—Direct segment operating costs increased $52.7 million for the year ended December 31, 2006 from none in the same period of 2005 due to adding the segment operations in 2006. As a percentage of segment revenue direct segment operating costs were 67.8% for the year ended December 31, 2006.
Selling, General and Administrative Expense.
Selling, general and administrative expense consists primarily of salaries and other related expenses for our sales, marketing, administrative, finance, information technology and human resources functions. Selling, general and administrative expenses for the year ended December 31, 2006 increased $9.3 million, or 94.0%, over the year ended December 31, 2005. This increase was primarily due to (i) the acquisitions that we made during 2005 and 2006, which added 37 personnel providing support to field offices who are accounted for in selling, general and administrative expenses and (ii) the write off of approximately $0.9 million of deferred offering expenses associated with our withdrawn 2006 IPO. Additionally, we increased our corporate headcount by 41 during the same period. Additional costs were incurred for outside consulting services for accounting, tax and information technology in connection with integration of acquired companies into our business network. As a percentage of revenue, selling, general and administrative expenses increased from 13.5% for the year ended December 31, 2005 to 8.0% for the year ended December 31, 2006.
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Depreciation and Amortization Expense.
Depreciation and amortization expense for the year ended December 31, 2006 increased 285.6%, or $22.3 million, over the year ended December 31, 2005. The increase in depreciation and amortization expense was the result of additional equipment and intangible assets acquired through capital expenditures and acquisitions. As a percentage of revenue, depreciation and amortization expense was 12.5% for the year ended December 31, 2006 compared to 10.7% for the same period of 2005.
Interest Expense.
Interest expense was $18.9 million for the year ended December 31, 2006 compared to $4.6 million for the same period ended December 31, 2005. Interest expense for the year ended December 31, 2006 includes $1.6 million of expense related to the write off of certain debt issuance cost associated with our 2005 credit facility. We replaced that credit facility with a new credit facility during the first quarter of 2006. See “—Liquidity and Capital Resources—Credit Facility.” Additionally, the increase in interest expense was attributable to an increase in the average amount of debt outstanding as a result of acquisitions completed and capital expenditures incurred in 2005 and 2006. The weighted average interest rate on our outstanding debt increased from 6.75% at December 31, 2005 to 7.84% at December 31, 2006. The increase in our weighted average interest rate is related to borrowings under our variable interest rate facilities combined with a general increase in the prime rate of interest during that same time period. As a consequence of the increased level of debt and charges in debt structure resulting from the issuance of the notes in January 2007 and the amendment and restatement of our secured credit facility, we expect interest expense to increase. Our actual interest expense will depend in part on our revolving credit balances, which in turn will depend on our available cash flow from operations.
Income Tax Expense.
We are not subject to federal or state income taxes on a consolidated basis due to our partnership structure; however, certain of our subsidiary companies are taxable corporations and are subject to income tax. Our income tax expense is comprised of current and deferred tax expense. These taxes added together provide an indication of an effective rate of income tax. Our tax expense was $0.6 million and $4.9 million for the years ended December 31, 2005 and 2006, respectively. This increase was due primarily to our acquisition of certain entities which were taxable and increased operations in certain of our taxable subsidiaries. Following this offering we will be subject to income taxes.
Liquidity and Capital Resources
Our primary liquidity needs are to fund acquisitions and capital expenditures, such as acquiring new rental equipment and funding our general working capital requirements. Our primary capital resources are net cash flow from our operations and our $175.0 million revolving credit facility, of which approximately $47.4 million was available as of July 31, 2008.
We anticipate that we will rely on cash generated from operations and borrowings under our amended and restated revolving credit facility to satisfy our liquidity needs. We believe that funds from these sources will be sufficient to meet our working capital requirements for at least the next 12 months. Our ability to fund future capital expenditures and to make strategic acquisitions will depend upon our future operating performance and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry, and general financial, business and other factors, some of which are beyond our control.
Operating Activities
Our cash flow provided by operating activities decreased $10.8 million from $49.5 million for the six months ended June 30, 2007 to $38.7 million for the six months ended June 30, 2008. The decrease in cash flow provided by operations was primarily related to our net loss for the six months ended June 30, 2008 combined
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with increased depreciation and amortization of approximately $11.9 million resulting from our 2007 and 2008 capital expenditures for equipment and the acquisition of 10 businesses during the twelve-month period ended June 30, 2008.
Our cash flow provided by operating activities increased $17.2 million from $41.1 million for the year ended December 31, 2006 to $58.3 million for the year ended December 31, 2007. The increase in cash flow provided by operations was primarily related to our 2006 and 2007 capital expenditures for equipment and the acquisition of businesses.
Our cash flow provided by operating activities for the year ended December 31, 2006 increased $34.0 million compared to the year ended December 31, 2005. Our gross receipts increased during 2006 as demand for our services continued to grow, resulting in more billable days and more favorable billing rates, while we expanded our current business and entered new markets through acquisitions and capital investments. The increase in cash flow provided by operations was primarily related to our increased revenue resulting from our 2005 and 2006 capital expenditures for equipment and the acquisition of businesses.
Investing Activities
Cash flow used in investing activities was $80.8 million for the six months ended June 30, 2008 as compared to $177.9 million for the same period of 2007. During the six months ended June 30, 2008, we made property, plant and equipment capital expenditures of $61.3 million compared to $75.9 million in the same period of 2007. Additionally, during the first six months of 2008, we used cash of $22.6 million for the acquisition of two businesses and an additional $0.7 million for a purchase price adjustment related to a 2007 acquisition compared to the six months ended June 30, 2007, when we made seven acquisitions for cash consideration totaling $112.8 million.
Cash flow used in investing activities was $496.8 million for the year ended December 31, 2007 as compared to $280.2 million for the same period of 2006. During the year ended December 31, 2007, we made property, plant and equipment capital expenditures of $122.3 million compared to $92.0 million in the same period of 2006. We used cash of $388.1 million and $178.0 million for the year ended December 31, 2007 and 2006, respectively, to acquire businesses in our wellsite support and production & logistics businesses.
Cash flow used in investing activities was $280.2 million for the year ended December 31, 2006 as compared to $83.5 million for the same period of 2005. During 2006, we made property, plant and equipment capital expenditures of $92.0 million compared to $36.0 million in the same period of 2005. Additionally in 2006, we paid total consideration of $206.6 million for the acquisition of eleven businesses. During 2005, we made six acquisitions totaling $51.3 million. Those acquisitions used cash of $178.0 million and $47.2 million for the year ended December 31, 2006 and 2005, respectively. In addition, we used cash of $1.4 million and $0.4 million for related acquisition costs in the years ended December 31, 2006 and 2005, respectively.
Capital Expenditures
We made total capital expenditures for property, plant and equipment for our existing business of $122.3 million and $92.0 million during the year ended December 31, 2007 and 2006, respectively. In 2007, we expanded our wellsite support services segment with capital expenditures of $60.4 million to acquire additional equipment and our production & logistics segment with capital expenditures of $59.5 million to acquire additional equipment.
In July 2007, we purchased the assets of Patriot and Bayou Tank and, in August 2007, we purchased the assets of Salty’s. Patriot provides saltwater injection wells, frac tanks rental and vacuum trucks. Bayou Tank leases frac tanks to and performs other oilfield-related services for oilfield, refining and industrial customers. Salty’s provides frac tank rentals and sales and saltwater hauling and disposal services. With these acquisitions, we entered the production services business.
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Capital expenditures for the purchase of property, plant and equipment and acquisitions of businesses are the main component of our investing activities. We made total capital expenditures for property, plant and equipment for our existing business of $61.3 million and $75.9 million during the six months ended June 30, 2008 and 2007, respectively. In 2008, we have expanded our wellsite support services segment with capital expenditures of $26.7 million to acquire additional equipment and $10.6 million to acquire one business that operates in the workforce accommodations and surface equipment rental service line. Additionally, we have expanded our production & logistics segment with capital expenditures of $34.3 million to acquire additional equipment and $12.0 million to acquire one business that operates in this segment.
In addition to making investments in property, plant and equipment capital expenditures, we will continue to evaluate acquisitions of complementary companies. We currently expect to spend approximately $108.4 million in 2008 for investment in property, plant and equipment capital expenditures, including approximately $16.0 million for maintenance capital expenditures. In the first six months of 2008, we spent approximately $61.3 million on capital expenditures, including approximately $8.0 million on maintenance capital expenditures.
Financing Activities
We generated cash from our financing activities in the first six months of 2008 totaling $36.6 million. During this period our equity sponsors funded approximately $26.3 million, net of issuance cost of approximately $0.3 million. Additionally, we made payments of $0.9 million on long-term debt and increased our revolving credit debt approximately $12.4 million.
We generated cash from our financing activities in the first six months of 2007 totaling $133.4 million. During this period we issued $300.0 million of our 9.75% Senior Notes, drew down $100 million on our revolving credit facility and issued $75 million of Term Loan B loans. Additionally, we paid $12.4 million of related debt issuance costs. The increase in long-term debt was partially offset by payments on long-term debt totaling approximately $209.5 million and payments of $19.5 million under the revolving credit facility.
In 2007, we generated cash from our financing activities totaling $444.3 million. During the year ended December 31, 2007, we issued $300.0 million of our 9.75% Senior Notes, drew down $283.0 million on our revolving credit facility, issued $75.0 million of Term Loan B loans and closed our $250.0 million senior unsecured credit facility. Additionally, we paid $17.7 million of related debt issuance costs and $5.0 million of debt discount related to our Term Loan Agreement. The increase in long-term debt was partially offset by payments on long-term debt totaling approximately $210.8 million and payments of $229.9 million under the revolving credit facility.
In 2006, we generated cash from our financing activities totaling $242.2 million. Approximately $62.8 million of this amount resulted from contributions of capital, net of distributions, made by the partners. The remaining amount was attributable to new notes payable and long-term debt of $209.5 million, net of issuance costs, and approximately $38.4 million drawn down on our line of credit that were offset by payments on the notes and long-term debt and line of credit totaling $68.4 million.
Credit Facility
In June 2007, we amended and restated the agreement governing our credit facility (as amended and restated, the “Restated Credit Agreement”) with UBS AG, Stamford Branch as Issuing Bank, Administrative Agent and Collateral Agent (“UBS AG”), and certain other financial institutions. In addition, we amended the Restated Credit Agreement (as amended, the “Credit Agreement”) in May 2008 to adjust the covenant package to provide greater operating flexibility, raise the letter of credit sub-limit and provide for the issuance of euro-denominated letters of credit.
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The Credit Agreement provides for a $75.0 million term loan that will mature on June 12, 2013 and up to $175.0 million in borrowing capacity under a revolving credit facility that will mature on March 1, 2011. Additionally, the Credit Agreement provides for increases to the term loan facility and/or the revolving credit facility of up to $75.0 million in aggregate, subject to certain conditions. The Credit Agreement also provides up to $50.0 million for the issuance of letters of credit which may include euro-denominated letters of credit. Any outstanding letters of credit reduce borrowing capacity under the revolving credit facility.
Subject to certain limitations, we have the ability to elect how interest under the Credit Agreement will be computed. Interest under the Credit Agreement may be determined by reference to (1) the London Interbank Offered Rate (“LIBOR”) plus 2.0% or (2) the greater of (a) the base rate charged by UBS AG and (b) the Federal Funds Rate, plus 0.5%, plus an applicable margin between 1.75% and 2.25% depending on the credit rating of commitments under the Credit Agreement. If an event of default exists under the Credit Agreement, advances will bear interest at the then applicable rate plus 2.0%. Interest is payable quarterly in arrears for base rate loans and at the end of the applicable interest periods for LIBOR loans.
All of our obligations under the Credit Agreement are secured by first priority security interests on substantially all of our assets. Additionally, all of our domestic subsidiaries have guaranteed our obligations under the Credit Agreement.
The Credit Agreement contains various standard covenants that place limits on our operations. Some of these covenants require that we maintain specific ratios or conditions (with such ratios tested at the end of each fiscal quarter).
Under the Credit Agreement, we are permitted to prepay certain borrowings. In addition, the Credit Agreement requires us to make prepayments in certain situations.
If an event of default exists under the Credit Agreement, the lenders may accelerate the maturity of the obligations outstanding under the Credit Agreement and they may exercise other rights and remedies. While an event of default is continuing, advances will bear interest at the then applicable rate plus 2.0%. As of December 31, 2007, we were in compliance with all of its debt covenants.
As of July 31, 2008, we have $125.0 million drawn under our revolving credit facility and $2.6 million drawn under our letter of credit sub-limit leaving us approximately $47.4 million available. The weighted average interest rate on our outstanding Credit Agreement debt as of that date was 5.1%.
9.75% Senior Notes
In a private placement on January 19, 2007, Stallion Oilfield Services Ltd. issued $300.0 million of 9.75% Senior Notes due February 1, 2015. Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $210.0 million Term B Loan and to pay down approximately $44.5 million under the revolving credit facility.
Interest payments on the Senior Notes are due semi-annually, on February 1 and August 1. The Senior Notes are non-convertible, unsecured and guaranteed by all the subsidiaries of the Partnership. In connection with the retirement of the Term B Loan on January 19, 2007, we expensed the remaining unamortized deferred debt issuance costs which amounted to approximately $4.8 million in the first quarter of 2007.
The Senior Notes are redeemable at the option of Stallion Oilfield Services Ltd. on or after February 1, 2011 at the specified redemption price as described in the indenture (“Indenture”) under which the Senior Notes were issued. The Senior Notes will be redeemable by Stallion Oilfield Services Ltd., in whole or in part, at any time prior to February 1, 2011 at a discount rate of the U.S. Treasury rate plus 50 basis points. Prior to February 1, 2010 Stallion Oilfield Services Ltd. may redeem up to 35% of the Senior Notes with the proceeds of certain
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equity offerings at a redemption price equal to 109.75% of the principal amount of the Senior Notes, plus accrued and unpaid interest and liquidated damages, if any, to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such qualified equity offering.
Following a change of control, as defined in the Indenture, Stallion Oilfield Services Ltd. will be required to make an offer to repurchase all or any portion of the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the date of repurchase.
The Senior Notes contain certain covenants that limit the ability of Stallion Oilfield Services Ltd. and its restricted subsidiaries to, among other things: incur additional debt, incur layered debt, consolidate or merge with or into other companies. The Senior Notes also have limitations on asset sales, limitations on restricted payments, limitations on dividends and other restrictions, limitations on transactions with affiliates, and limitations on additional note guarantees. The restrictive covenants are subject to a number of important exemptions and qualifications set forth in the Indenture.
As of July 31, 2008, we were in compliance with the covenants contained in the Indenture.
At June 30, 2008, the fair market value of our Senior Notes was $252.8 million.
As part of the issuance of the Senior Notes, Stallion Oilfield Services Ltd. incurred debt issuance costs of approximately $9.1 million, which are being amortized to interest expense using the straight line method, which approximates the effective interest method over the term of the Senior Notes.
Bridge Loan
In August 2007, we entered into a $250.0 million bridge loan facility to fund the acquisitions of our production services businesses. The bridge loan facility has a five-year maturity and requires interest only payments until maturity.
The interest rate on the bridge loan facility is as follows: the base rate plus 3.50% or LIBOR plus 4.50%;provided that (A) from and after May 1, 2008 until November 1, 2008, the interest rate will be the base rate plus 4.25% or LIBOR plus 5.25%, and (B) from and after November 1, 2008 until February 1, 2009 the interest rate will be base rate plus 5.00% or LIBOR plus 6.00%, and (C) from and after February 1, 2009 through August 1, 2012, the interest rate will be the base rate plus 5.50% or LIBOR plus 6.50%.
Our bridge loan facility contains certain restrictive covenants applicable to us and our restricted subsidiaries which are substantially similar to the covenants contained in the Indenture. We are required to repay the bridge loan facility at 101% of face value with our net proceeds from this offering.
The weighted average interest rate on our outstanding bridge loan facility debt was 8.4% as of July 31, 2008.
Other Debt
We have a variety of other capital leases and notes payable outstanding that are customary in our industry. None of these debt instruments are significant individually.
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Outstanding Debt and Operating Lease Commitments
We have significant contractual obligations in the future that will require capital resources. Our primary contractual cash obligations are (1) our debt, (2) our capital lease obligations, (3) our operating leases and (4) purchase obligations.
The following table summarizes our known contractual obligations as of December 31, 2007 (in thousands):
Payments Due by Period
Obligations | Total | 2008 | 2009 - 2010 | 2011 - 2012 | Thereafter | ||||||||||
Payments of long-term debt, excluding interest | $ | 724,551 | $ | 2,235 | $ | 2,291 | $ | 349,150 | $ | 370,875 | |||||
Capital lease obligations | 181 | 86 | 95 | — | — | ||||||||||
Operating lease obligations | 15,750 | 2,527 | 4,010 | 3,228 | 5,985 | ||||||||||
Purchase obligations(1) | 13,000 | 13,000 | — | — | — | ||||||||||
Total | $ | 753,482 | $ | 17,848 | $ | 6,396 | $ | 352,378 | $ | 376,860 | |||||
(1) | In April 2008, we entered into a contract with Thrustmaster of Texas, Inc. (“Thrustmaster”) pursuant to which Thrustmaster will manufacture and sell to us marine propulsion and maneuvering equipment for a price of approximately $18.5 million. Of the total price, we paid approximately $5.5 million in April 2008. In addition, $12.0 million of the purchase price is due when the equipment is ready for shipment. The remaining approximately $1.0 million is due after the equipment is installed on our or an affiliate’s vessel and commissioning, start-up, and sea trials of the equipment are complete. |
Off-Balance Sheet Arrangements
We have entered into operating lease arrangements for certain of our specialized equipment and for our office and field operating locations in the normal course of business. The terms of our facility leases range from monthly to five years. The terms of the specialized equipment leases range from one to five years. Annual payments pursuant to these leases are included in the above table under “Operating lease obligations.”
Quantitative and Qualitative Disclosures about Market Risk
The demand, pricing and terms for oil and natural gas services that we provide are largely dependent upon the level of activity in the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have little or no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the expected rates of declining current production; the discovery rate of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divesture activity among oil and natural gas producers.
The level of activity in the oil and natural gas exploration and production industry is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices that would likely affect drilling activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow.
We are exposed to changes in interest rates as a result of our credit facility and bridge loan facility, which have floating rates. We had a total of $199.3 million and $250.0 million of indebtedness outstanding under our credit facility and bridge loan facility, respectively, at July 31, 2008. The impact of a 1% increase in interest rates
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on this amount of debt would result in an annual increase in interest expense, and a corresponding decrease in net income, of approximately $4.5 million.
We utilize derivative instruments in the form of interest rate swap agreements in order to manage the interest rate risk associated with long-term debt. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of operations as the actual interest rate hedged by the agreements is settled. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.
The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as interest expense and presented in cash flow from operations.
In February and April 2008, we entered into interest rate hedge transactions in the form of two-year interest rate swaps with notional amounts totaling $250.0 million, and $70.0 million, respectively, both of which became effective on August 7, 2008. The February hedge is designed to swap the underlining variable rate on our bridge loan facility for a fixed rate of 2.705%. The April hedge is designed to swap the underlying variable rate on our term loan facility for a fixed rate of 2.90%.
Recent Accounting Pronouncements
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”). This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS No. 159 became effective on January 1, 2008. We have not elected to adopt the fair value option prescribed by SFAS No. 159 for assets and liabilities held as of June 30, 2008, but we will consider the provisions of SFAS No. 159 and may elect to apply the fair value option for assets or liabilities associated with future transactions.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) “Business Combinations” (“SFAS No. 141(R)”) retains the fundamental requirements of the original pronouncement requiring that the purchase method be used for all business combinations. SFAS No. 141(R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as on the acquisition date. SFAS No. 141(R) also requires that acquisition related costs be recognized separately from the acquisition. SFAS No. 141(R) is effective for us for fiscal 2010. We are currently assessing the impact of SFAS No. 141(R) on our consolidated financial position and results of operations.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This Statement applies to all entities that prepare consolidated financial statements, except not-for-profit organizations. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB 51’s consolidation procedures for consistency with the requirements of SFAS No. 141(R). This Statement
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is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The effectivedate of SFAS No. 160 is the same as that of the related SFAS No. 141(R). SFAS No. 160 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements will be applied retrospectively for all periods presented. We are currently evaluating the impact that SFAS No. 160 may have on our financial position, results of operations and cash flows.
In March 2008, the FASB released Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The application of SFAS No. 161 is required for fiscal years beginning after November 15, 2008, and interim period within those fiscal years. At this time we are evaluating the implications of SFAS No. 161 and its impact on our financial statements has not yet been determined.
In April 2008, the FASB issued FASB Staff Position FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FAS 142-3”). FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under Statement of Accounting Standards No. 142, ”Goodwill and Other Intangible Assets” (“SFAS No. 142”). FSP 142-3 is intended to improve the consistency between the useful life of an intangible asset determined under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under Statement of Accounting Standards No. 141R and other GAAP. FSP 142-3 is effective as of January 1, 2009. We are currently evaluating the impact of this staff position but do not expect FSP 142-3 to have a material impact on our consolidated financial statements.
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General
We provide wellsite support services and production & logistics services to exploration and production companies and drilling contractors throughout the United States. Our company slogan, Everything but the Rig, reflects our business strategy of providing a broad and comprehensive range of critical services to support wellsite operations, including onshore and offshore workforce accommodations, surface equipment rental, communications services, solids control, production services, wellsite construction, rig relocation and heavy equipment hauling. We seek to differentiate ourselves by offering a broad array of wellsite services with a focus on quality and reliability. Our service offerings are designed to improve living and working conditions at the wellsite, wellsite safety and our customers’ drilling and production operations.
Our services span the entire life-cycle of the land-based wellsite—wellsite preparation, rig deployment, drilling activities, production activities and decommissioning. We are typically the first service provider on the wellsite, as we assist in the initial preparation of the wellsite and often haul the rig and related heavy equipment onto the wellsite using our fleet of tractor trucks, trailers, pole trucks and cranes. Throughout the drilling and completion phases of the land-based well, we provide rental equipment and required support services to the wellsite. We also, in some cases, provide continuing support services during the production phase of the well, including the construction of production facilities and well connections to existing pipeline infrastructure. In addition, we manufacture oilfield equipment used in drilling and production activities, including frac tanks and other containment equipment. We frequently are the last service provider to leave the wellsite as we perform production facility disassembly and wellsite restoration, which are the last phases of the wellsite decommissioning process. In addition, our offshore workforce accommodations business serves our offshore customers during many phases of the offshore drilling and production life-cycle.
We currently focus on oil and natural gas regions within North America that we believe have attractive long-term potential for growth, including South Texas, the Gulf Coast, ArkLaTex, the Fort Worth Basin, the
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Permian Basin, the Mid-Continent, Rocky Mountain and Appalachian Basin regions and Prudhoe Bay, Alaska. We also supply offshore workforce accommodations and related equipment for use in the Gulf of Mexico and, to a lesser extent, other international offshore regions. We manage our operations from 74 field service offices located throughout our operating areas.
We conduct our operations through the following two business segments:
Wellsite Support Services. Through our wellsite support services segment, we offer integral services used by oil and natural gas companies, drilling contractors and other wellsite service providers to support wellsite operations. This segment includes the following primary service lines:
• | Workforce accommodations. We provide onshore workforce accommodations in the United States with, as of July 31, 2008, approximately 2,400 transportable units in our inventory. Our fleet of land-based units is designed to accommodate various personnel on wellsite locations before, during and after drilling operations. Certain trends in the oil and natural gas exploration and production industry, including increased drilling complexity and a tight supply of labor, have resulted in wellsite personnel spending more time at the wellsite. These trends have contributed to an increase in demand for high-quality, reliable workforce accommodations. In addition, we design, manufacture, lease and repair offshore workforce accommodation structures, which include U.S. Coast Guard certified and/or SOLAS certified units. Our onshore and offshore workforce accommodation units are specifically configured to provide transportable, comfortable living quarters and functional workspaces. |
• | Surface equipment rental. We provide a variety of surface rental equipment used in and critical to wellsite activities including forklifts, manlifts, power generators, compressors, loaders and water systems. |
• | Communications services.We provide integrated communications services through our StaRComm satellite system that provides wireless communications via intercoms and telephone, fax and internet/data services throughout the wellsite location. |
• | Solids control. We provide customized solids control services, closed-loop mud systems and fluid recovery services to help maximize our customers’ operating efficiency at the wellsite. We provide high-quality shakers, mud conditioners, centrifuges and peripheral backside equipment, as well as solids removal and waste handling coordination services. |
Production & Logistics Services. Through our production & logistics services segment, we offer services that are critical to establish, maintain and decommission the wellsite and position key equipment prior to, during and after drilling operations. This segment includes the following primary service lines:
• | Production services. We provide a fleet of vacuum and winch trucks, frac tanks, saltwater injection wells and other assets used for fluid provision, transportation and disposal services. These specialized assets allow our customers to obtain, move, store and dispose of fluids that are involved in the development and production of the well. In addition, we manufacture oilfield equipment used in drilling and production activities, such as frac tanks and other containment equipment. |
• | Wellsite construction. We provide construction equipment and services to build and reclaim infrastructure at wellsites before, during and after drilling operations. Our services include wellsite clearing, road construction, mat placement, production facility assembly and construction, pipeline installation, pit remediation, production decommissioning and wellsite restoration. We provide services for wellsites in both land and inland marine environments. |
• | Rig relocation and heavy equipment hauling. We provide a fleet of tractor trucks, trailers, pole trucks and cranes used for the demobilization, relocation and mobilization of drilling rigs and related heavy equipment. We maintain a focus on providing reliable, efficient and safe transportation and mobilization services. |
Wellsite support services and production & logistics services are critical to establish and operate the land-based wellsite. We believe our scale, our access to capital and our ability to provide a single supply source for many of our customers’ needs are strengths of our business. We believe we differentiate ourselves and thus are
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able to achieve growth by offering our customers high-quality, professional and reliable equipment and services on a large scale. In addition, we provide offshore workforce accommodations to exploration and production companies in the Gulf of Mexico and, to a lesser extent, other international offshore regions.
Corporate Structure
The chart below illustrates our corporate structure following the Restructuring.
Industry
Our business depends on the level of exploration, development and production expenditures made by our customers. These expenditures are driven by the current and expected future prices for oil and natural gas, and the perceived stability and sustainability of those prices. Our services comprise a relatively small portion of the total cost of drilling the well and, accordingly, our revenue does not tend to vary significantly with changing drilling rig rates. Our business is primarily driven by natural gas and oil drilling and production activities in North America. We believe the following three principal economic factors will positively affect our industry in the coming years:
• | Higher demand for natural gas in North America. We believe that natural gas will be in high demand in North America over the next several years because of its growing popularity as a cleaner burning fuel. According to the International Energy Agency’s 2006 World Energy Outlook, natural gas demand in North America (United States, Canada and Mexico) is projected to grow by approximately 29% from 2004 to 2030. |
• | Favorable domestic natural gas drilling outlook. Domestic natural gas exploration and production companies are trending toward development of unconventional natural gas basins. These basins are known for large inventories of drilling locations and wells with high initial decline rates. These high initial decline rates typically result in more wells drilled over time in order to maintain production. Additionally, early supply estimates for LNG imports into the United States have not fully materialized, as LNG exporters are channeling a significant portion of available supply away from the United States to international markets with higher natural gas prices. According to the Energy Information Administration of the U.S. Department of Energy, current 2008 LNG import estimates of 580 Bcf are 25% lower than the amount imported in 2007. Combined, we believe these factors should result in high levels of domestic natural gas drilling activity. |
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• | Increased oil drilling activity and sustained higher oil prices. We believe that historical data and industry forecasts suggest an increasing demand for oil coupled with a flat or declining production curve. The average West Texas Intermediate oil price has increased 324.7% from an average price of $26.17 for 2002 to an average price of $111.14 for the six months ended June 30, 2008. According to BHI, the average number of drilling rigs in the United States dedicated to drilling for crude oil has increased 157.7 % from an average of 137 for 2002 to an average of 353 for the six months ended June 30, 2008. We believe that this increasing demand for crude oil is reflected in the sharp increase in crude oil prices and utilization of oil drilling rigs. According to the U.S. Department of Energy, the average daily oil production in the United States has decreased 11.8%, from 5,822 MBbl per day in 2000 to 5,136 MBbl per day in 2006. We believe that sustained domestic drilling activity for crude oil will continue as exploration and production companies contend with constrained supply and increased demand. |
As a result of the above factors, we expect that there will continue to be a tight supply of, and high demand for, natural gas and oil in North America in the near future. We believe these trends will continue to support high levels of drilling activity.
Our Business Strategy
Our business strategy consists of the following core elements:
Establish and maintain a leadership position in our principal operating areas.We intend to continue to build upon our market positions in the areas in which we operate by offering a comprehensive and integrated package of services which allows us to provide our customers with wellsite support services required across their drilling locations. We view the incremental steps in achieving this to include:
• | Deploying our suite of services across existing land-based operating areas. We believe we have developed expertise in specific service lines which can be effectively marketed across the majority of our land-based operating areas. We intend to continue to roll-out our existing services across our current operating areas in an effort to deliver a comprehensive portfolio of services in each region. We believe our established customer base and strong regional relationships will continue to provide a strategic distribution network for our service deployment efforts. |
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• | Continue to develop our offshore service offerings. We provide offshore workforce accommodations to exploration and production companies. We intend to expand our manufacturing capabilities and offshore service offerings to meet the growing needs of these customers. |
Extend our operations into new geographic areas.We intend to apply our expertise in wellsite support services and land-based production & logistics services in markets where we currently do not operate and which provide an attractive platform for future growth. We believe our customers will continue to find value in our ability to provide services across multiple operating regions. We intend to continue to improve the ease with which our clients can use our services from one wellsite location to the next. We expect to support our customers’ entry into other active drilling regions by introducing our service offerings in those regions. In addition, we will also seek opportunities for expanding into new geographic areas where market conditions are favorable in order to attract new customers.
Broaden the suite of services we provide.We have established strong working relationships with our customers which provide us a stable base of operations. We work closely with our customers to define newservice offerings that meet specific customer needs in the onshore markets where we operate and also intend to expand our offshore service offerings. For example, our StaRComm system was first deployed in December 2005 after a series of customer driven studies and trials. We have approximately 350 StaRComm systems deployed at July 31, 2008. Also in 2007, we completed a number of acquisitions which provided us the capability in certain operating areas to provide more extensive rig relocation and heavy equipment hauling services. These acquisitions not only enhanced our revenue generating capacity but also provided us the opportunity to be the first service supplier at the wellsite and to cross-sell other services. We intend to continue to invest in developing or acquiring new high-quality assets and services which add to the equipment breadth and quality of our service portfolio.
Focus on service quality, business performance and safety. Our management team is responsible for assessing our service quality, performance and safety compliance and coordinates with our field offices to help ensure that our quality and performance metrics and safety standards are met at every level of our organization. In addition to our internal safety policies, we adhere to certain external safety regulations, such as certifying certain of our offshore workforce accommodation units with the U.S. Coast Guard and/or SOLAS prior to deployment. We believe that our pursuit of a reliable, comprehensive and professional service solution differentiates us from smaller regional competitors. We intend to continue to invest in and promote designs, systems and methodologies which improve the reliability, responsiveness, accountability and safety of our operations.
Continue to pursue strategic expansion opportunities.We believe that the markets in which we operate remain fragmented and that there are numerous consolidation opportunities within these markets. We completed 24 acquisitions in 2006 and 2007 and have completed three acquisitions in 2008 and intend to continue pursuing strategic acquisitions which add to the scope and quality of our service portfolio. In evaluating such acquisitions, we consider a number of factors, including enhancing our current service offerings, geographic diversification, synergies with existing operations, financial performance and acquisition costs.
Capitalize on regional experience. One component of our acquisition and growth strategy is to acquire assets located in strategic operating areas that include personnel with strong local leadership and regional experience. We believe that by having the administrative functions previously performed at the regional level centralized in and handled by our corporate office, we have enhanced our controls environment and enabled our local management to focus on our customers, our employees and the effective management and deployment of our assets.
Expand our services internationally. Our offshore workforce accommodation business predominantly operates in the Gulf of Mexico. We intend to pursue strategic opportunities to expand our service offerings into other international offshore markets by leveraging our custom product design and existing customer base.
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Our Competitive Strengths
We believe our operations benefit from a number of competitive strengths, including the following:
• | Extensive breadth of service throughout the wellsite life-cycle. We provide a broad array of wellsite services throughout each phase of the land-based drilling and production process. This breadth of service strengthens our relationships with our customers and allows us to identify and cross-sell additional services. |
• | Extensive geographic footprint with a strong regional and local presence. Our regional operations are located in some of the most active onshore oil and natural gas drilling regions of the United States, including South Texas, the onshore Gulf Coast, ArkLaTex, the Fort Worth Basin, the Permian Basin, the Mid-Continent, Rocky Mountain and Appalachian Basin regions and Prudhoe Bay, Alaska. Within these regions, there were approximately 1,811 active land drilling rigs as of August 8, 2008. In addition, our products are utilized in certain offshore markets, including the Gulf of Mexico and, to a lesser extent, other international offshore regions. Within the offshore Gulf of Mexico market, there were approximately 63 active offshore drilling rigs as of August 8, 2008. Our regional managers have developed strong relationships with our customers throughout their regions and are largely responsible for the sales, marketing and delivery of our services. Our broad geographic and multi-basin footprint decreases regional and specific play risk which could impact region-focused competitors. |
• | Large scale of operations. We provide comprehensive land-based wellsite services in our operating areas. Our scale enables us to deliver a comprehensive range of reliable and high-quality wellsite services to our customers. Our size also provides us with increased access to capital resources and reduces our administrative burden as a percentage of sales. |
• | Experienced management team with proven acquisition track record and control environment. Our senior management team has extensive experience in the oil and natural gas industry, with an average of 23 years of experience. We believe that this background provides our management team with an in-depth understanding of our customers’ needs and enhances our ability to deliver customer driven solutions. Our management also has substantial experience in identifying, completing and integrating acquisitions and since our inception through July 31, 2008, we have acquired 37 businesses. We have also implemented a standardized control environment that includes accounting, safety, environmental and maintenance processes and controls. Our integrated systems allow us to monitor operating performance, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk. In addition, our control environment provides transparency for our management team to track regional and project level performance and reliability and frees our local personnel to focus on customer service and performance. |
• | Leveraged to drilling activity. We believe that favorable supply and demand fundamentals will maintain the current level of drilling for oil and natural gas. Efforts to maintain current levels of production will, in turn, necessitate continued drilling for the foreseeable future, which will sustain demand for our services. As our package of services typically comprises less than 15% of total drilling expenditures, our business has not historically experienced the pricing volatility experienced by drilling contractors, who represent a much larger portion of total drilling expenditures. |
• | Leadership position in the offshore workforce accommodation business. We provide U.S. Coast Guard and SOLAS certified offshore workforce accommodations units worldwide. We believe our history, our custom design and the quality of our products and services are strengths of our business. |
Overview of Our Segments
We manage our business through two segments: wellsite support services and production & logistics services. Through these segments, we offer services that are essential to the successful set-up, drilling and completion of a land-based wellsite. Our ability to provide timely and reliable service, our extensive inventory of readily-available
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equipment, and our reputation for high-quality are important to drilling contractors looking to stay on schedule and attract the best crews. We also believe that larger exploration and production companies often prefer to work with service providers who offer regional and even national supply options, which many smaller vendors cannot provide. Unlike some of our competitors, we offer a comprehensive suite of wellsite support services and are well positioned to be the preferred provider of these services to our customers. In addition, through our entry into the offshore workforce accommodation business, which is part of our wellsite support service segment, we provide products and services that are critical to offshore exploration and production activities.
We have the ability to provide a broad array of wellsite support services through our extensive inventory of equipment and services and network of regional offices. Our diverse and integrated product offerings enhance the value of our services to our customers, while reducing our reliance on a single product line. Our core business involves offering integrated services which provides us opportunities to cross-sell our other services. For example, our construction services operations are the first service provider to begin work on a new land-based wellsite. By delivering this service, we are strategically positioned to market our workforce accommodations and surface equipment services to the wellsite operator. Further, by staying in contact with the customer throughout the drilling phase, we are also well positioned to win business from the same customer for post drilling work, such as assembly of production facilities and pipelines, wellsite remediation and other services. Finally, by providing land-based rig hauling and relocation services, we transition with the client to the next wellsite location. In addition to diversifying our revenue streams, we believe we can obtain a competitive advantage by supporting our customers before, during and after their drilling activities. Maintaining an ongoing dialogue with our customers also provides us with real-time information that ultimately helps us anticipate and support our customers’ needs.
Our products and services represent only a fraction of the overall costs of a well, providing an opportunity for pricing leverage as demand for higher quality workforce accommodations, surface equipment and other services increases.
We currently provide the following types of services for our customers to support their operations before, during and after wellsite operations:
Service Line | South Texas | Gulf Coast | ArkLaTex | Fort Worth Basin | East Texas | Permian Basin | Mid- Continent | Rocky Mountains | Appalachian Basin | Prudhoe Bay | Offshore | |||||||||||
Wellsite Support Services: | ||||||||||||||||||||||
Workforce Accommodations | ü | ü | ü | ü | ü | ü | ü | ü | ü | ü | ||||||||||||
Surface Equipment Rental | ü | ü | ü | ü | ü | ü | ü | ü | ||||||||||||||
Communications Services | ü | ü | ü | ü | ü | ü | ü | ü | ü | |||||||||||||
Solids Control | ü | ü | ü | ü | ü | ü | ü | |||||||||||||||
Production & Logistics Services: | ||||||||||||||||||||||
Production Services | ü | ü | ü | ü | ||||||||||||||||||
Wellsite Construction | ü | ü | ü | ü | ||||||||||||||||||
Mat Rental | ü | |||||||||||||||||||||
Production Equipment Assembly and Installation | ü | |||||||||||||||||||||
Pipeline Installation | ü | |||||||||||||||||||||
Production Facility Disassembly | ü | |||||||||||||||||||||
Wellsite Remediation | ü | ü | ||||||||||||||||||||
Rig Relocation and Heavy Equipment Hauling | ü | ü | ü | ü | ü |
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Wellsite Support Services
Through our wellsite support services segment, integral services are delivered to oil and natural gas companies, drilling contractors and other wellsite service providers that are required to support wellsite operations. This segment includes onshore and offshore workforce accommodations, surface equipment rental, communications services and solids control services.
Workforce Accommodations
We provide basic living accommodations and rental services, primarily through equipment rental at the onshore wellsite location. As of July 31, 2008, we owned and operated approximately 2,400 transportable units. These onshore accommodation services include mobile and skid-mounted units, portable bathrooms, change houses and crew quarters; water, sewer, and other specialized vehicles; and on-site water and sewer systems. We provide wellsite accommodation services in all of the regions in which we operate. In addition, we design, manufacture, lease and repair offshore workforce accommodation structures, which include U.S. Coast Guard board certified and/or SOLAS-certified units. We provide basic living accommodations and related equipment to exploration and production companies conducting operations offshore. Each of our accommodation units is manufactured to our custom specifications for use in the oilfield environment and includes the equipment we believe is necessary to provide comfortable living quarters and functional workspaces.
In 1997, we built our first U.S. Coast Guard approved building for lease to meet customers’ deepwater needs in the Gulf of Mexico. We continue to design and manufacture customized U.S. Coast Guard certified offshore workforce accommodation units. In addition, we maintain a rental fleet of over 120 U.S. Coast Guard approved buildings, which includes sleeping quarters, galleys, offices and laundry buildings. We also provide repair services, including offshore refurbishment, maintenance and rig repair, to our customers in the offshore workforce accommodation business. We have a team of experienced craftsmen that may be deployed at the wellsite to provide these repair services to our customers. We have successfully completed many platform, workforce accommodation and vessel renovation and repair projects.
Our primary competition in most of our operating regions for our onshore workforce accommodations includes a fragmented group of smaller, independent service providers. Contracts for these workforce accommodations are awarded based on the quality of accommodations and services and pricing is determined by regional supply and demand.
Our primary competition in the offshore workforce accommodation market includes two domestic oilfield service companies and two service providers in the United Kingdom that focus on the workforce accommodation business. Contracts for offshore workforce accommodations are awarded based on the quality of accommodations and service and pricing is determined by market conditions and availability.
Surface Equipment Rental
We also offer a wide range of surface equipment for every phase of a client’s operations at the land-based wellsite. As of July 31, 2008, we owned and operated a fleet of over 470 forklifts and loaders, including standard forklifts, extended-reach forklifts and articulating loaders. In addition, we have a number of manlifts, backhoes, generators, air compressors, light plants and trash containers as well as air, diesel and gasoline powered trash pumps, all of which can be coordinated and dispatched according to a customer’s needs.
Our primary competition in surface equipment rental includes various small service providers as well as large equipment rental companies. Contracts for our surface equipment are awarded based on the quality of equipment and service reliability and pricing is determined by regional supply and demand. Our surface equipment rental business operates in all of our operating regions in the continental United States.
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Communications Services
We also offer our onshore and offshore customers operating in the continental United States StaRComm, a comprehensive technology solution with intercoms, television, integrated telephone, fax and internet communications delivered via satellite. Communications services are critical to the productivity and reporting at the wellsite. StaRComm provides a means of delivering these communications services in remote locations where land-based communications services are not available.
Solids Control
Through our solids control business, we offer customized solids control and fluid management services to the land-based wellsite, including the designing and planning of waste control systems and the installation, operation and management of solids control equipment. These services help to reduce waste, maximize fluid recovery and lower costs for our customers. To assist us in providing innovative and effective solids control solutions to our customers, we maintain an inventory of customized solids control equipment. As of July 31, 2008, we owned over 1,000 various pieces of solids control equipment, including centrifuges, mud conditioners, flow line shakers, drying shakers and peripheral backside equipment. This equipment is delivered and configured at the wellsite and operated by our trained technicians to maximize our customers’ fluids recovery and efficiency and to help reduce the environmental impact of fluids and solids generated during drilling and production activities at the wellsite. Our solids control business provides packaged and ad-hoc rental services. Packaged services include closed-loop and de-watering systems.
• | Closed-Loop Systems.We provide closed-loop mud systems which provide our customers with economic and environmental advantages over traditional earthen pit disposal at the wellsite. Drilling rigs have some solids control equipment, typically shakers and mud conditioning equipment. However, this equipment often is not properly maintained and provides only basic solids control capability, which limits drilling efficiency. Closed-loop systems are used to help reduce solids disposal, fluids disposal and the environmental impact at the wellsite while enhancing drilling efficiency. Closed-loop systems are required in environmentally sensitive areas including wellsites in or around coastal waters as well as in close proximity to residential communities. Closed-loop systems include a combination of flowline shakers, drying shakers, mud conditioners (desanders and desilters), centrifuges, pumps, tanks and other equipment in a customized configuration for a specific drilling rig. |
• | Solids Control Coordination. We also provide coordination and management services, as needed, for all of our solids control system installations. For a particular project, we will engineer custom comprehensive solids control solutions which includes equipment rental, equipment monitoring services and waste handling coordination services in a turnkey solution package. |
Our solids control business also rents individual pieces of equipment on an ad-hoc basis. As part of our solids control services, we also provide remediation services to our customers including land farm location maintenance, slurry treatment, fluid treatment, de-watering services and pit closures.
Our primary competition in solids control includes nationally focused oilfield service companies. Contracts for our solids control services are generally awarded based on a bid basis and pricing is determined by availability of equipment and ability to meet the customer’s deadlines. Our solids control business operates in Texas, Louisiana, New Mexico, Oklahoma and the Rocky Mountains.
Production & Logistics Services
Through our production & logistics services segment, we offer services that are critical to establish, maintain and decommission the onshore wellsite and position key equipment prior to, during and after land-based drilling operations. This segment includes production services, wellsite construction, rig relocation and heavy equipment hauling. We established this operating segment in March 2006 when we acquired Stallion Oilfield Construction and Stallion Heavy Haulers.
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Production Services
Oil and gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. We provide fluid handling services in Texas, Oklahoma and Arkansas.
• | Fluid Transportation. We operate specialized vacuum trucks to deliver, transport and dispose of fluids safely and efficiently. We transport fresh water, completion fluids, produced water, drilling mud and other fluids to and from our customers’ wellsites. Our assets include U.S. Department of Transportation certified equipment for transportation of hazardous waste. |
• | Frac Tank Rental. We operate a fleet of over 2,100 frac tanks that are often used during hydraulic fracturing operations. We use our fleet of fluid transport assets to fill and empty these tanks and we deliver and remove these tanks from the wellsite with our fleet of winch trucks. In addition, we manufacture frac tanks and other containment equipment for our customers. |
• | Fluid Disposal. We own 13 injection wells, 12 of which are in operation and are permitted to dispose of saltwater and incidental non-hazardous oil and gas wastes. Our vacuum trucks transport fluids that are disposed of in these saltwater injection wells. The injection wells have injection capacities ranging up to 30,000 barrels per day at certain permitted injection pressures. The saltwater injection wells are located in close proximity to customers’ producing wells. Most oil and gas wells produce varying amounts of saltwater throughout their productive lives. In the areas in which we operate oil and gas wastes and saltwater produced from oil and gas wells are required by law to be disposed of in authorized facilities, including permitted saltwater injection wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. Separators are maintained at most of our injection wells permitting us to salvage residual crude oil, which is later sold for our account. |
• | Other Services. We also sell fluids used during well completions, such as fresh water, which we move to our customers’ wellsites using our fluid transportation services. |
Wellsite Construction
Through our wellsite construction business, we offer equipment and services to build and reclaim infrastructure at wellsites before, during and after drilling operations. We build roads, dig pits, clear land, move earth and provide a number of construction services to oil and natural gas producers. Wellsite construction requires the use of heavy equipment used in road construction. As of July 31, 2008, we owned and operated approximately 175 pieces of heavy construction equipment, including bulldozers, excavators, backhoes, compactors, road graders, dump trucks and cranes, and approximately 65,000 mats.
We also provide oilfield construction services for inland marine environments in bays and marshes of the Gulf Coast. Our inland marine construction services utilize tug boats, barges, crew boats, marsh hoes and cranes. Construction of production facilities in some coastal areas can require driving up to 100 to 200 pilings deep into the seafloor in order to provide an adequate foundation from which to construct and assemble production equipment above sea level.
Our primary competition in wellsite construction services includes various small service providers as well as large, integrated oilfield service companies. Contracts for our wellsite construction services are awarded based on availability of equipment and the ability to meet the customer’s deadlines and pricing is determined by regional supply and demand. Our construction business operates in Louisiana and Texas, and our services are offered for wellsites in both land and inland marine environments.
Mat Rental
In areas near coastal wetlands or areas that receive significant rainfall, mats are used to stabilize locations and roads. Mats are made of hardwood and/or composite materials and are layered on roads and the wellsite to
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stabilize the location and prepare it for heavy equipment including the drilling rig. In some cases, pilings must be driven into the soil using hammer systems on cranes to provide strongback foundations to support the drilling rig. Mats are then layered across the location to provide a stable and dry area for wellsite operations. In areas with more stable foundations and soil conditions, mats are not required and crushed rock is brought in and graded to level and stabilize the wellsite pad.
Production Equipment Assembly and Installation
After the well is drilled, we also prepare the wellsite for production operations. Construction of wellsite production facilities includes the assembly and installation of tank batteries, containment barriers, condensers, heaters, compressors, flow lines and other specified production equipment.
Pipeline Installation
For natural gas wellsites, pipelines must be constructed to connect the new well to the nearest natural gas gathering system. We construct pipelines from the production wellsite to the nearest gathering system or marketing line where the product may go to market.
Production Facility Disassembly and Wellsite Remediation
After a well is plugged and abandoned, we provide decommissioning services including the disassembly of production equipment, removal of stabilization material or pad rock and re-seeding of native grasses to return the location to its original condition. This final process ends the life-cycle of the wellsite.
Rig Relocation and Heavy Equipment Hauling
We move land-based drilling rigs and related equipment to and from the wellsite. We own and operate a fleet of tractor trucks, trailers, pole trucks and cranes used for the demobilization, relocation and mobilization of drilling rigs and related heavy equipment. Our capabilities allow us to move some of the largest rigs in the United States. Our land-based rig relocation and heavy equipment hauling operations are located in regions where a high concentration of the land drilling rigs in the United States are located. We maintain a focus on providing reliable, efficient and safe transportation services.
Our primary competition in rig relocation and heavy equipment hauling includes regionally based oilfield service companies. In addition, most drilling contractors also maintain some dedicated rig hauling capacity. Contracts for our rig and heavy equipment hauling services are awarded based on availability of equipment and the ability to meet the customer’s deadlines and pricing is determined by regional supply and demand.
Properties
Our principal executive offices are located at 950 Corbindale Road, Suite 300, Houston, Texas 77024. As of July 31, 2008, we conducted our business from 74 field offices, 24 of which we own and 50 of which we lease. Each field office typically includes a yard, administrative office and maintenance facility. Our 74 field offices are located in Texas, Louisiana, Arkansas, Oklahoma, Colorado, Wyoming, North Dakota, Utah, New Mexico, Alaska, Ohio and The Netherlands. We believe that our leased and owned properties are adequate for our current needs.
Sales and Marketing
Our sales and marketing activities are generally performed through our local operations in each geographic region. We believe our local field sales personnel understand basin-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We also have a corporate sales team located in our Houston headquarters that supplements our field sales efforts and focuses on large accounts and selling our complementary services.
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Customers
In our onshore business, we serve numerous major and independent oil and natural gas companies, operators and drilling contractors that are active in our core areas of operations. For the twelve months ended December 31, 2007, we provided services to several hundred customers, with our top 10 customers comprising 31.5% of our total revenue with no one customer accounting for more than 10% of our total revenue. For the six months ended June 30, 2008, our top 10 customers comprised 31.1% of our total revenue with no one customer accounting for more than 10% of our total revenue. The majority of our onshore business is with major and independent oil and natural gas companies. As of June 30, 2008, our top customers in our onshore business include Chesapeake Oil and Gas Corporation, Devon Energy Corp., Questar Exploration, EOG Resources and Encana Oil & Gas. Our area managers and supervisors maintain relationships with customers whose operating decisions are generally made in the field. We serve numerous major and independent oil and natural gas companies conducting drilling operations offshore. As of June 30, 2008, our top customers in our offshore business include Total E&P USA, Inc., Chevron/Texaco, Inc., Apache Corporation, Secunda Marine Services and BP America Production.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oil and natural gas industry, such as accidents, blowouts, explosions, craterings, fires and oil spills that can cause:
• | personal injury or loss of life; |
• | damage or destruction of property, equipment, the environment and marine life; and |
• | suspension of operations. |
In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services business. If a serious accident were to occur at a location where our equipment and services were being used, it could result in our being named as a defendant in lawsuits asserting substantial claims.
Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which could result in spills, property damage and personal injury.
Despite our efforts to maintain high safety standards, we from time to time have suffered accidents and anticipate that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability, and our relationships with our customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents or the general level of compensation awards could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance and could have other material adverse effects on our financial condition and results of operations.
Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain employer’s liability, pollution, cargo, umbrella, comprehensive commercial general liability, workers’ compensation and limited physical damage insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us.
In our offshore workforce accommodation business, our customers are contractually obligated to maintain insurance against property damage to or loss of our workforce accommodation units. However, if our customers do not comply with their insurance obligations and our products sustain damage or are lost, then we may be unable to recover the value of the damaged or lost products.
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Competition
We operate in competitive markets with low barriers to entry. To compete successfully in those markets, a company must provide high-quality, reliable services that meet the specific needs of oil and natural gas exploration companies and drilling contractors at competitive prices. In our core land-based market areas, we compete against different companies in each of our business segments. Our competition includes many private “mom & pop” shops, as well as larger public companies including Superior Energy Services, Inc. (with respect to workforce accommodations), Key Energy Services (with respect to production services), Basic Energy Services (with respect to production and wellsite construction services), Newpark Resources, Inc. (with respect to wellsite construction), National Oilwell Varco Inc. (with respect to solids control), Complete Production Services, Inc. (with respect to rig and heavy equipment hauling and production services), Hertz Equipment Rental Corporation (with respect to surface equipment rental) and RSC Equipment Rental (with respect to surface equipment rental). In our onshore workforce accommodation business, we compete primarily with smaller, independent service providers and in our offshore workforce accommodation business, we compete against U.S. based oilfield service companies and certain international workforce accommodation providers. Our competition in this market includes Superior Energy Services, Inc., Oil States International, Inc. and Ferguson Modulars.
We believe that the principal competitive factors in the market areas that we serve are quality of service, reputation for safety and technical expertise, availability and price. While we must be price competitive, we believe that many of our customers select our services based primarily on our professional, reliable and comprehensive provision of services in each of our service areas and the experience of our service professionals who deliver those services.
Safety Program
In the wellsite support services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled work force. In recent years, many of our larger customers have placed an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs as well as our employee review process. Many of our competitors, particularly small contractors, have not undertaken similar training programs for their employees or managers.
Environmental Matters
Extensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment affect our business. Numerous governmental departments issue regulations to implement and enforce these laws, which are often difficult and costly to comply with. Failure to comply with these laws and regulations often carries substantial administrative, civil and even criminal penalties. Some laws and regulations relating to protection of the environment may, in some circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Compliance with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that, except as noted below, we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a materially adverse effect upon our capital expenditures, earnings or our competitive position.
In November 2006, we were notified by a local agency that a discharge of wash water from equipment cleaning activities at our Houston, Texas solids controls facility into a drainage swale adjacent to the facility was not authorized. We stopped the discharge of equipment wash water immediately, and promptly remediated areas of impacted soil next to the equipment wash pad and in the adjacent drainage area. Although no proceeding has
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been commenced, it is possible that an enforcement action could be brought against us with respect to this discharge. Under the Texas Water Code, unauthorized discharges of wastewater may be subject to either civil or criminal fines and penalties. We are unable to predict whether the apparently unauthorized discharge will result in any enforcement action, but we do not expect this matter to have a material adverse effect on our operations or financial condition.
We generate non-hazardous and hazardous solid wastes that are subject to the requirements of the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA” in this prospectus, and comparable state statutes. Our operations generate minimal quantities of hazardous wastes because RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as hazardous waste. Disposal of wastes from oil and natural gas exploration, development and production that are non-hazardous wastes is usually regulated under state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion from RCRA and may be regulated as hazardous waste. In addition, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. For instance, from time to time legislation has been proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” potentially subjecting these wastes to more stringent handling, disposal and cleanup requirements. If this legislation were enacted it could have a significant adverse impact on our operating costs, as well as the oil and natural gas industry and well servicing industry in general.
In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.
Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state and local laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for state and local programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells. We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in substantial compliance with permit conditions and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.
In addition, our sales of residual crude oil collected as part of the saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws.
The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” in this prospectus, and comparable state laws impose liability, without regard to fault on some classes of persons
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that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, companies that incur liability frequently confront additional claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. We generally conduct site assessments prior to acquiring new property and have taken measures to protect ourselves from liability for hazardous substance releases. Accordingly, we believe that we do not have any material liability for remediation of site contamination or related damages. However, because we may not have identified all instances of existing site contamination and because hazardous substance releases could occur in the future, we cannot assure you that we will not incur such liabilities in the future or that such liabilities will not be material.
Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the Environmental Protection Agency has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an Environmental Protection Agency general permit. Some of our properties may require permits for discharges of storm water runoff and as part of our overall evaluation of our current operations. We are applying for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that, where necessary, we will be able to obtain, or be included under, these permits and make minor modifications to existing facilities and operations that would not have a material effect on us.
The federal Clean Water Act and the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States, require some owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. We believe we are in substantial compliance with these regulations.
We maintain insurance against some risks associated with underground contamination that may occur as a result of wellsite service activities. However, this insurance is limited to activities at the wellsite, and this insurance may not continue to be available or may not be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
Government Regulation
We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the hauling of hazardous materials, the transportation of explosives, the protection of the environment and driving standards of operation. Regulations concerning equipment certifications create an ongoing need for regular maintenance which is incorporated into our daily operating procedures.
Among the services that we provide, we operate as a motor carrier and therefore we are subject to regulation by the U.S. Department of Transportation (the “DOT”) and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions. There are additional regulations specifically related to the trucking industry, including testing and specifications of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services.
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Some of these possible changes include increasingly stringent environmental regulations; changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific time period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. DOT regulations also mandate regular drug testing of drivers.
In addition, through our construction and logistic service business we operate a fleet of barges that are subject to the safety requirements of the United States Coast Guard. Also, in our offshore workforce accommodation business, the units we design and manufacture are subject to the safety requirements of the U.S. Coast Guard.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Employees
As of July 31, 2008, we employed 2,778 people, 111 of which were administrative employees located in our Houston headquarters, and 2,667 of which were field workers and others employed in regional operations. Approximately 79.0% of our employees are employed on an hourly basis. Our future success will depend in part on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.
Legal Proceedings
From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings that could reasonably be expected to have a material adverse affect on our financial condition or results of operations.
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Directors and Executive Officers
Our directors and executive officers and their ages and positions, as of August 15, 2008, are as follows:
Name | Age | Position | ||
Craig M. Johnson | 45 | President, Chief Executive Officer and Chairman of the Board | ||
David S. Schorlemer | 41 | Vice President, Chief Financial Officer and Director | ||
Hill M. Dishman | 48 | Vice President and Chief Operating Officer | ||
Douglas E. Stewart | 31 | Vice President, General Counsel and Secretary | ||
Jennifer Guidry | 34 | Chief Accounting Officer, Treasurer and Assistant Secretary | ||
N. John Lancaster, Jr. | 40 | Director | ||
Pierre F. Lapeyre, Jr. | 46 | Director |
Set forth below is a description of the backgrounds of our directors and executive officers.
Craig M. Johnson. Mr. Johnson has over 20 years of experience in the oilfield service industry. Mr. Johnson has served as our Chief Executive Officer, President and Chairman of our board of directors since our formation in June 2006. Prior to our formation, he established Stallion Ltd., our predecessor, and served as the Chief Executive Officer, President and Chairman of its general partner, Stallion Oilfield Holdings GP, LLC, since December 2002. From September 2002 until December 2002, Mr. Johnson surveyed various investment and employment opportunities. Prior to September 2002, Mr. Johnson managed the rental and fishing tools division at Key Energy Services, Inc, a publicly traded well servicing and workover company. Mr. Johnson joined Key in July 2002 in connection with Key’s purchase of Q Services, Inc., a private production services company. From 1997 through July 2002, Mr. Johnson served as President and Chief Operating Officer of Q Services, Inc. Mr. Johnson earned his Bachelor of Arts degree from the University of Mississippi. Mr. Johnson served on the board of Remote Knowledge, Inc. between September 2004 and August 2005.
David S. Schorlemer. Mr. Schorlemer serves as our Vice President, Chief Financial Officer and director. Prior to our formation, he served in the same positions with Stallion Oilfield Holdings GP, LLC, the general partner of our predecessor, since September 2004. From July 2002 until September 2004, Mr. Schorlemer served as the Vice President of Marketing and Strategic Planning at Key Energy Services, Inc. From 1997 until July 2002, Mr. Schorlemer served as the Chief Financial Officer of Q Services, Inc. Prior to that, Mr. Schorlemer was with Andersen Consulting (now Accenture) where he worked on a variety of projects for numerous oil and natural gas companies, including Shell Oil Company, Conoco, PEMEX and Tenneco. Mr. Schorlemer earned his BBA at the University of Texas at Austin and his MBA at Texas A&M University. Mr. Schorlemer serves on the board of directors of Moreno Group Holdings, LLC, an energy engineering, procurement and construction company.
Hill M. Dishman. Mr. Dishman serves as our Vice President and Chief Operating Officer. Prior to our formation, he served in the same positions with Stallion Oilfield Holdings GP, LLC, the general partner of our predecessor, since December 2002. From 1997 until December 2002, Mr. Dishman served as Vice President of Texas Operations for SOLOCO Texas, LP, an operating unit of Newpark Resources, Inc., an NYSE-listed oilfield service company. Mr. Dishman earned his Bachelor of Arts degree from Lamar University.
Douglas E. Stewart. Mr. Stewart has served as our Vice President, General Counsel and Secretary since June 2007. Between January 2007 and June 2007, Mr. Stewart served in the international business development group of Occidental Development Company, a subsidiary of Occidental Petroleum Corporation. From September 2001 until December 2006, Mr. Stewart practiced corporate finance and securities law, with a focus on private equity and mergers and acquisitions, at Vinson & Elkins LLP. Mr. Stewart received his B.A. from Trinity University and his J.D. from the University of Texas.
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Jennifer Guidry. Ms. Guidry serves as our Chief Accounting Officer, Treasurer and Assistant Secretary. Prior to our formation, she served as Controller, Treasurer and Assistant Secretary with Stallion Oilfield Holdings GP, LLC, the general partner of our predecessor, since August 2003. From September 2002 to August 2003, Ms. Guidry served as Financial Reporting Manager for 3TEC Energy Services, Inc., a publicly traded company. From April 2002 to September 2002, Ms. Guidry served as Director of Financial Reporting of Q Services, Inc., which was acquired by Key Energy Services, Inc. in July 2002. From September 1996 through April 2002, Ms. Guidry was with Arthur Andersen where she worked on a variety of audits for numerous oil and gas companies. Ms. Guidry is a CPA and earned her Bachelor of Science (Accounting) degree from Louisiana Tech University.
N. John Lancaster, Jr. Mr. Lancaster has served as one of our directors since our formation in June 2006. Prior to our formation, he served as a director of Stallion Oilfield Holdings GP, LLC, the general partner of our predecessor, since January 2005. Mr. Lancaster is a Managing Director of Riverstone Holdings, LLC (“Riverstone”), an affiliate of Carlyle/Riverstone. Prior to joining Riverstone in 2000, Mr. Lancaster was a Director with The Beacon Group, LLC, a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Prior to Beacon, Mr. Lancaster was a Vice President with Credit Suisse First Boston’s Natural Resources Group. Mr. Lancaster received his BBA from the University of Texas at Austin and his MBA from Harvard Business School. Mr. Lancaster serves on the boards of directors (or equivalent governing bodies) of Frontier Drilling ASA, Red Technology Alliance, LLC, Moreno Group Holdings, LLC, Titan Specialties, Ltd., 4Gas International, Dynamic Offshore Resources, LLC and Dresser Holdings, Inc. Mr. Lancaster was nominated pursuant to the Nominating Agreement.
Pierre F. Lapeyre, Jr. Mr. Lapeyre has served as one of our directors since our formation in June 2006. Prior to our formation, he served as a director of Stallion Oilfield Holdings GP, LLC, the general partner of our predecessor, since January 2005. Mr. Lapeyre is a founder and Senior Managing Director of Riverstone. Prior to founding Riverstone in 2000, Mr. Lapeyre was a Managing Director of Goldman, Sachs & Co. in its Global Energy & Power Group. While at Goldman, Sachs, Mr. Lapeyre’s responsibilities included client coverage and leading the execution of a wide variety of M&A, IPO, strategic advisory and capital markets financings for clients across all sectors of the industry, and he was involved extensively in the origination and execution of energy private equity investments on behalf of the firm. Mr. Lapeyre received his BS in finance/economics from the University of Kentucky and his MBA from the University of North Carolina at Chapel Hill. Mr. Lapeyre serves on the boards of directors (or equivalent governing bodies) of Legend Natural Gas II, LP, Legend Natural Gas III, LP, CDM Resource Management, Ltd., Topaz Power Group, LLC , Cobalt International Energy, L.P., Frontier Drilling ASA, 4Gas International, Targe Energy LLC, Moreno Group Holdings, LLC, Dynamic Offshore Resources, LLC, Green Earth Fuels, LLC, Bottle Rock Power, LLC, Collingwood Ethanol, L.P., Titan Specialties, Ltd., Niska GS Holdings I, L.P., Niska GS Holdings II, L.P., Knight Holdco, LLC and Dresser Holdings, Inc. Mr. Lapeyre was nominated pursuant to the Nominating Agreement.
Board of Directors
Our board of directors (the “Board”) currently consists of four members. The Board expects to appoint one director prior to our being listed on The NASDAQ Stock Market LLC (“NASDAQ”). Following the closing of this offering, we intend to actively recruit additional directors to serve on our Board.
Each of our current directors was nominated in accordance with provisions of a nominating agreement. Please read “Certain Relationships and Related Party Transactions—Nominating Agreement” for additional information about the nominating agreement.
Board Independence
The Board has reviewed the independence of our directors using the independence standards of NASDAQ and, based on this review, has determined that Messrs. Lancaster and Lapeyre are independent within the
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meaning of the NASDAQ listing standards currently in effect. We expect that any additional directors will qualify as independent for purposes of serving on our Board.
Board Committees
Prior to our common stock being listed on NASDAQ, our Board intends to form, as standing committees, an Audit Committee, a Compensation Committee and a Nominating and Governance Committee. Based on the Board’s review of the independence of our directors noted above, Messrs. Lancaster and Lapeyre currently qualify as independent for purposes of serving on the Compensation Committee and the Nominating and Governance Committee. Messrs. Johnson and Schorlemer will not be independent for purposes of serving on any of these committees. Prior to their appointment to committees of the Board, the Board will affirmatively determine that each member of each of our Audit Committee, Compensation Committee and Nominating and Governance Committee is independent within the meaning of NASDAQ listing standards and the requirements of the SEC. The expected members of the individual committees are named below:
Audit | Compensation | Nominating and Governance | ||||||
* | * | * |
* | Chairman of the committee |
The Board expects to adopt a written charter for each of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee, which sets forth each committee’s purposes, responsibilities and authority. The Board will also adopt Corporate Governance Principles, a Code of Ethics and Business Conduct and a Financial Code of Ethics for Senior Officers. These committee charters, guidelines, codes and procedures will be available on our website atwww.stallionoilfield.com. You may also contact our Secretary at (713) 528-5544 for paper copies free of charge.
Audit Committee
The Audit Committee will assist the Board in its general oversight of our financial reporting, internal controls and audit functions, and will be directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors. We expect that will be designated the “audit committee financial expert” as prescribed by the SEC. Stockholders should understand that this designation is a disclosure requirement of the SEC related to experience and understanding with respect to certain accounting and auditing matters. The designation will not impose on any duties, obligations or liability that will be greater than will be generally imposed on him as a member of the Audit Committee and Board, and his designation as an audit committee financial expert pursuant to this SEC requirement will not affect the duties, obligations or liability of any other member of the Audit Committee or Board.
In compliance with NASDAQ requirements and SEC regulations, a majority of the directors on our Audit Committee will be independent within 90 days of the effectiveness of the registration statement relating to this offering and, within one year of effectiveness, all directors on the Audit Committee will be independent.
Compensation Committee
The Compensation Committee’s responsibility will be primarily to recommend for Board approval the compensation arrangements for our Chief Executive Officer and other senior management, including establishment of salaries and bonuses and other compensation for our executive officers; to approve any compensation plans in which our officers and directors are eligible to participate and to administer such plans, including the granting of stock options or other benefits under any such plans; and to review significant issues that relate to changes in benefit plans. The Compensation Committee will be authorized to retain the services of independent outside consultants to assist in its efforts. We expect that each member of the Compensation Committee will be “independent” as defined by the NASDAQ listing standards.
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Please see “Compensation Discussion and Analysis” for a description of the process and procedures for consideration and determination of executive compensation.
Compensation Committee Interlocks and Insider Participation
We did not have a Compensation Committee during fiscal year 2007. During 2007, Messrs. Johnson, Lancaster and Lapeyre participated in deliberations of the Board concerning executive officer compensation.
Nominating and Governance Committee
The Nominating and Governance Committee will assist our Board in identifying qualified individuals to become directors, in determining the size and composition of the Board and its committees and in overseeing the evaluation of the Board and management. It will also be charged with developing and maintaining an appropriate set of corporate governance principles for us and generally monitoring developments in corporate governance. We expect that each member of the Nominating and Governance Committee will be “independent” as defined by the NASDAQ listing standards.
The Nominating and Governance Committee will identify potential nominees for director through business and other contacts. The Nominating and Governance Committee may in the future also choose to retain a professional search firm to identify potential nominees for director.
The Nominating and Governance Committee will recommend nominees to our Board and our Board is ultimately responsible for proposing a slate of nominees to our stockholders for election to the Board, using information provided by the committee. In the event that a majority of the members of the Nominating and Governance Committee are up for re-election to the Board, our Board (with those interested directors abstaining) will evaluate nominees and propose a slate of nominees to our stockholders for election to the Board. We are a party to the Nominating Agreement. Please read “Certain Relationships and Related Party Transactions—Nominating Agreement” for additional information about the Nominating Agreement.
We believe that nominees to our Board must meet certain minimum qualifications, including the achievement of significant success in business or extensive financial expertise, a commitment to representing the long-term interests of our stockholders in the aggregate, and high ethical and moral standards and integrity.
In addition, the committee evaluates a potential nominee in relation to all nominees by considering whether the potential nominee meets the minimum qualifications described above, as well as by considering the following factors:
• | whether the potential nominee has experience and expertise that is relevant to our business, including any specialized business experience, technical expertise, or other specialized skills, and whether the potential nominee has knowledge regarding issues affecting us; |
• | whether the potential nominee has experience as a board member of a U.S. publicly-held company, and with regard to any prior board experience the history, nature and overall contribution to such board; |
• | whether the potential nominee is independent, whether such nominee is free of any conflict of interest or the appearance of any conflict of interest with our best interests and the best interests of all of our stockholders, and whether such nominee is willing and able to represent the interests of all of our stockholders; and |
• | any factor affecting the ability or willingness of the potential nominee to devote sufficient time to Board activities and to enhance such nominee’s understanding of our business. |
In addition, with respect to an incumbent director whom the Nominating and Governance Committee is considering as a potential nominee for re-election, the committee will review and consider the incumbent director’s service to us during the director’s term, including the number of meetings attended, level of participation, and overall contribution to the Board.
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Any stockholder of record entitled to vote for the election of directors at a meeting of stockholders may nominate candidates for election to our Board by submitting timely written notice of such stockholder’s director nomination(s) to our Secretary at our principal executive offices, provided that such stockholder is a stockholder of record at the time such notice is delivered to our Secretary. In the case of an annual meeting, the notice must be delivered to our Secretary not less than 45 or more than 75 days prior to the first anniversary of the date on which we first mailed our proxy materials for the preceding year’s annual meeting of stockholders; provided, however, that in the event that the date of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, the notice must be delivered not later than the close of business on the later of (1) the 90th day prior to such annual meeting or (2) the 10th day following the day on which public announcement, if any, of the date of such meeting is first made. In the case of a special meeting at which directors are elected, the notice must be delivered to our Secretary not earlier than the 90th day prior to such special meeting and not later than the close of business on the later of the 70th day prior to such special meeting or the 10th day following the day on which public announcement, if any, is first made of the date of the special meeting and of the nominees proposed by our Board to be elected at such meeting. The notice must set forth:
• | all information relating to the proposed nominee that is required to be disclosed in solicitations of proxies for election of directors, or is otherwise required, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and |
• | the written consent of the nominee to being named in the proxy statement as a nominee and to serving as a director if elected. |
In addition, the stockholder must provide:
• | such stockholder’s name and address, as they appear on our books and records; |
• | the class and number of shares of Stallion that are owned beneficially and of record by such stockholder; |
• | a representation that the stockholder is a holder of record of stock of Stallion entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such nomination; and |
• | whether the stockholder intends to deliver a proxy statement and form of proxy to holders of a sufficient number of our voting shares to elect such nominee or nominees (an affirmative statement of such intent being referred to in this prospectus as a “Solicitation Notice”). |
If the stockholder has provided us with a Solicitation Notice, such stockholder must have delivered a proxy statement and form of proxy to holders of a percentage of our voting shares reasonably believed by such stockholder to be sufficient to elect the nominee or nominees proposed to be nominated by such stockholder, and must have included in such materials the Solicitation Notice. If no Solicitation Notice has been timely provided, the stockholder proposing such nomination must not have solicited a number of proxies sufficient to have required the delivery of such Solicitation Notice.
The stockholder should also include an affidavit signed by the proposed nominee certifying that he or she meets the qualifications necessary to serve as a director.
Executive Sessions; Communications with the Board; Meeting Attendance
The Board will adopt a policy providing that the independent directors will meet in executive session at each regularly scheduled Board meeting, or more frequently if necessary.
Any stockholder may communicate with our Board (or with any individual director) by sending a letter by mail addressed to c/o Secretary, Stallion Oilfield Services, Inc., 950 Corbindale, Suite 300 Houston, Texas 77024. The Secretary will forward the stockholder’s communication directly to the appropriate director or directors.
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Separately, the Audit Committee of our Board will establish procedures for (a) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matters, and (b) the confidential, anonymous submission by the Company’s employees of concerns regarding questionable accounting or auditing matters. Individuals may notify the Chairman of the Audit Committee in writing, describing in sufficient detail the practice, event or circumstance at issue, by sending the notice to the attention of the Chairman of the Audit Committee, c/o Stallion Oilfield Services, Inc., 950 Corbindale, Suite 300, Houston, Texas 77024, or to the Company’s Designated Recipient in the manner described on our website (www.stallionoilfield.com).
Guidelines to be adopted by our Board will recommend that all directors personally attend each annual and special meeting of our stockholders.
Code of Ethics
We expect to adopt a Code of Ethics and Business Conduct and a Financial Code of Ethics in accordance with the NASDAQ listing standards and SEC rules and regulations. Concerns related to possible violations of these codes should be reported pursuant to the procedures to be outlined therein. Copies of both documents will be available on our website (www.stallionoilfield.com). Changes to or material waivers of our Code of Ethics and Business Conduct and our Financial Code of Ethics will be immediately disclosed via our website atwww.stallionoilfield.com.
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COMPENSATION DISCUSSION AND ANALYSIS
We were formed as a Delaware corporation in June 2006 and will commence business operations upon completion of the Restructuring. Consequently, our executive officers were not specifically compensated for time expended with respect to our business during 2006 and 2007. In connection with this offering, we will succeed to the business and operations of Stallion Ltd. The executive officers of Stallion Ltd. are also serving as our executive officers and will continue to serve as our executive officers following the Restructuring. For 2006 and 2007, the Board of Directors (the “GP Board”) of Stallion Oilfield Holdings GP, LLC (“Holdings GP”), the general partner of Stallion Ltd., approved compensation for Stallion Ltd.’s executive officers. The following analysis discusses the compensation objectives and decisions of the GP Board with respect to compensation paid to Stallion Ltd.’s executive officers in 2007. Following this offering, the Compensation Committee of our Board will determine the objectives, philosophy and procedures for our compensation program, which we expect will be similar to the objectives and philosophy instituted by the GP Board, except that we expect our compensation program will have a greater focus on long-term incentives through equity awards following adoption of a long-term incentive plan in connection with our initial public offering.
The following analysis contains statements regarding future individual and company performance targets and goals. These targets and goals are disclosed in the limited context of Stallion Ltd.’s executive compensation program and should not be understood to be statements of management’s expectations or estimates of results or other guidance. We specifically caution investors not to apply these statements to other contexts.
Overview of Executive Compensation Program
Stallion Ltd.’s success is contingent on its ability to recruit, develop, motivate and retain top executive talent with the requisite skills and experience to develop, expand and execute its business strategy. As a result, Stallion Ltd. seeks to deliver fair and competitive compensation for its executive officers by structuring its executive compensation program principally around two goals. First, it targets compensation at competitive market levels, as discussed in detail below. Second, it believes its executive officers should be rewarded for executing goals designed to generate returns for its unitholders but not for poor performance. As a result, it ties selected elements of its executive compensation program to individual and company performance goals.
At the end of each fiscal year, the Chief Executive Officer (“CEO”) reviews the performance of the Chief Financial Officer (“CFO”), Chief Operating Officer (“COO”), General Counsel and the Chief Accounting Officer (“CAO”). The GP Board evaluates the performance of all executive officers, including the CEO. The information and recommendations based on the CEO’s review, including base salary adjustments and annual cash incentive award amounts, are presented to the GP Board. The GP Board can exercise its discretion in modifying any recommended adjustments or awards.
Throughout this Compensation Discussion and Analysis and related tables, the individuals who served as Stallion Ltd.’s CEO and CFO during the fiscal year ended December 31, 2007, as well as the other individuals included in the Summary Compensation Table, are referred to as “Named Executive Officers.”
Objectives of Our Executive Compensation Program
Holdings GP has developed an executive compensation program that is designed to (1) recruit, develop and retain key executive officers responsible for Stallion Ltd.’s success and (2) motivate management to enhance long-term unitholder value. To that end, the GP Board bases its executive compensation decisions on the following objectives:
• | Compensation should reflect the value of the officer’s job in the marketplace. To recruit, develop and retain a highly skilled work force, Stallion Ltd. must remain competitive with the pay of other employers who compete with it for talent. |
• | Compensation should be based on the level of job responsibility as well as individual and company performance. As employees progress to higher levels in Stallion Ltd.’s organization, an increasing |
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proportion of their pay should be linked to company performance and unitholder returns, rather than individual performance, because they are in a position to have greater influence on company results. |
• | Compensation should reward performance. Stallion Ltd.’s programs should deliver higher compensation given top-tier individual and company performance; likewise, where individual performance falls short of expectations and/or Stallion Ltd.’s performance lags the industry, its executive compensation program should deliver lower compensation. In addition, the objectives of pay-for-performance and retention must be balanced. Even in periods of temporary downturns in company performance, the executive compensation program should continue to ensure that successful, high-achieving employees will remain motivated and committed to Stallion Ltd. |
The GP Board has established a number of processes to assist it in ensuring that Stallion Ltd.’s executive compensation program is achieving these objectives. Among those are:
• | Competitive Benchmarking.The GP Board historically has not utilized the services of an independent advisor or other compensation consultant when determining the appropriate compensation packages for Stallion Ltd.’s executive officers. Instead, the GP Board believes it may rely upon the CFO to utilize the accounting, legal and human resources departments of Stallion Ltd. to provide sufficient information necessary to make compensation decisions. As such, the GP Board reviews information provided in an annual internal analysis conducted by David S. Schorlemer, Stallion Ltd.’s CFO, regarding relevant publicly available market data for compensation of its executive officers. Mr. Schorlemer’s analysis provides insight into base pay levels, cash and non-cash bonus payments, the scope of duties for individuals by pay level and compensation levels by company size, performance and strategy. This analysis allows the GP Board to track and benchmark its executive compensation program with a group of peer companies (“Peer Companies”) in the oilfield services sector of the oil and gas industry. The Peer Companies were selected based on the following characteristics: (i) compensation information for the company is publicly, or otherwise, available for review, (ii) the company has grown through acquisitions, (iii) the company employs a business strategy similar to that of Stallion Ltd. and/or (iv) the company operates in service lines similar to those in which Stallion Ltd. operates. |
In 2007, Stallion Ltd.’s group of Peer Companies included: Superior Energy Services, Inc.; W-H Energy Services Inc.; Oil States International, Inc.; and Complete Production Services, Inc. Stallion Ltd. utilized the same group of companies as Peer Companies for its 2006 fiscal year.
Generally, the GP Board uses the data on the Peer Companies primarily to ensure that its executive compensation program as a whole is competitive, meaning generally within the range of pay offered by the Peer Companies, when Stallion Ltd. achieves the targeted performance levels.
• | Assessment of Individual and Company Performance. The GP Board has established specific company performance measures that determine the size of incentive payouts for Stallion Ltd.’s executive officers. In addition, a portion of the incentive bonuses are based on informal evaluations of individual performance. These performance measures are discussed in more detail below. |
• | Total Compensation Review. Each December, the GP Board reviews each executive officer’s base pay and annual cash incentives. In addition to these primary compensation elements, the GP Board periodically reviews perquisites and other compensation, as well as post-termination payments that would be required under the Company’s employment agreements. Following the 2007 review, the GP Board determined that all elements of our compensation packages were reasonable in the aggregate. |
Elements of Our Executive Compensation Program
The GP Board evaluates the performance of Stallion Ltd. and the executive officers and compensation paid to executive officers to ensure that Stallion Ltd. maintains its ability to attract and retain superior employees in key positions and that compensation provided to its key employees remains competitive relative to the
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compensation paid to similarly situated executive officers of Stallion Ltd.’s Peer Companies. In furtherance of these goals, the executive compensation program consists of three basic components:
• | base salary; |
• | annual cash incentive; and |
• | termination benefits. |
Base Salaries
Stallion Ltd. provides its executive officers and other employees with an annual base salary to compensate them for services rendered during the year. Its goal is to set base salaries for its executive officers at levels that are competitive with comparable companies for the skills and requirements of similar positions. To achieve this goal, the GP Board uses benchmarking as previously discussed. The fact that information gathered from Peer Companies may be used as one factor in the setting of base salaries does not mean the GP Board will always directly tie salaries to those of comparable companies; the information relating to the Peer Companies is one of many guidelines available to the GP Board. The GP Board considers each officer’s responsibilities, experience, leadership, potential future contribution and demonstrated individual performance as well as Stallion Ltd.’s cash flows, earning levels and progress in implementing its business strategy in establishing increases in base salaries for Stallion Ltd.’s executive officers. The GP Board considers adjustments to base salaries at the end of each fiscal year.
Annual Cash Incentive Awards
At the core of Stallion Ltd.’s executive compensation philosophy is a belief that pay should be linked directly to performance. Accordingly, it has adopted a set of performance measurements that are designed to provide specific goal-oriented incentives to its executive officers and to tie the annual cash incentive compensation of those officers to individual and company performance guidelines.
A majority of an executive officer’s award under the annual cash incentive plan is based on Stallion Ltd.’s performance as measured against financial targets established in the first quarter of the year. For the 2007 and 2008 fiscal years, EBITDA and Return on Equity were chosen as the financial targets for the CEO, CFO and COO and EBITDA was chosen as the financial target for the CAO. These targets provide clear and readily determinable measures of annual performance that compensate the executive officers for current operating performance. The GP Board believes these performance metrics are commonly accepted and would be used by management of a public company to evaluate performance.
In adopting the individual performance measures, the GP Board determined that such measures should be based on subjective criteria to recognize the company’s strategy of rapid growth, the achievement of which may not result in short-term improvements conducive to an objective or formula-driven plan. The subjective measures considered by the GP Board are the executive officer’s overall role in accomplishing Stallion Ltd.’s non-financial goals including capital deployment, capital efficiency, capital structure management, growth, safety performance, acquisition integration, financial controls and reporting efficiency. The GP Board does not set or utilize quantified or other targets to assess the subjective criteria. This annual incentive arrangement reflects the subjective nature of management performance and influence on an organization. The GP Board believes that evaluating these areas better reflects management performance in a growth company employing an acquisitive strategy and that non-financial measures are extremely important in reducing risk inherent in a growth strategy. The GP Board believes it is in the interests of stockholders to compensate management for strategies that result in organizational longevity.
Payment amounts and recommendations under the annual cash incentive plan for Stallion Ltd.’s executive officers are presented by the CEO to the GP Board. As part of this presentation, the CEO analyzes the Company’s performance as measured against the financial targets and reviews each executive officer’s performance measured against the subjective criteria considered by the GP Board. Cash awards for all executive officers are determined and approved by the GP Board. The GP Board informally reviews each executive officer, including the CEO, throughout the year. Based on these informal reviews, the GP Board determines performance payouts for the executive officers.
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The performance measures and targets for the fiscal year ended December 31, 2007, and the corresponding payout level as a percentage of the available payout amount, are set forth in the table below.
2007 Financial Targets (dollars in millions) | Payouts (% of Base Pay) | Bonus Amount | ||||||||||||||||||||||||||||||||||
Performance | Entry | Expected | Exceed | Entry | Expected | Exceed | Weight | Base Pay | Entry | Expected | Exceed | |||||||||||||||||||||||||
CEO & President | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 106.5 | $ | 142.0 | $ | 184.6 | 50 | % | 100 | % | 125 | % | 25 | % | $ | 306,250 | $ | 38,281 | $ | 76,563 | $ | 95,703 | ||||||||||||||
Return on Equity | 14 | % | 18 | % | 23 | % | 50 | % | 100 | % | 125 | % | 30 | % | 306,250 | 45,938 | 91,875 | 114,844 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 125 | % | 45 | % | 306,250 | 68,906 | 137,813 | 172,266 | |||||||||||||||||||||
Total | 100 | % | $ | 153,125 | $ | 306,250 | $ | 382,813 | ||||||||||||||||||||||||||||
CFO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 106.5 | $ | 142.0 | $ | 184.6 | 50 | % | 100 | % | 125 | % | 25 | % | $ | 256,250 | $ | 32,031 | $ | 64,063 | $ | 80,078 | ||||||||||||||
Return on Equity | 14 | % | 18 | % | 23 | % | 50 | % | 100 | % | 125 | % | 30 | % | 256,250 | 38,438 | 76,875 | 96,094 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 125 | % | 45 | % | 256,250 | 57,656 | 115,313 | 144,141 | |||||||||||||||||||||
Total | 100 | % | $ | 128,125 | $ | 256,250 | $ | 320,313 | ||||||||||||||||||||||||||||
COO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 106.5 | $ | 142.0 | $ | 184.6 | 50 | % | 100 | % | 125 | % | 25 | % | $ | 212,500 | $ | 26,563 | $ | 53,125 | $ | 66,406 | ||||||||||||||
Return on Equity | 14 | % | 18 | % | 23 | % | 50 | % | 100 | % | 125 | % | 30 | % | 212,500 | 31,875 | 63,750 | 79,688 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 125 | % | 45 | % | 212,500 | 47,813 | 95,625 | 119,531 | |||||||||||||||||||||
Total | 100 | % | $ | 106,250 | $ | 212,500 | $ | 265,625 | ||||||||||||||||||||||||||||
CAO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 106.5 | $ | 142.0 | N/A | 30 | % | 60 | % | N/A | 25 | % | $ | 135,500 | $ | 10,125 | $ | 20,250 | N/A | |||||||||||||||||
Financial Reporting | 75 | % | 95 | % | N/A | 30 | % | 60 | % | N/A | 50 | % | 135,500 | 20,250 | 40,500 | N/A | ||||||||||||||||||||
Timeliness & Accuracy | <18 days | <13 days | ||||||||||||||||||||||||||||||||||
Effectiveness of Management Reporting | Gets distributed to management (at all necessary levels) | |||||||||||||||||||||||||||||||||||
Discretionary | N/A | N/A | N/A | 30 | % | 60 | % | N/A | 25 | % | 135,500 | 10,125 | 20,250 | N/A | ||||||||||||||||||||||
Total | 100 | % | $ | 40,500 | $ | 81,000 | N/A | |||||||||||||||||||||||||||||
(1) | All calculations are after full bonus accruals but before extraordinary charges. Return on Equity is calculated by multiplying the quotient of revenue and average partners’ capital (or stockholders’ equity) and the quotient of net income and revenue, with each of these items determined in accordance with GAAP and calculated at the end of the measurement period. EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization. Please read “Selected Consolidated Financial Data.” Financial Reporting is a subjective measure relating to management’s ability to complete the accounting close process in an orderly and efficient manner without material adjustments. Timeliness & Accuracy relate to the ability of all operations to complete, within a specified timeframe, accounting period-end close processes, corporate allocations and other general ledger entries so that management can access completed financial reports from our internal financial reporting system. |
Each performance component is weighted by its relative importance to the Company and a percentage of the executive officer’s base salary equal to this weighting (25%, 30% or 45% for 2007, depending on the performance component) is used to determine the annual cash incentive award to be paid based on the performance achieved for each component. Possible performance results for each performance component are Entry, Expected and Exceed. The following example illustrates the mechanics of our annual incentive plan. For 2007, our CFO achieved “Exceed” performance in the discretionary component. Pursuant to the incentive plan, the CFO’s performance in this category contributed $144,141 to the total cash incentive award paid to the CFO for 2007. The contributed amount is calculated by multiplying the CFO’s base salary for 2007 ($256,250) by the weighting attributed to the discretionary component for 2007 (45%) and the payout level attributed to the “Exceed” level of performance for 2007 (125%). Please see “Executive Compensation—Summary Compensation—Summary Compensation Table for Year Ended December 31, 2007” for the base salaries of our executive officers for 2007. We do not pro-rate the amounts of awards for performance achieved between the three performance levels.
We establish the performance targets for the Expected level of achievement to match the financial performance on which our budget for the applicable fiscal year is based. While this achievement level is budgeted and planned for, we believe it to be moderately difficult for the Company and the named executive officers to reach this achievement level. We expect the Company and our named executive officers to achieve an Entry level performance without undue effort. We do not expect the Company and our named executive officers to achieve an Exceed level of performance without a significant effort on the part of the executive. With respect
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to the Net Income and Return on Equity components, Stallion Ltd. achieved “Expected” performance for 2006. For 2007, Stallion Ltd. achieved “Entry” performance for the EBITDA component but did not achieve “Entry” performance for the Return on Equity component. With respect to the Individual Performance component, our CEO, CFO and COO each achieved “Exceed” performance for 2006 and 2007.
We appointed Jennifer Guidry, our then Corporate Controller, as our CAO in February 2007. For 2006 and 2007, only Entry and Expected bonus grades were applicable for Ms. Guidry, with a potential bonus of 30% of base salary for the Entry category and 60% of base salary for the Expected category. The bonus components in 2006 for Ms. Guidry were Net Income, Financial Reporting Efficiency and Individual Performance weighted 25%, 50% and 25%, respectively. Ms. Guidry achieved Expected performance for the Financial Reporting Efficiency and Individual Performance components for 2006. Stallion Ltd. achieved “Expected” performance for the Net Income component in 2006. The bonus components in 2007 for Ms. Guidry were EBITDA, Financial Reporting and Individual Performance weighted 25%, 50% and 25%, respectively. Ms. Guidry achieved “Entry” performance for the Financial Reporting component and “Expected” performance for the Individual performance component in 2007. Stallion Ltd. achieved “Expected” performance for the EBITDA component in 2007.
We appointed Douglas E. Stewart, Vice President and General Counsel on June 11, 2007. Mr. Stewart did not participate in our annual cash incentive plan in 2007. He was awarded a discretionary cash bonus of $72,000 in 2007.
The performance measures are annually reviewed and updated and amended as the GP Board deems necessary. The GP Board also determines whether the performance measures and standards are appropriate for Stallion Ltd.and whether the full range of possible payouts makes sense relative to each applicable performance measure, as well as total compensation. Also, the GP Board reviews potential results of the subjective performance measures and determines whether or not the guidelines being tied to an individual’s annual salary are appropriate.
The performance measures and targets for the fiscal year ended December 31, 2008, and the corresponding payout level as a percentage of the available payout amount, are set forth in the table below:
2008 Financial Targets (dollars in millions) | Payouts (% of Base Pay) | Bonus Amount | ||||||||||||||||||||||||||||||||||
Performance Measures(1) | Entry | Expected | Exceed | Entry | Expected | Exceed | Weight | Base Pay | Entry | Expected | Exceed | |||||||||||||||||||||||||
CEO & President | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 145.59 | $ | 194.12 | $ | 252.35 | 50 | % | 100 | % | 200 | % | 25 | % | $ | 475,000 | $ | 59,375 | $ | 118,750 | $ | 237,500 | ||||||||||||||
Return on Equity | 11 | % | 14 | % | 18 | % | 50 | % | 100 | % | 200 | % | 30 | % | 475,000 | 71,250 | 142,500 | 285,000 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 200 | % | 45 | % | 475,000 | 106,875 | 213,750 | 427,500 | |||||||||||||||||||||
Total | 100 | % | $ | 237,500 | $ | 475,000 | $ | 950,000 | ||||||||||||||||||||||||||||
CFO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 145.59 | $ | 194.12 | $ | 252.35 | 50 | % | 100 | % | 200 | % | 25 | % | $ | 350,000 | $ | 43,750 | $ | 87,500 | $ | 175,000 | ||||||||||||||
Return on Equity | 11 | % | 14 | % | 18 | % | 50 | % | 100 | % | 200 | % | 30 | % | 350,000 | 52,500 | 105,000 | 210,000 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 200 | % | 45 | % | 350,000 | 78,750 | 157,500 | 315,000 | |||||||||||||||||||||
Total | 100 | % | $ | 175,000 | $ | 350,000 | $ | 700,000 | ||||||||||||||||||||||||||||
COO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 145.59 | $ | 194.12 | $ | 252.35 | 50 | % | 100 | % | 150 | % | 25 | % | $ | 250,000 | $ | 31,250 | $ | 62,500 | $ | 93,750 | ||||||||||||||
Return on Equity | 11 | % | 14 | % | 18 | % | 50 | % | 100 | % | 150 | % | 30 | % | 250,000 | 37,500 | 75,000 | 112,500 | ||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 100 | % | 150 | % | 45 | % | 250,000 | 56,250 | 112,500 | 168,750 | |||||||||||||||||||||
Total | 100 | % | $ | 125,000 | $ | 250,000 | $ | 375,000 | ||||||||||||||||||||||||||||
General Counsel | ||||||||||||||||||||||||||||||||||||
Discretionary | N/A | N/A | N/A | 50 | % | 75 | % | 100 | % | 100 | % | $ | 185,000 | $ | 92,500 | $ | 138,750 | $ | 185,000 | |||||||||||||||||
CAO | ||||||||||||||||||||||||||||||||||||
EBITDA | $ | 145.59 | $ | 194.12 | N/A | 30 | % | 60 | % | N/A | 25 | % | $ | 150,000 | $ | 11,250 | $ | 22,500 | N/A | |||||||||||||||||
Financial Reporting | 75 | % | 95 | % | N/A | 30 | % | 60 | % | N/A | 50 | % | 150,000 | 22,500 | 45,000 | N/A | ||||||||||||||||||||
Timeliness & Accuracy | <18 days | <13 days | ||||||||||||||||||||||||||||||||||
Effectiveness of Management Reporting | Gets distributed to management (at all necessary levels) | |||||||||||||||||||||||||||||||||||
Discretionary | N/A | N/A | N/A | 30 | % | 60 | % | N/A | 25 | % | 150,000 | 11,250 | 22,500 | N/A | ||||||||||||||||||||||
Total | 100 | % | $ | 45,000 | $ | 90,000 | N/A | |||||||||||||||||||||||||||||
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(1) | All calculations are after full bonus accruals but before extraordinary charges. Return on Equity is calculated by multiplying the quotient of revenue and average partners’ capital (or stockholders’ equity) and the quotient of net income and revenue, with each of these items determined in accordance with GAAP and calculated at the end of the measurement period. EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization. Please read “Selected Consolidated Financial Data.” Financial Reporting is a subjective measure relating to management’s ability to complete the accounting close process in an orderly and efficient manner without material adjustments. Timeliness & Accuracy relate to the ability of all operations to complete, within a specified timeframe, accounting period-end close processes, corporate allocations and other general ledger entries so that management can access completed financial reports from our internal financial reporting system. |
For 2008, we do not expect achieving an Entry, Expected or Exceed level of performance for each performance component to be more or less difficult than achieving such performance levels was for 2007.
TerminationBenefits
We provide our Named Executive Officers with termination benefits to facilitate the attraction and retention of high caliber executives in a competitive labor market in which formal severance plans are common. Please see “Executive Compensation—Potential Payments Upon Termination or Change in Control” for a discussion of termination benefits payable to the Named Executive Officers pursuant to their employment agreements with Stallion Ltd.
Other Benefits
In addition to base pay, annual cash incentives and termination benefits, Stallion Ltd. provides the following forms of compensation:
• | 401(k) Savings Plan Matching.Stallion Ltd. has a tax-qualified defined contribution profit sharing plan designed to assist eligible officers and employees in providing for their retirement. Stallion Ltd. matches the contributions of all of its employees to the plan in cash, up to a maximum of 3% of eligible deferral. One-third of all company contributions made during an employee’s first year of employment vest on the first anniversary of the employee’s employment. Two-thirds of all company contributions made during an employee’s first two years of employment vest on the second anniversary of the employee’s employment. Finally, all company contributions made during an employee’s first three years of employment vest on the third anniversary of the employee’s employment. An employee is immediately vested in all employee deferral contributions and in company contributions made after the employee’s third anniversary of employment. |
• | Health and Welfare Benefits. Stallion Ltd.’s executive officers are eligible to participate in medical, dental, vision, disability insurance and life insurance to meet their health and welfare needs. These benefits are provided so as to assure that Stallion Ltd. is able to maintain a competitive position in terms of attracting and retaining officers and other employees. The benefits under this component of compensation are provided on a non-discriminatory basis to all employees. |
• | Perquisites.Stallion Ltd. doesnot provide significant perquisites or personal benefits to its executive officers. To the extent perquisites or other personal benefits are provided, they are determined on an individual basis as appropriate in light of competitive standards and the performance of the executive officers. While there is some personal benefit to the executive officers, the perquisites we provide are incidental to the performance of their duties and are reasonable and consistent with Stallion Ltd.’s overall compensation program. All perquisites received by the Named Executive Officers are quantified in the “Summary Compensation Table for Year Ended December 31, 2007” and consist of items which are not offered to our employees generally, such as automobile benefits. |
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Other Matters
Long-Term Equity-Based Incentives
Stallion Ltd. does not maintain an equity-based incentive compensation plan, although we do anticipate establishing such a plan prior to the consummation of this offering. As such, the Named Executive Officers did not receive grants of options or restricted units during 2007 and this type of compensation is not reflected in the tables following this Compensation Discussion and Analysis.
Unit Ownership Guidelines and Hedging Prohibition
Unit ownership guidelines have not been implemented by the GP Board for Stallion Ltd.’s executive officers. In addition, Stallion Ltd. does not have a policy that restricts its executive officers from limiting their economic exposure to the price of its units. Stallion Ltd. periodically reviews best practices and re-evaluates its position with respect to unit ownership guidelines and hedging prohibitions.
Tax Treatment of Executive Compensation Decisions
Section 162(m) of the Internal Revenue Code generally disallows a tax deduction to public companies for compensation over $1.0 million paid in a calendar year to a corporation’s chief executive officer and the three other most highly compensated executive officers other than the chief financial officer. Section 162(m) further provides that qualifying “performance-based” compensation will not be subject to the deduction limit if certain requirements are met. We do not currently structure our annual incentive compensation for executive officers to comply with the performance-based exception to Section 162(m). Although we intend to structure future grants of stock and cash incentives in a manner that complies with the performance-based exception to Section 162(m), we may forego all or some portion of a tax deduction to conform to our compensation goals.
In addition, we are aware of the recently enacted Section 409A of the Internal Revenue Code which changed the tax rules applicable to nonqualified deferred compensation arrangements. We have structured, and in the future will structure, our compensation plans in ways to minimize the likelihood that our employees, including executive officers, will be subject to the additional taxes prescribed in Section 409A.
The Board of Directors of Stallion Oilfield Services, Inc. has reviewed and discussed the disclosure set forth above under the heading “Compensation Discussion and Analysis” with our management and, based on the review and discussions, it has recommended that the “Compensation Discussion and Analysis” be included in this prospectus.
Respectfully submitted by the Board of Directors,
Craig M. Johnson
David S. Schorlemer
N. John Lancaster, Jr.
Pierre F. Lapeyre, Jr.
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Summary Compensation
The following table summarizes, with respect to the Named Executive Officers, information relating to the compensation earned for services rendered in all capacities to Stallion Ltd. The Named Executive Officers consist of Stallion Ltd.’s five current executive officers, including its Chief Executive Officer and Chief Financial Officer.
Summary Compensation Table for Year Ended December 31, 2007
Name and Principal Position | Year | Salary | Bonus | Non-Equity Incentive Plan Compensation | All Other Compensation(1) | Total | ||||||||||||
Craig M. Johnson | 2007 | $ | 301,923 | $ | 835,792 | (3) | $ | 38,281 | $ | 34,878 | $ | 1,210,874 | ||||||
2006 | 250,000 | 140,625 | 116,875 | 9,931 | 517,431 | |||||||||||||
David S. Schorlemer | 2007 | $ | 253,846 | $ | 326,087 | (4) | $ | 32,031 | $ | 35,094 | $ | 647,058 | ||||||
2006 | 225,000 | 126,563 | 105,188 | 10,655 | 467,405 | |||||||||||||
Hill M. Dishman | 2007 | $ | 211,538 | $ | 293,274 | (5) | $ | 26,563 | $ | 30,712 | $ | 562,087 | ||||||
2006 | 185,385 | 112,500 | 93,500 | 7,486 | 398,871 | |||||||||||||
Douglas E. Stewart(2) | 2007 | $ | 96,923 | $ | 72,000 |
| — | $ | 3,370 | $ | 172,293 | |||||||
Jennifer Guidry | 2007 | $ | 136,198 | $ | 40,500 | (6) | $ | 40,500 | $ | 20,085 | $ | 237,283 | ||||||
2006 | 114,427 | 17,325 | 51,975 | 3,411 | 186,838 |
(1) | “All Other Compensation” includes the aggregate value of matching contributions to our 401(k) plan, the dollar value of life insurance coverage, the dollar value of non-discriminatory disability insurance and automobile benefits. |
The table below itemizes the aggregate value of matching contributions to our 401(k) plan and the automobile benefits provided to the Named Executive Officers in 2007:
Name | 401(k) Plan | Automobile Benefits | ||||
Craig M. Johnson | $ | 12,767 | $ | 19,983 | ||
David S. Schorlemer | 12,074 | 21,000 | ||||
Hill M. Dishman | 11,404 | 17,500 | ||||
Douglas E. Stewart | 2,492 | — | ||||
Jennifer Guidry | 6,846 | 12,000 |
(2) | Mr. Stewart was hired in June 2007. |
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(3) | Mr. Johnson was awarded a bonus for 2007 of $663,526 in addition to the $172,266 awarded to Mr. Johnson under the discretionary portion of the annual cash incentive plan. |
(4) | Mr. Schorlemer was awarded a bonus for 2007 of $181,946 in addition to the $144,141 awarded to Mr. Schorlemer under the discretionary portion of the annual cash incentive plan. |
(5) | Mr. Dishman was awarded a bonus for 2007 of $173,743 in addition to the $119,531 awarded to Mr. Dishman under the discretionary portion of the annual cash incentive plan. |
(6) | Ms. Guidry was awarded a bonus for 2007 of $20,250 in addition to the $20,250 awarded to Ms. Guidry under the discretionary portion of the annual cash incentive plan. |
Grants of Plan-Based Awards
The following table and the footnotes thereto provide information regarding grants of plan-based non-equity awards made to the named executive officers during 2007:
Grants of Plan Based Awards | |||||||||||
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1) | |||||||||||
Name | Grant Date | Threshold | Target | Maximum | |||||||
Craig M. Johnson | — | $ | 84,219 | $ | 168,438 | $ | 210,547 | ||||
David S. Schorlemer | — | 70,469 | 140,938 | 176,172 | |||||||
Hill M. Dishman | — | 58,438 | 116,875 | 146,094 | |||||||
Jennifer Guidry | — | 30,375 | 60,750 | — |
(1) | These awards were granted under our annual cash incentive plan. At the time our annual cash incentive plan for 2007 was adopted, the estimated future payouts in the above table under the heading “Estimated Possible Payouts Under Non-Equity Incentive Plan Awards” represented the incentive payments available for awards to the Named Executive Officers under the annual cash incentive plan. |
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
The following is a discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table and Grants of Plan Based Awards Table.
A discussion of total compensation and each individual element of compensation of our Named Executive Officers for 2007 is included in “Compensation Discussion and Analysis.”
Employment agreements. Stallion Ltd. has entered into a separate employment agreement (together, the “Employment Agreements,” and each an “Employment Agreement”) with each of Messrs. Johnson, Schorlemer and Dishman (together the “Employees” and each an “Employee”), the extension term of which terminates on January 31, 2009. Unless either party to an Employment Agreement gives notice of its intention not to renew prior to November 2, 2008, the term of such agreement will be automatically extended for successive one-year periods until notice is given by either party prior to November 2nd of any subsequent year that the term of employment will expire on January 31 of the following year. The Employment Agreements provide for an annual base salary of $250,000, $225,000 and $180,000 for each of Messrs. Johnson, Schorlemer and Dishman, respectively, subject to increase from time to time. Messrs. Johnson, Schorlemer and Dishman are also eligible to receive an annual discretionary performance bonus with respect to each calendar year during the term of their Employment Agreement to the extent such bonuses are declared by the GP Board. Each Employee is also entitled to participate in all employee benefit plans and programs that we may provide from time to time.
In connection with the Employment Agreements, each of the Employees was indirectly granted Class E Units representing limited partnership interests of our predecessor. The Class E Units were granted directly to Stallion Value, L.P., in which Messrs. Johnson, Schorlemer and Dishman and certain of our other employees own interests. Messrs. Johnson, Schorlemer and Dishman received 600,000, 600,000 and 300,000 Class E Units, respectively. Mr. Johnson also indirectly received 7,653,061 Class F Units representing limited partnership interests of our predecessor.
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Stallion Ltd. has entered into an employment agreement with Ms. Guidry, the term of which terminates on March 1, 2009 (the “Guidry Employment Agreement”). The term of such agreement will be automatically extended for successive one-year periods until notice is given by either party no later than 90 days prior to the scheduled expiration of the then applicable extension term. The Guidry Employment Agreement provides for an annual base salary of $115,500, subject to increase from time to time. Ms. Guidry is also eligible to receive an annual discretionary performance bonus with respect to each calendar year during the term of the Guidry Employment Agreement to the extent such bonuses are declared by the GP Board. Ms. Guidry is also entitled to participate in all employee benefit plans and programs that we may provide from time to time. Effective October 2007, Ms. Guidry’s annual base salary is $150,000 and she remains eligible to receive an annual bonus of up to 60% of her base salary.
Stallion Ltd. has entered into an employment agreement with Mr. Stewart, the initial term of which terminates July 19, 2010 (the “Stewart Employment Agreement”). Unless either party to the Stewart Employment Agreement gives notice of its intention not to renew prior to April 21, 2010, the term of such agreement will be automatically extended for successive one-year periods until notice is given by either party no later than 90 days prior to the scheduled expiration of the then applicable extension term. The Stewart Employment Agreement provides for an annual base salary of $180,000, subject to increase from time to time. Mr. Stewart is also eligible to receive an annual discretionary performance bonus with respect to each calendar year during the term of the Stewart Employment Agreement to the extent such bonuses are declared by the GP Board. Mr. Stewart is also entitled to participate in all employee benefit plans and programs that we may provide from time to time. Effective October 2007, Mr. Stewart’s annual base salary is $185,000 and he is eligible to receive an annual bonus of up to 100% of his base salary.
The Employment Agreements, the Guidry Employment Agreement and the Stewart Employment Agreement also contain severance and change in control provisions which are described in detail below in the section titled “Potential Payments Upon a Termination or Change in Control.”
Stallion Value, L.P. Stallion Value, L.P. (“Stallion Value”) owns all the E Units of Stallion Ltd. The partnership interests in Stallion Value are divided into two classes: E-1 and E-2 Units. Class E-1 and Class E-2 Units have the same rights and preferences, except that Class E-1 Units are entitled to receive a preferential distribution prior to any distributions to Class E-2 Units. The Class E-1 Units are held by Messrs. Johnson, Schorlemer and Dishman and other partners in Stallion Value that received units in Stallion Value early in Stallion Ltd.’s formation. The preferential distribution will be an amount of cash or property with a value of $1/Class E-1 Unit. The preferential distribution will be made to each Class E-1 unitholder in the proportion of such holder’s Class E-1 Units over the aggregate number of Class E-1 Units held by all Class E-1 unitholders. Further distributions from Stallion Ltd. to its partners after the preferential distribution has been made to the Class E-1 unitholders will be made to all of the unitholders of Stallion Value in the ratio of each such unitholder’s Class E-1 and Class E-2 Units divided by the aggregate number of Class E-1 and Class E-2 Units held by all unitholders. At or prior to this initial public offering, the Class E-1 unitholders will contribute their rights in and to Class E-1 Units to us in exchange for shares of our common stock which will have a value (based on the offering price to the public) equal to the preferential distribution.
2008 Stock Incentive Plan
We currently anticipate that, prior to the consummation of this offering, the Company’s board of directors and stockholders will adopt the 2008 Stock Incentive Plan (the “Plan”). The principal purpose of the Plan will be to promote our success, enhance our value, and attract, retain and motivate selected employees, consultants and directors through the granting of stock-based compensation awards. The Plan will provide for a variety of such incentive awards, including nonstatutory stock options, incentive stock options (within the meaning of Section 422 of the Internal Revenue Code, or the “Code”), stock appreciation rights, restricted stock awards, restricted stock unit awards, performance-based awards, and other stock-based awards. We currently anticipate that shares of the Company’s common stock will be reserved for issuance under the Plan.
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Administration
Prior to the consummation of this offering, the Plan will be administered by a committee appointed by the Company’s board of directors. Upon and following the consummation of this offering, the Plan will be administered by a compensation committee of the board of directors. The board of directors, or the compensation committee if so empowered, will have the authority to interpret the Plan and to adopt such rules for the administration, interpretation and application of the Plan according to its terms. However, the board of directors may not delegate, to the compensation committee or otherwise, the power to grant awards to independent directors.
Grant of Awards
Certain employees, consultants and directors will be eligible to be granted awards under the Plan. The Company’s board of directors, or the compensation committee if so empowered, will determine:
• | which employees, consultants and directors are to be granted awards; |
• | the type of award that is granted (only employees can be granted incentive stock options under Code Section 422); |
• | the number of shares subject to the awards; and |
• | terms and conditions of each award, as consistent with the Plan. |
Under the Plan, performance-based awards are intended to comply with the requirements of Code Section 162(m), in order to allow those awards, when payable, to be fully tax deductible by the Company.
Expiration of Stock Options
The term of an option will be set by the Company’s board of directors, or the compensation committee if so empowered, subject to the following conditions: (1) no option term will be longer than ten years from the date of grant; and (2) the option term for an incentive stock option granted to an employee owning more than 10% of the total combined voting power of all classes of the Company’s capital stock will not exceed five years from the date of grant. Upon termination of an outstanding option holder’s services, the holder may exercise such holder’s options within the time period specified in the option grant, to the extent that the options were vested as of the termination date.
Adjustments of Awards
If the Company shall effect any stock dividend, stock split, subdivision, consolidation, recapitalization, or other capital readjustment, without receiving compensation therefor, then the number of outstanding shares under the Plan and the option price or fair market value of awards shall be proportionately adjusted.
The board of directors, or the compensation committee if so empowered, shall take such action as it deems appropriate in order that the value of each outstanding award shall not be adversely affected by any of these events.
Amendment or Termination
The board of directors may generally amend or terminate the Plan at any time; however, the board must generally obtain approval of the shareholders: (i) to increase the number of shares of common stock that may be issued under the Plan; (ii) to amend the group of employees eligible for awards under the Plan; (iii) to extend the term of the Plan; (iv) to increase the per person limits on awards intended to qualify for the performance-based exception; or (v) to the extent otherwise required by applicable law, rule or regulation.
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Potential Payments Upon Termination or Change in Control
Under the Employment Agreements, if an Employee’s employment is terminated for any reason, including death or disability, the Employee will be entitled to receive (1) an amount equal to the Employee’s annual base salary accrued through the date of termination and not previously paid plus (2) any reimbursable expenses paid by and owed to the Employee plus (3) any accrued vacation pay owed to the Employee and (4) any accrued vested benefits under our employee benefit plans, programs and arrangements (which shall be payable in accordance with the terms and conditions of such employee benefit plans, programs or arrangements) (together, the payments set forth in (1), (2), (3) and (4) above are the “Base Termination Payments”).
If an Employee’s employment is terminated (other than during any 12-month period following any Change in Control (as defined below)) (1) by the Employee for Good Reason (as defined below), (2) by us for any reason other than for Cause (as defined below) or (3) because we do not extend the Employee’s term (and with respect to a non-extension of the Employee’s term, the Employee complies with the provisions relating to non-competition, non-disclosure of proprietary information, and inventions), in addition to the Base Termination Payments, the Employee will be entitled to receive the following benefits, subject to the non-compete, confidentiality and inventions provisions, and provided that the Employee executes a general waiver and release:
(A) an amount equal to the Employee’s annual base salary that the Employee would have received if he had continued his employment under his Employment Agreement for a period equal to the greater of 24 months following the date of termination and the remainder of the Employee’s term under his Employment Agreement;
(B) an amount equal to any earned portion of the Employee’s annual bonus for the completed year preceding the date of termination that remains unpaid; and
(C) all unvested Class E Units and Class F Units held by the Employee will become fully vested.
Under the Employment Agreements, if during the 12-month period immediately following a Change in Control, an Employee’s employment is terminated by the Employee for Good Reason or by us for any reason other than for Cause, in addition to the Base Termination Payments, the Employee will be entitled to receive the following benefits, subject to the non-compete and confidentiality provisions, and provided that the Employee executes a general waiver and release:
(A) an amount equal to three times his annual base salary paid in a lump sum within 30 days of termination;
(B) an amount equal to any earned portion of the Employee’s annual bonus for the completed year preceding the date of termination that remains unpaid;
(C) continued coverage for the Employee and his dependents under our health benefit plans until the earlier date of the Employee’s coverage under another employee benefit plan or 18 months after the date of termination; and
(D) all unvested Class E Units held by the Employee will become fully vested.
In addition, under the Employment Agreements, if an Employee’s employment is terminated at any time due to death or disability, all unvested Class E Units and Class F Units held by the Employee will become fully vested. If an Employee’s employment is terminated at any time due to disability, that Employee is also entitled to an amount equal to the Employee’s base salary that the Employee would have been entitled to receive if the Employee had continued his employment under his Employment Agreement for a period of six months following the date of termination.
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The following terms have the specified meanings for purposes of the Employment Agreements, the Guidry Employment Agreement and the Stewart Employment Agreement:
• | Stallion Oilfield Services Ltd. shall have “Cause” to terminate employee’s employment if (i) employee has engaged in gross negligence, gross incompetence, or willful misconduct in the performance of, or employee’s refusal without proper reason to perform, the duties and services required of employee pursuant to the employment agreement, which is not remedied within thirty (30) days following written notice to employee by Stallion Oilfield Services Ltd. specifying such failure; (ii) employee is convicted of a felony; or (iii) employee materially breaches any material provision of the employment agreement or corporate code or policy of Stallion Oilfield Services Ltd., which breach remains uncorrected after thirty (30) days following written notice to employee of such breach (the applicable breach or provision do not need to be material in the Guidry Employment Agreement). |
• | “Change in Control” means (i) the consummation of the sale, transfer, conveyance or other disposition (including any merger, reorganization or consolidation) in one or a series of related transactions of the voting equity securities of Stallion Holdings, Ltd. or its successor or a similar transaction (other than an initial public offering of equity securities of Stallion Oilfield Services Ltd. through a registration statement filed with the Securities and Exchange Commission) such that immediately following such transaction (or transactions) any “person” or related “group” of “persons” (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act) (other than Stallion Holdings, Ltd., any of its current subsidiaries, an employee benefit plan maintained by Stallion Holdings, Ltd. or any of its subsidiaries, C/R Stallion Investment Partnership, L.P. and its affiliates, and Cardigan Holdings, Inc. and its affiliates) beneficially owns more than fifty percent (50%) of the total voting equity securities of Stallion Holdings, Ltd. outstanding immediately after such acquisition or (ii) the sale or transfer of all or substantially all of Stallion Oilfield Services Ltd.’s assets to another corporation which is not a subsidiary or current affiliate of Stallion Oilfield Services Ltd. |
• | “Disability” means any mental or physical illness, condition, disability or incapacity which (i) prevents employee from discharging substantially all of his essential job responsibilities and employment duties; (ii) shall be attested to in writing in the reasonable opinion of a qualified doctor approved by the board of directors; and (iii) has prevented, or will prevent in the reasonable opinion of such doctor, employee from discharging his duties for a period of more than 210 days in any 365 day period. |
• | Employee shall have “Good Reason” to resign his employment upon the occurrence of any of the following: (i) a reduction in employee’s annual base salary; (ii) a breach by Stallion Oilfield Services Ltd. of any material provision of the employment agreement; (iii) a material reduction in employee’s duties or responsibilities for Stallion Oilfield Services Ltd. or its successor or there is a material change in employee’s title (the change in title provision is not applicable to the Guidry Employment Agreement); or (iv) any change in location of employee’s principal place of employment by more than sixty (60) miles from the location of Stallion Oilfield Services Ltd.’s principal office in Houston, Texas. Employee may not resign his employment for Good Reason unless (x) employee provides Stallion Oilfield Services Ltd. with at least thirty (30) days prior written notice of his intent to resign for Good Reason (which notice is provided not later than the 60th day following the occurrence of the event constituting Good Reason) and (y) Stallion Oilfield Services Ltd. does not remedy the alleged violation(s) within such 30-day period. |
The disclosure that follows delineates the amount of compensation and other benefits due to Messrs. Johnson, Schorlemer and Dishman in the event of their termination of employment, including, but not limited to, in connection with a Change in Control of the Company. The amounts shown assume that such termination was effective as of December 31, 2007, and thus includes amounts earned through such time and assumes all expenses have previously been reimbursed. In addition, in the case of a qualifying termination within 12 months after a Change in Control, the amounts shown assume continued coverage under our health benefit plans for 18 months after the date of termination. While these numbers represent our best estimate as to the amount that would be due to the executives, the actual amounts to be paid out can only be determined at the time of such executive’s separation from the Company.
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The following table presents the potential payments and benefits upon termination or change in control for Messrs. Johnson, Schorlemer and Dishman:
Named Executive Officer and Post Termination Benefits | Qualifying Termination | Qualifying Termination during the 12 months immediately following Change in Control | Termination for Cause or Resignation without Good Reason | Disability | Death | ||||||||||
Craig M. Johnson | |||||||||||||||
Salary | $ | 610,500 | $ | 915,750 | — | $ | 305,250 | — | |||||||
Accrued vacation(1) | 27,403 | 27,403 | $ | 27,403 | 27,403 | $ | 27,403 | ||||||||
Equity compensation | — | — | — | — | — | ||||||||||
Health benefit plan continuation coverage(2) | — | 11,653 | — | — | — | ||||||||||
Total | $ | 637,903 | $ | 954,806 | $ | 27,403 | $ | 332,653 | $ | 27,403 | |||||
David S. Schorlemer | |||||||||||||||
Salary | $ | 512,500 | $ | 768,750 | — | $ | 256,250 | — | |||||||
Accrued vacation(1) | 20,191 | 20,191 | $ | 20,191 | 20,191 | $ | 20,191 | ||||||||
Equity compensation | — | — | — | — | — | ||||||||||
Health benefit plan continuation coverage(2) | — | 11,653 | — | — | — | ||||||||||
Total | $ | 532,691 | $ | 800,594 | $ | 20,191 | $ | 276,441 | $ | 20,191 | |||||
Hill M. Dishman | |||||||||||||||
Salary | $ | 425,500 | $ | 637,500 | — | $ | 212,750 | — | |||||||
Accrued vacation(1) | 14,433 | 14,433 | $ | 14,433 | 14,433 | $ | 14,433 | ||||||||
Equity compensation | — | — | — | — | — | ||||||||||
Health benefit plan continuation coverage(2) | — | 10,775 | — | — | — | ||||||||||
Total | $ | 439,933 | $ | 662,708 | $ | 14,433 | $ | 226,183 | $ | 14,433 | |||||
(1) | Vacation benefits are accrued at a rate per hour of unused paid time off equal to an employee’s annual salary divided by 2080 (the number of work hours in a 52-week year based on a 40-hour work week). |
(2) | Calculated based upon amount of health care benefit premium paid by us in fiscal year 2007. |
Under the terms of the Employment Agreements, subject to certain exceptions, during their employment and for 24 months following the termination of their employment, the Employees may not compete in the markets in which we and our affiliates engage in business or planned to engage in business as of the date of termination.
Under the Stewart and Guidry Employment Agreements (together the “Officer Employment Agreements and each an “Officer Employment Agreement”), if Mr. Stewart’s or Ms. Guidry’s (together, the “Officers” and each an “Officer”) employment is terminated for any reason, including death or disability, the respective Officer will be entitled to a prompt payment by us of a lump sum amount equal to the respective Officer’s annual base salary accrued through the date of termination and not previously paid, any reimbursable expenses paid by and owed to the respective Officer, any accrued vacation pay owed to the Officer plus any accrued vested benefits under our employee benefit plans, programs and arrangements (which shall be payable in accordance with the terms and conditions of such employee benefit plans, programs or arrangements).
In addition to the termination benefits described above, if the respective Officer’s employment is terminated (other than during any 12-month period following any Change in Control) (i) by the respective Officer for Good Reason or by us for any reason other than for Cause, the respective Officer will be entitled to receive, subject to the non-compete, confidentiality and inventions provisions of the Officer Employment Agreements, and provided
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that the respective Officer executes a general waiver and release, (A) an amount equal to the respective Officer’s annual base salary that such Officer would have received if he or she had continued his or her employment under the respective Officer Employment Agreement for a period equal to the greater of 12 months following the date of termination and the remainder of Ms. Guidry’s term under the Guidry Employment Agreement, and the greater of 24 months following the date of termination and the remainder of Mr. Stewart’s term under the Stewart Employment Agreement, and (B) an amount equal to any earned portion of the respective Officer’s annual bonus for the completed year preceding the date of termination that remains unpaid, (ii) by us as a result of the respective Officer’s disability, such Officer will be entitled to receive, subject to the non-compete, confidentiality and inventions provisions of the Officer Employment Agreements, and provided that such Officer executes a general waiver and release, (A) an amount equal to such Officer’s annual base salary that such Officer would have received if he or she had continued his or her employment under the Officer Employment Agreements for a period of six months following the date of termination, net of other disability payments payable by any person to such Officer and (B) an amount equal to any earned portion of such Officer’s annual bonus for the completed year preceding the date of termination that remains unpaid, and (iii) as a result of the death of an Officer, such Officer’s estate will be entitled to receive an amount equal to any earned portion of such Officer’s annual bonus for the completed fiscal year preceding the date of termination that remains unpaid.
In addition to the termination benefits described above for a termination for any reason, if during the 12- month period immediately following a Change in Control, Ms. Guidry’s employment is terminated by Ms. Guidry for Good Reason or by us for any reason other than for Cause, Ms. Guidry will be entitled to receive, subject to the confidentiality and inventions provisions of the Guidry Employment Agreement, and provided that Ms. Guidry executes a general waiver and release, (A) an amount equal to Ms. Guidry’s annual base salary paid in a lump sum within 30 days of termination; (B) an amount equal to any earned portion of Ms. Guidry’s annual bonus for the completed year preceding the date of termination that remains unpaid; and (C) continued coverage for Ms. Guidry and her dependents under our health benefit plans until the earlier date of Ms. Guidry’s coverage under another employee benefit plan or six months after the date of termination.
In addition to the termination benefits described above for a termination for any reason, if during the 12- month period immediately following a Change in Control, Mr. Stewart’s employment is terminated by Mr. Stewart for Good Reason or by us for any reason other than for Cause, Mr. Stewart will be entitled to receive, subject to the confidentiality and inventions provisions of the Stewart Employment Agreement, and provided that Mr. Stewart executes a general waiver and release, (A) an amount equal to two times Mr. Stewart’s annual base salary paid in a lump sum within 30 days of termination; (B) an amount equal to any earned portion of Mr. Stewart’s annual bonus for the completed year preceding the date of termination that remains unpaid; and (C) continued coverage for Mr. Stewart and his dependents under our health benefit plans until the earlier date of Mr. Stewart’s coverage under another employee benefit plan or 12 months after the date of termination.
The disclosures that follow delineate the amount of compensation and other benefits due to Mr. Stewart and Ms. Guidry in the event of their termination of employment, including, but not limited to, in connection with a Change in Control of the Company. The amounts shown assume that any such termination was effective as of December 31, 2007, and thus includes amounts earned through such time and are estimates of the amounts which would be paid out to either Mr. Stewart or Ms. Guidry upon their termination. The actual amounts to be paid out can only be determined at the time of either Officer’s separation from the Company.
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The following table presents the potential payments and benefits upon termination or change in control for Ms. Guidry and Mr. Stewart:
Named Executive Officer and Post Termination Benefits | Qualifying Termination | Qualifying Termination during the 12 months immediately following Change in Control | Termination for Cause or Resignation without Good Reason | Disability | Death | |||||||||||
Douglas E. Stewart | ||||||||||||||||
Salary | $ | 457,500 | (1) | $ | 360,000 | — | $ | 90,000 | — | |||||||
Accrued Vacation(2) | 5,625 | 5,625 | $ | 5,625 | 5,625 | $ | 5,625 | |||||||||
Health Benefit Plan Continuation Coverage(3) | — | 11,653 | — | — | — | |||||||||||
Total | $ | 463,125 | $ | 377,278 | $ | 5,625 | $ | 95,625 | $ | 5,625 | ||||||
Jennifer Guidry | ||||||||||||||||
Salary | $ | 135,000 | $ | 135,000 | — | $ | 67,500 | — | ||||||||
Accrued Vacation(2) | 1,298 | 1,298 | $ | 1,298 | 1,298 | $ | 1,298 | |||||||||
Health Benefit Plan Continuation Coverage (3) | — | 5,827 | — | — | — | |||||||||||
�� | ||||||||||||||||
Total | $ | 136,298 | $ | 142,125 | $ | 1,298 | $ | 68,798 | $ | 1,298 | ||||||
(1) | The Stewart Employment Agreement expires on June 19, 2010, therefore 30.5 months remained on the Stewart Employment Agreement at December 31, 2007. |
(2) | Vacation benefits are accrued at a rate per hour of unused paid time off equal to an employee’s annual salary divided by 2080 (the number of work hours in a 52-week year based on a 40-hour work week). |
(3) | Calculated based upon amount of health care benefit premium paid by us in fiscal year 2007. |
Under the terms of the Officer Employment Agreements, subject to certain exceptions, during such Officer’s employment and for 24 months following the termination of such Officer’s employment, the Officers may not compete in the markets in which we and our affiliates engage in business or planned to engage in business as of the date of termination.
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Compensation of Directors of Holdings GP
The directors of Holdings GP did not receive compensation for their services as directors of Holdings GP during 2006. In connection with this offering, our Compensation Committee will approve the cash retainer fees, meeting fees and equity awards that will be provided to our directors, which compensation is described below. We expect that directors who are our full-time employees will receive no compensation for serving as directors.
Compensation of Directors of the Company
Directors who are also our employees do not receive a retainer or fees for service on our Board or any committees. Upon completion of this offering, directors who are not employees will receive an annual retainer of $30,000 and fees of $1,500 for attendance at each Board or committee meeting ($750 if a director attends a meeting telephonically). Each non-employee director who serves as the chairman of the Compensation Committee or the Nominating & Governance Committee receives an additional annual retainer of $5,000. The chairman of the Audit Committee receives an additional annual retainer of $15,000. Members of the Nominating and Governance Committee and the Compensation Committee, other than the Committee Chair, receive an additional annual retainer of $2,500 and members of the Audit Committee, other than the Committee Chair, receive an additional annual retainer of $7,500. Newly elected directors will receive restricted stock awards of the Company’s common stock valued at $75,000 after their initial election. Directors receive additional restricted stock awards of the Company’s common stock valued at $75,000 at each annual stockholders’ meeting after which they continue to serve. The directors’ restricted stock awards vest on the next annual stockholders’ meeting date following the date of grant. Directors are subject to the Company’s stock ownership guidelines pursuant to which they are expected to retain all restricted stock award shares remaining after payment of applicable taxes until retirement or until leaving the Board. All of our directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of our Board or committees and for other reasonable expenses related to the performance of their duties as directors.
Employment Agreements
We have entered into a separate employment agreement with each of Messrs. Johnson and Schorlemer (together the “Director Employees,” and each a “Director Employee”), the extension term of which terminates on January 31, 2009 (together, the “Director Employment Agreements,” and each a “Director Employment Agreement”). Unless either party to a Director Employment Agreement gives notice of its intention not to renew prior to November 2, 2008, the term of such agreement will be automatically extended for successive one-year periods until notice is given by either party prior to November 2 of any subsequent year that the term of employment will expire on January 31 of the following year. Messrs. Johnson’s and Schorlemer’s annual base salaries were initially set at $250,000 and $225,000, respectively, subject to increase at the discretion of our board of directors. In October 2007, the board of directors increased Messrs. Johnson’s and Schorlemer’s annual base salaries to $475,000 and $350,000, respectively. Messrs. Johnson and Schorlemer will be eligible to receive an annual bonus, if any, as determined by our board of directors, taking into account our profitability and each Director Employee’s performance during that calendar year. Each Director Employee is also entitled to participate in all employee benefit plans and programs that we may provide from time to time.
In connection with Messrs. Johnson’s and Schorlemer’s employment agreements, each of Mr. Johnson and Mr. Schorlemer indirectly received 600,000 Class E Units representing limited partnership interests of our predecessor. In addition, Mr. Johnson indirectly received 7,653,061 Class F Units representing limited partnership interests of our predecessor.
The Class E Units were granted directly to Stallion Value, L.P, in which Messrs. Johnson and Schorlemer and certain of our other employees own interests.
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Upon the closing of the Restructuring, the Class E Units and the Class F Units will be converted into shares of our common stock. Upon this conversion, Messrs. Johnson and Schorlemer will receive and shares of our common stock, respectively. In connection with the closing of this offering, these shares will no longer be subject to the forfeiture restrictions that previously encumbered the Class E Units and the Class F Units.
For information regarding potential payments upon termination or change in control for the Director Employees please see “Executive Compensation—Potential Payments Upon Termination or Change in Control”.
Under the terms of the Director Employment Agreements, subject to certain exceptions, during their employment and for 24 months following the termination of their employment, the Director Employees may not compete in the markets in which we and our affiliates engage in business or planned to engage in business as of the date of termination of each Director Employee’s respective employment.
Indemnification Agreements
We have entered into indemnification agreements with all of our directors and some of our officers under which we indemnify such persons against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. These persons are indemnified to the fullest extent now or hereafter permitted by the General Corporation Law of the State of Delaware. The indemnification agreements also provide for the advancement of expenses to these directors and officers in connection with any suit or proceeding.
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The descriptions set forth below are qualified in their entirety by reference to the applicable agreements.
Offering By Selling Stockholders
We are paying the expenses of this offering by the selling stockholders, other than underwriting discounts, commissions and transfer taxes with respect to shares of our common stock sold by the selling stockholders. We have agreed to indemnify the selling stockholders against liabilities under the Securities Act, or contribute to payments that the selling stockholders may be required to make in that respect.
Registration Rights Agreement
Stallion and Carlyle/Riverstone are parties to a registration rights agreement (the “Registration Rights Agreement”).
Demand Registration Rights
Under the Registration Rights Agreement, at any time after 180 days following this offering, Carlyle/Riverstone has the right, subject to certain limitations, to demand on six occasions that we register all or any portion of their registrable securities so long as the registrable securities proposed to be sold on an individual registration statement have an aggregate gross offering price of at least $20.0 million. After such time as we become eligible to use Form S-3 (or comparable form) for the registration under the Securities Act of any securities, Carlyle/Riverstone may request that securities be registered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, provided that any such registration will be treated as two demand registrations.
Piggyback Registration Rights
If we propose to file a registration statement under the Securities Act relating to an offering of our common stock, upon the written request of Carlyle/Riverstone, we will include in such registration, and any related underwriting, all of the registrable securities included in such requests, subject to customary cutback provisions.
Registration Procedures and Expenses
The Registration Rights Agreement contains customary procedures relating to underwritten offerings and the filing of registration statements. We have agreed to pay all registration expenses incurred in connection with any registration, up to a total of six registrations, including all registration, qualification and filing fees, printing expenses, reasonable fees of one counsel to Carlyle/Riverstone, blue sky fees and expenses and the expense of any special audits incident to or required by any such registration. All underwriting discounts and selling commissions and stock transfer taxes applicable to securities registered by holders and fees of counsel to any such holder (other than as described above) will be payable by holders of registrable securities.
Nominating Agreement
We are party to a nominating agreement (the “Nominating Agreement”) with C/R Stallion Investment Partnership, L.P. (“Investment Partnership”). Pursuant to the Nominating Agreement, as long as Investment Partnership beneficially owns at least 30%, 20% or 10% of our issued and outstanding shares of common stock, we have agreed to take all corporate action within our power required to cause the board of directors at all times to include at least three, two or one member(s), respectively, designated by Investment Partnership. In addition, as long as Investment Partnership beneficially owns at least a majority of the aggregate amount of shares of common stock it held immediately following the Restructuring, we have agreed to take all corporate action
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within our power required to cause the board of directors at all times to include at least one member designated by Investment Partnership. In the event that such designees are not elected to our board of directors, Investment Partnership will have the right to appoint observers to our board of directors.
The Restructuring
We were formed as a Delaware corporation in June 2006. In connection with this offering, we will succeed to the business and operations of Stallion Ltd, which are described in this prospectus. Prior to the completion of this offering, Stallion Ltd will merge with and into Stallion Oilfield Services, Inc., with Stallion Oilfield Services, Inc. being the surviving corporate parent and owning all of the operating subsidiaries of Stallion Ltd. The majority owners of Stallion Ltd are Carlyle/Riverstone and an affiliate of Craig Johnson, our President, Chief Executive Officer and Chairman of the Board. Since the entities are under common ownership and control, the Restructuring will be accounted for at historical cost. In the Restructuring, assuming an initial public offering price of $ , which is the midpoint of the range set forth on the cover of this prospectus, the partners of Stallion Ltd will receive an aggregate of shares of our common stock in exchange for all of the Stallion Ltd partnership interests held by them. Immediately following completion of the Restructuring and prior to this offering, we will have shares of common stock outstanding, % of which will be owned by Carlyle/Riverstone and % of which will be owned by an affiliate of Craig Johnson.
Transactions with Our Significant Stockholder
The partnership agreement governing our predecessor required our predecessor to pay Carlyle/Riverstone an annual fee equal to 1% of our predecessor’s consolidated pro forma EBITDA for the provision of support services. Our obligation to pay this fee terminates upon the closing of our initial public offering.
In December 2006, Carlyle/Riverstone entered into a Contribution Agreement pursuant to which Carlyle/Riverstone agreed to acquire Class A partnership units in Stallion Ltd., our predecessor, for an aggregate investment of up to $125.0 million. Purchasers of units under the Contribution Agreement are subject to various conditions including approval of the board of the general partner of Stallion Ltd. As of August 15, 2008, $71.3 million has been funded under the Contribution Agreement. This investment arrangement will terminate upon completion of our initial public offering.
Transactions with Executive Officers and Directors
Two of our directors, Mr. John Lancaster and Mr. Pierre Lapeyre, are affiliated with Riverstone, an affiliate of Carlyle/Riverstone.
Mr. Craig Johnson, our President, Chief Executive Officer and Chairman of the Board, was party to a promissory note with us pursuant to which we borrowed $7.3 million at an annual interest rate of 6% from Mr. Johnson. The full principal amount of this loan was repaid to Mr. Johnson, along with related interest accrued, on January 31, 2005 in the total amount of $8.3 million.
On November 30, 2006, we made certain loans aggregating $10.0 million to certain of our executive officers (Mr. Johnson—$6.0 million, Mr. Schorlemer—$2.0 million and Mr. Dishman—$2.0 million). These notes had a ten-year maturity but could be accelerated by us upon certain acceleration events including an initial public offering. The notes bore interest at a rate of 4.97% per year. The full principal amounts of these loans were repaid by Messrs Johnson, Schorlemer and Dishman along with related interest accrued from November 30, 2006 of approximately $109,000, $36,000 and $36,000, respectively.
We lease an industrial facility in Alice, Texas from Q2 Rentals, L.L.C. for approximately $90,000 per year. Pursuant to an informal arrangement, we lease a houseboat and certain other recreational boats in coastal Louisiana on a month-to-month basis from Q2 Rentals in exchange for paying the operating expenses of the facilities which were approximately $0.2 million for the year ended December 31, 2007. Q2 Rentals is operated
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by Mr. David M. Johnson, Mr. Craig Johnson’s father, and owned equally by Mr. Craig Johnson, Mr. Clayton D. Johnson, Mr. Craig Johnson’s brother, and Mr. David M. Johnson.
In addition, we lease a King-Air airplane from Permian Mud Service, Inc. and have entered into an operating agreement to operate the aircraft with ChampAir, L.L.C. We incurred expenses related to Permian Mud Service, Inc. and ChampAir, L.L.C. of approximately $0.6 million, $0.9 million and $0.1 million for the years ended December 31, 2006 and 2007 and the six months ended June 30, 2008, respectively. ChampAir, L.L.C. is owned and operated by Permian Mud Service, Inc., of which Mr. David Johnson and our Chief Executive Officer, President and Chairman of the Board are minority shareholders. Our executive officers reimburse us for operating expenses associated with the personal use of the aircraft. The term of our lease for this plane expired on December 31, 2006, but is continuing on a month-to-month basis.
It is customary for us to lease real property from the former owners of businesses that we acquire. It is typical for many of these former owners to be employed by us. Thus, we and certain of our employees may be parties to leases relating to real property.
All loans made to our executive officers have been repaid to us and we will not make loans to executive officers in the future. We believe that our other related party transactions were either on terms at least as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties or were negotiated in connection with acquisitions, the overall terms of which were as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties.
Policies and Procedures for Approval of Related Party Transactions
From time to time we engage in transactions with a related party. Prior to this offering, these interested transactions were reviewed and approved or ratified by our board of directors and no policies and procedures were in place to assist the board of directors in its review, approval or ratification. Upon the listing of our common stock on The NASDAQ Stock Market LLC, the review of certain interested transactions will be governed by the policies and procedures contained in our Related-Party Transaction Policy (the “Related-Party Policy”) and the Audit Committee charter.
A “related party” is a director, executive officer, an immediate family member of a director or executive officer, stockholder owning more than 5% of our common stock, or any entity in which any of the foregoing persons is employed or is a partner or principal or in a similar position or in which such person has a 5% or greater beneficial ownership interest. The Audit Committee is responsible for reviewing certain interested transactions with related parties. An interested transaction is any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships in which (i) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (ii) the Company is a participant and (iii) any related party has or will have a direct or indirect (other than solely as a result of being a director or a less than 10% beneficial owner of another entity).
In the course of its review and approval or ratification of such interested transactions, the Audit Committee will consider various aspects of the transaction it deems appropriate, which will include:
• | whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances; and |
• | the extent of the related party’s interest in the transaction. |
We have various processes for identifying, reporting and reviewing conflicts of interests, including related person transactions. Our Proper Business Practices and Ethics Policy (“Ethics Policy”) provides that no director, officer or other employee shall engage in business or conduct, or enter into agreements or arrangements, which would give rise to actual, potential or the appearance of conflicts of interest. The Ethics Policy also provides procedures for reporting any actual or potential conflicts of interest. In addition, we annually distribute and
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review a questionnaire to our executive officers and directors requesting certain information regarding, among other things, certain transactions with us in which they or their family members have an interest.
No director will participate in any discussion or approval of an interested transaction for which he or she is a related party, except that the director shall provide all material information concerning the interested transaction to the Audit Committee.
Pursuant to the Related-Party Policy, the Audit Committee has reviewed the following interested transactions and such transactions are deemed to be preapproved by the Audit Committee:
1. | Employment of executive officers. Any employment by the Company of an executive officer of the Company if: |
a. | the related compensation is required to be reported in the Company’s proxy statement; or |
b. | the executive officer is not an immediate family member of another executive officer or director of the Company, the related compensation would be reported in the Company’s proxy statement if the executive officer was a “named executive officer”, and the Company’s Compensation Committee approved (or recommended that the board of directors approve) such compensation; |
2. | Director compensation. Any compensation paid to a director if the compensation is required to be reported in the Company’s proxy statement; |
3. | Certain transactions with other companies. Any transaction with another company at which a related party’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than ten percent (10%) of that company’s shares, if the aggregate amount involved does not exceed the greater of $200,000, or five percent (5%), of that company’s total annual revenues; |
4. | Certain Company charitable contributions. Any charitable contribution, grant or endowment by the Company to a charitable organization, foundation or university at which a related party’s only relationship is as an employee (other than an executive officer) or a director, if the aggregate amount involved does not exceed the lesser of $200,000, or five percent (5%), of the charitable organization’s total annual receipts; |
5. | Transactions where all shareholders receive proportional benefits. Any transaction where the related party’s interest arises solely from the ownership of the Company’s common stock and all holders of the Company’s common stock received the same benefit on a pro rata basis; |
6. | Transactions involving competitive bids. Any transaction involving a related party where the rates or charges involved are determined by competitive bids; |
7. | Regulated transactions. Any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority; and |
8. | Certain banking-related services. Any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar services. |
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth information with respect to the beneficial ownership of our common stock as of August 15, 2008, assuming the Restructuring had taken place prior to such date, by:
• | each selling stockholder in this offering; |
• | each person who is known by us to own beneficially 5% or more of our outstanding common stock; |
• | our named executive officers; |
• | our directors; and |
• | all of our executive officers and directors as a group. |
Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. Unless otherwise indicated, the address of each stockholder listed below is 950 Corbindale Houston, Texas 77024.
Shares Beneficially Owned Prior to this Offering | Number of Shares Offered | Shares Beneficially Owned After this Offering | ||||||||
Name of Beneficial Owner | Number | % | Number | % | ||||||
C/R Stallion Investment Partnership, | % | % | ||||||||
C/R Energy Coinvestment II, L.P.(1)(2) | ||||||||||
Cardigan Holdings, Inc.(2)(3) | ||||||||||
Craig M. Johnson(2) | ||||||||||
David S. Schorlemer(2) | ||||||||||
Hill M. Dishman(2) | ||||||||||
Douglas E. Stewart | ||||||||||
Jennifer Guidry | ||||||||||
John Lancaster(1)(4) | ||||||||||
Pierre Lapeyre(1)(5) | ||||||||||
Directors and Executive Officers as a Group (7 persons)(3)(4)(5) |
* | Less than 1%. |
(1) | The address of this stockholder is c/o The Carlyle Group, 1001 Pennsylvania Avenue, N.W., Suite 200, Washington, D.C. 20004. |
(2) | A selling stockholder in this offering. |
(3) | Craig M. Johnson is the natural person who has voting and investment control over the securities owned by Cardigan Holdings, Inc. Mr. Johnson serves as Chief Executive Officer and the sole stockholder of Cardigan Holdings, Inc. |
(4) | Mr. Lancaster serves as a Managing Director of Riverstone, an affiliate of Carlyle/Riverstone. As such, Mr. Lancaster may be deemed to have voting and dispositive power over the shares beneficially owned by Carlyle/Riverstone. Mr. Lancaster disclaims beneficial ownership of the shares owned by Carlyle/Riverstone. |
(5) | Mr. Lapeyre serves as a Senior Managing Director of Riverstone, an affiliate of Carlyle/Riverstone. As such, Mr. Lapeyre may be deemed to have voting and dispositive power over the shares beneficially owned by Carlyle/Riverstone. Mr. Lapeyre disclaims beneficial ownership of the shares owned by Carlyle/Riverstone. |
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Upon the completion of this offering, our authorized capital stock will consist of:
• | shares of common stock, $0.01 par value; and |
• | shares of preferred stock, $0.01 par value, none of which are currently designated. |
Upon the completion of this offering, shares of common stock and no shares of preferred stock will be outstanding.
The following summarizes the material provisions of our capital stock and important provisions of our certificate of incorporation and bylaws. This summary is qualified by our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus is a part and by the provisions of applicable law.
Common Stock
Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Because holders of common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election. The holders of common stock are entitled to receive dividends as may be declared by the board of directors. Upon our liquidation, dissolution or winding up, and subject to any prior rights of outstanding preferred stock, the holders of our common stock will be entitled to share pro rata in the distribution of all of our assets available for distribution to our stockholders after satisfaction of all of our liabilities and the payment of the liquidation preference of any preferred stock that may be outstanding. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable. The holders of our common stock will have no preemptive or other subscription rights to purchase our common stock.
Preferred Stock
Subject to the provisions of the certificate of incorporation and limitations prescribed by law, the board of directors will have the authority to issue up to shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions of the preferred stock, including dividend rights, dividend rates, conversion rates, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of the series, which may be superior to those of the common stock, without further vote or action by the stockholders. We have no present plans to issue any shares of preferred stock.
One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and, as a result, protect the continuity of our management. The issuance of shares of the preferred stock under the board of directors’ authority described above may adversely affect the rights of the holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock or may otherwise adversely affect the market price of the common stock.
Provisions of Our Certificate of Incorporation and Bylaws
Written Consent of Stockholders
Our certificate of incorporation and bylaws provide that any action required or permitted to be taken by our stockholders must be taken at a duly called meeting of stockholders and not by written consent.
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Amendment of the Bylaws
Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by the holders of not less than of the voting power of all outstanding voting stock.
Special Meetings of Stockholders
Our bylaws preclude the ability of our stockholders to call special meetings of stockholders.
Other Limitations on Stockholder Actions
Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. In addition, the ability of our stockholders to remove directors without cause is precluded.
Limitation of Liability of Officers and Directors
Our certificate of incorporation provides that no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:
• | for any breach of the director’s duty of loyalty to us or our stockholders; |
• | for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of laws; |
• | for unlawful payment of a dividend or unlawful stock purchase or stock redemption; and |
• | for any transaction from which the director derived an improper personal benefit. |
The effect of these provisions is to eliminate our rights and our stockholders’ rights, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for a breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.
Business Combination Under Delaware Law
We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.
Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:
• | our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status; |
• | upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time |
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the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued under employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or |
• | the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder. |
This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law. This election would be effective 12 months after the adoption of the amendment and would not apply to any business combination between us and any person who became an interested stockholder on or before the adoption of the amendment.
Registration Rights
We are party to a registration rights agreement with Carlyle/Riverstone covering all or any portion of the shares of common stock owned by Carlyle/Riverstone after the closing of this offering. For a description of the registration rights agreement, see “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”
Transfer Agent and Registrar
The transfer agent and registrar for the common stock is Computershare Investor Services, LLC.
Quotation of Common Stock
We have applied to include our shares of common stock for quotation on The NASDAQ Stock Market LLC under the symbol “SOFS.”
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SHARES ELIGIBLE FOR FUTURE SALE
Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors also could make it more difficult to raise funds through future offerings of common stock.
After this offering, shares of common stock will be outstanding, or shares if the underwriters exercise in full their option to purchase additional shares. Of these shares, the shares sold in this offering, or shares if the underwriters exercise in full their option to purchase additional shares, will be freely tradable without restriction under the Securities Act, except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. A total of shares will be “restricted securities” within the meaning of Rule 144 under the Securities Act or subject to lock-up arrangements.
The restricted securities generally may not be sold unless they are registered under the Securities Act or are sold under an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. After this offering, the holders of shares of our common stock will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.
Our officers and directors and substantially all of our stockholders have entered into lock-up agreements described in “Underwriting.” Approximately shares, representing approximately %, of our common stock will not be subject to any lock-up arrangements. These shares may be freely tradable upon the consummation of this offering.
As restrictions on resale end, the market price of our common stock could drop significantly if the holders of these restricted shares sell them, or are perceived by the market as intending to sell them.
As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock option plans. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups we and our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
Rule 144
In general, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least six months is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:
• | 1% of the then outstanding shares of common stock; and |
• | the average weekly trading volume of the common stock on The NASDAQ Stock Market LLC during the four calendar weeks immediately proceeding the date on which the notice of the sale on Form 144 is filed with the Securities Exchange Commission. |
Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.
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A person who is not one of our affiliates, and who is not deemed to have been one of our affiliates at any time during the three months preceding a sale, may sell the shares proposed to be sold according to the following conditions:
• | If the person has beneficially owned the shares for at least six months, including the holding period of any prior owner other than an affiliate, the shares may be sold, subject only to continued availability of current public information about us. |
• | If the person has beneficially owned the shares for at least one year, including the holding period of any prior owner other than an affiliate, the shares may be sold without any Rule 144 limitations. |
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CERTAIN UNITED STATES FEDERAL TAX CONSIDERATIONS
FOR NON-UNITED STATES HOLDERS
The following is a general discussion of the principal United States federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder. As used in this discussion, the term “non-U.S. holder” means a beneficial owner of our common stock that is not, for U.S. federal income tax purposes:
• | an individual who is a citizen or resident of the United States; |
• | a corporation or partnership (including any entity treated as a corporation or partnership for U.S. federal income tax purposes) created or organized in or under the laws of the United States, or of any political subdivision of the United States; |
• | an estate whose income is subject to U.S. federal income taxation regardless of its source; or |
• | a trust, in general, if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person. |
An individual may be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of this calculation, you would count all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens. This discussion does not consider:
• | U.S. state or local or non-U.S. tax consequences; |
• | all aspects of U.S. federal income and estate taxes or specific facts and circumstances that may be relevant to a particular non-U.S. holder’s tax position, including the fact that in the case of a non-U.S. holder that is an entity treated as a partnership for U.S. federal income tax purposes, the U.S. tax consequences of holding and disposing of our common stock may be affected by certain determinations made at the partner level; |
• | the tax consequences for the stockholders, partners or beneficiaries of a non-U.S. holder; |
• | special tax rules that may apply to particular non-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, U.S. expatriates, broker-dealers, traders in securities, common trust funds, controlled foreign corporations or persons that have a functional currency other than the U.S. dollar; or |
• | special tax rules that may apply to a non-U.S. holder that holds our common stock as part of a “straddle,” “hedge,” “conversion transaction,” “synthetic security” or other integrated investment. |
The following discussion is based on provisions of the U.S. Internal Revenue Code of 1986, as amended, existing and proposed Treasury regulations and administrative and judicial interpretations, all as of the date of this prospectus, and all of which are subject to change, retroactively or prospectively. The following summary assumes that a non-U.S. holder holds our common stock as a capital asset.
Prospective purchasers should consult a tax advisor regarding the U.S. Federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.
Distributions on Common Stock
In the event that we make cash distributions on our common stock, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated
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earnings and profits, as determined under U.S. federal income tax principles. Dividends paid to non-U.S. holders of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a U.S. trade or business will be subject to U.S. withholding tax at a 30% rate, or if a tax treaty applies, a lower rate specified by the treaty. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under a relevant income tax treaty.
Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, are attributable to a permanent establishment in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with the conduct of a trade or business in the United States.
A non-U.S. holder who claims the benefit of an applicable income tax treaty generally will be required to satisfy applicable certification and other requirements. However,
• | in the case of common stock held by a foreign partnership, the certification requirement will generally be applied to the partners of the partnership and the partnership will be required to provide certain information; |
• | in the case of common stock held by a foreign trust, the certification requirement will generally be applied to the trust or the beneficial owners of the trust depending on whether the trust is a “foreign complex trust,” “foreign simple trust” or “foreign grantor trust” as defined in the U.S. Treasury regulations; and |
• | look-through rules will apply for tiered partnerships, foreign simple trusts and foreign grantor trusts. |
A non-U.S. holder that is a foreign partnership or a foreign trust is urged to consult its own tax advisor regarding its status under these U.S. Treasury regulations and the certification requirements applicable to it.
A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the U.S. Internal Revenue Service.
Gain on Disposition of Common Stock
A non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:
• | the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States; in these cases, the gain will be taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons and, if the non-U.S. holder is a foreign corporation, the “branch profits tax” described above may also apply; |
• | the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements; or |
• | we are or have been a “United States real property holding corporation” for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock. |
Generally, a corporation is a “United States real property holding corporation” if the fair market value of its “United States real property interests” equals or exceeds 50% of the sum of the fair market value of its
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worldwide real property interests plus its other assets used or held for use in a trade or business. The tax relating to stock in a “United States real property holding corporation” generally will not apply to a non-U.S. holder whose holdings, direct and indirect, at all times during the applicable period, constituted 5% or less of our common stock, provided that our common stock was regularly traded on an established securities market. We believe that we are not currently, and we do not anticipate becoming in the future, a “United States real property holding corporation” for U.S. federal income tax purposes.
U.S. Federal Estate Tax
Common stock owned or treated as owned by an individual who is not a citizen or resident of the United States (as defined for U.S. federal estate tax purposes) at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise and, therefore, may be subject to U.S. federal estate tax.
Information Reporting and Backup Withholding Tax
Dividends paid to you may be subject to information reporting and U.S. backup withholding. If you are a non-U.S. holder you will be exempt from this backup withholding tax if you properly provide a Form W-8BEN certifying that you are a non-U.S. holder or you otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder or otherwise establish an exemption.
The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that:
• | is a U.S. person; |
• | derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States; |
• | is a “controlled foreign corporation” for U.S. tax purposes; or |
• | is a foreign partnership, if at any time during its tax year: |
i. | one or more of its partners are U.S. persons who in the aggregate hold more than 50% of the income or capital interest in the partnership; or |
ii. | the foreign partnership is engaged in a U.S. trade or business, |
unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met or you otherwise establish an exemption.
If you receive payments of the proceeds of a sale of our common stock to or through a U.S. office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless you properly provide a Form W-8BEN certifying that you are a non-U.S. person or you otherwise establish an exemption.
You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability by timely filing a properly completed refund claim with the U.S. Internal Revenue Service.
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Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC are acting as joint book-running managers and representatives of the underwriters of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us and the selling shareholders the respective number of common stock shown opposite its name below:
Underwriters | Number of Shares | |
Lehman Brothers Inc. | ||
Credit Suisse Securities (USA) LLC | ||
UBS Securities LLC | ||
Raymond James & Associates, Inc. | ||
Total | ||
The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:
• | the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased; |
• | the representations and warranties made by us and the selling stockholders to the underwriters are true; |
• | there is no material change in our financial condition or the financial markets; and |
• | we deliver customary closing documents to the underwriters. |
Commissions and Expenses
The following table summarizes the underwriting discounts and commissions we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling stockholders for the shares.
Per Share | Total | |||||||
No Exercise | Full Exercise | No Exercise | Full Exercise | |||||
Paid by us | $ | $ | $ | $ | ||||
Paid by selling stockholders | $ | $ | $ | $ |
The representatives of the underwriters have advised us that the underwriters propose to offer the shares of common stock directly to the public initially at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per share. After the initial offering, the representatives may change the offering price and other selling terms.
The expenses of the offering that are payable by us and the selling stockholders are estimated to be $ (excluding underwriting discounts and commissions). We have agreed to pay expenses incurred by the selling stockholders in connection with the offering, other than the underwriting discounts and commission.
Option to Purchase Additional Shares
We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of shares at the public offering price
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less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this underwriting section.
Lock-Up Agreements
We, all of our directors and executive officers and the selling stockholders have agreed that, subject to certain exceptions, without the prior written consent of each of Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC, we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock (including, without limitation, shares of common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and shares of common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of common stock or securities convertible, exercisable or exchangeable into common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.
The 180-day restricted period described in the preceding paragraph will be extended if:
• | during the last 17 days of the 180-day restricted period we issue an earnings release or material news or announce a material event relating to us; or |
• | prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, |
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.
Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC in their sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common stock and other securities from lock-up agreements, Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time. The underwriters have no present intent, agreements or understandings to release any of the lock-up agreements early.
Offering Price Determination
Prior to this offering, there has been no public market for our common stock. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common stock, the representatives will consider:
• | the history and prospects for the industry in which we compete; |
• | our financial information; |
• | the ability of our management and our business potential and earning prospects; |
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• | the prevailing securities markets at the time of this offering; and |
• | the recent market prices of, and the demand for, publicly traded shares of generally comparable companies. |
Indemnification
We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.
Directed Share Program
At our request, the underwriters have reserved for sale at the initial public offering price up to 5% of the total shares of our common stock offered hereby (excluding any shares to be sold pursuant to the over-allotment option) for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered hereby. The purchasers under the directed share program will be subject to lock-up provisions identical to those described above.
Stabilization, Short Positions and Penalty Bids
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock, in accordance with Regulation M under the Exchange Act:
• | Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. |
• | A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. |
• | Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. |
• | Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. |
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market
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price of the common stock. As a result, the price of the common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The NASDAQ Stock Market LLC or otherwise and, if commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make representations that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
Electronic Distribution
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
Listing
We have applied to list our shares of common stock for quotation on The NASDAQ Stock Market LLC under the symbol “SOFS.”
Discretionary Sales
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.
Stamp Taxes
If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
Other Relationships/FINRA Rules
Some of the underwriters and their affiliates have engaged in transactions with, and performed commercial and investment banking financial advisor or lending services for, us and our affiliates from time to time, for which they have received customary compensation and may do so in the future. UBS Securities LLC and Credit Suisse Securities (USA) LLC served as joint arrangers of our credit facility, an affiliate of UBS Securities LLC serves as administrative and collateral agent of our credit facility and affiliates of Lehman Brothers Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC serve as lenders under our credit facility. They receive fees customary for performing these services and, in the case of the lenders, interest on such indebtedness. Credit Suisse Securities (USA) LLC and UBS Securities LLC served as joint arrangers of our bridge loan facility and an affiliate of Credit Suisse Securities (USA) LLC serves as administrative agent and sole lender under our bridge loan facility. They receive fees customary for performing these services and, in the case of the sole lender, interest on such
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indebtedness. We currently intend to use the net proceeds received by us in this offering to repay our bridge loan facility in full and to repay a portion of our credit facility, in which case affiliates of Lehman Brothers Inc., UBS Securities LLC and Credit Suisse Securities (USA) LLC, as lenders under such facilities, will receive substantially all of the net proceeds received by us in this offering. Please read “Use of Proceeds.” Because of these relationships, this offering is being conducted in accordance with Rules 2720 and 2710(h) of the NASD Conduct Rules (which are part of the rules of the Financial Industry Regulatory Authority, Inc., or FINRA). These rules require that the initial public offering price for our shares cannot be higher than the price recommended by a “qualified independent underwriter,” as defined by the FINRA. Raymond James & Associates Inc. is serving as a qualified independent underwriter and will assume the customary responsibilities of acting as a qualified independent underwriter in pricing the offering and conducting due diligence. We have agreed to indemnify Raymond James & Associates Inc. against any liabilities arising in connection with its role as a qualified independent underwriter, including liabilities under the Securities Act.
Foreign Selling Restrictions
Australia
This prospectus is not a formal disclosure document and has not been lodged with the Australian Securities and Investments Commission (“ASIC”). It does not purport to contain all information that an investor or their professional advisers would expect to find in a prospectus for the purposes of Chapter 6D.2 of the Australian Corporations Act 2001 (Act) in relation to the securities or our company.
This prospectus is not an offer to retail investors in Australia generally. Any offer of securities in Australia is made on the condition that the recipient is a “sophisticated investor” within the meaning of section 708(8) of the Act or a “professional investor” within the meaning of section 708(11) of the Act, or on condition that the offer to that recipient can be brought within the exemption for ‘Small-Scale Offerings’ (within the meaning of section 708(1) of the Act). If any recipient does not satisfy the criteria for these exemptions, no applications for securities will be accepted from that recipient. Any offer to a recipient in Australia, and any agreement arising from acceptance of the offer, is personal and may only be accepted by the recipient. If a recipient on-sells their securities within 12 months of their issue, that person will be required to lodge a disclosure document with ASIC unless either:
• | the sale is pursuant to an offer received outside Australia or is made to a “sophisticated investor” within the meaning of 708(8) of the Act or a “professional investor” within the meaning of section 708(11) of the Act; or |
• | it can be established that our company issued, and the recipient subscribed for, the securities without the purpose of the recipient on-selling them or granting, issuing or transferring interests in, or options or warrants over them. |
Hong Kong
Our securities may not be offered or sold in Hong Kong, by means of any document, other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made under that Ordinance or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32, Laws of Hong Kong) or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to our securities may be issued, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to our securities which are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) or any rules made under that Ordinance. The contents of this document have not been reviewed by any regulatory authority in Hong Kong. You are advised to exercise caution in relation to the offer. If you are in any doubt about any of the contents of this prospectus, you should obtain independent professional advice.
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India
This prospectus has not been and will not be registered as a prospectus with the Registrar of Companies in India. This prospectus or any other material relating to these securities may not be circulated or distributed, directly or indirectly, to the public or any members of the public in India. Further, persons into whose possession this prospectus comes are required to inform themselves about and to observe any such restrictions. Each prospective investor is advised to consult its advisors about the particular consequences to it of an investment in these securities. Each prospective investor is also advised that any investment in these securities by it is subject to the regulations prescribed by the Reserve Bank of India and the Foreign Exchange Management Act and any regulations framed thereunder.
Japan
Our securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948 as amended, the FIEL), and we will not offer or sell any of our securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exception from the registration requirements of, and otherwise in compliance with, the FIEL and any other applicable laws, regulations and ministerial guidelines of Japan.
People’s Republic of China
This prospectus may not be circulated or distributed in the PRC and our securities may not be offered or sold, and we will not offer or sell to any person for re-offering or resale directly or indirectly to any resident of the PRC, except pursuant to applicable laws and regulations of the PRC. For the purpose of this paragraph, PRC does not include Taiwan and the special administrative regions of Hong Kong and Macau.
Singapore
This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of our securities may not be circulated or distributed, nor may our securities be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Future Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.
Where our securities are subscribed and purchased under Section 275 by a relevant person which is (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole whole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable in six months after that corporation or that trust has acquired our securities under Section 275 except (i) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA; (ii) where no consideration is given for transfer; or (iii) by operation of law.
Korea
Our securities may not be offered, sold and delivered directly or indirectly, or offered or sold to any person for reoffering or resale, directly or indirectly, in Korea or to any resident of Korea except pursuant to the applicable laws and regulations of Korea, including the Securities and Exchange Act and the Foreign Exchange
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Transaction Law and the decrees and regulations thereunder. Our securities have not been registered with the Financial Supervisory Commission of Korea for public offering in Korea. Furthermore, our securities may not be resold to Korean residents unless the purchaser of our securities complies with all applicable regulatory requirements (including but not limited to government approval requirements under the Foreign Exchange Transaction Law and its subordinate decrees and regulations) in connection with the purchase of our securities.
Public Offer Selling Restrictions Under the Prospectus Directive
In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:
• | to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities; |
• | to any legal entity that has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; |
• | to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives; or |
• | in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive; |
provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.
For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.
We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.
Selling Restrictions Addressing Additional United Kingdom Securities Laws
This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant persons should not act or rely on this document or any of its contents.
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The validity of the shares of common stock offered by this prospectus and certain other legal matters in connection with this offering will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed on for certain of the selling stockholders by Vinson & Elkins LLP. Certain legal matters in connection with this offering will be passed on for certain of the selling stockholders by Latham & Watkins LLP, Washington, D.C. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
The audited financial statements included in this prospectus and registration statement have been audited by UHY LLP, independent registered public accountants, as indicated in their reports with respect thereto. Such financial statements have been so included in reliance on the reports of such independent accountants given upon the authority of said firm as experts in auditing and accounting.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 regarding the common stock. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common stock offered in this prospectus, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates or from the SEC’s website on the Internet athttp://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. In addition, our future public filings can also be inspected and copied at the offices of The NASDAQ Stock Market LLC, Reports Section, 1735 K Street, N.W., Washington, D.C. 2006.
You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.
Following the completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located athttp://www.stallionoilfield.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: 950 Corbindale, Suite 300 Houston, Texas 77024, Attention: Chief Financial Officer, (713) 528-5544.
We intend to furnish or make available to our stockholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.
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F-1
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Stallion Oilfield Services, Inc.
Houston, Texas
We have audited the accompanying balance sheet of Stallion Oilfield Services, Inc. (“Stallion”) as of May 29, 2008. This financial statement is the responsibility of Stallion’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Stallion as of May 29, 2008 in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
May 30, 2008
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STALLION OILFIELD SERVICES, INC.
May 29, 2008 | |||
(in thousands) | |||
Assets | |||
Current assets | |||
Cash and cash equivalents | $ | 1 | |
Total current assets | 1 | ||
Total assets | $ | 1 | |
Liabilities and stockholders’ equity | |||
Liabilities | $ | — | |
Commitments and contingencies | — | ||
Stockholders’ equity | |||
Common stock, voting, par value $.01 per share, 1,000 shares authorized, 1,000 shares issued | — | ||
Additional paid-in capital | 1 | ||
Retained earnings | — | ||
Total stockholders’ equity | 1 | ||
Total liabilities and stockholders’ equity | $ | 1 | |
The accompanying notes are an integral part of this balance sheet.
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STALLION OILFIELD SERVICES, INC.
1. Organization
Stallion Oilfield Services, Inc. (“Stallion”) was formed as a Delaware corporation on June 27, 2006. The corporation was formed for the purpose of becoming a holding company for Stallion Oilfield Services Ltd. (“Stallion Oilfield”) in connection with a proposed initial public offering of Stallion’s common stock. Stallion and the partners of Stallion Oilfield have entered into a contribution agreement which, if consummated, would result in the partners of Stallion Oilfield contributing their respective partnership interests to Stallion in exchange for shares of common stock of Stallion.
Stallion Oilfield provides a wide range of wellsite support services and production and logistics services to drilling contractors and oil and gas exploration and production companies, including workforce accommodation units, surface equipment rental, solids control services and equipment, communications infrastructure, production and logistics services in the drilling regions in the United States, including the Gulf Coast, South Texas, ArkLaTex, North Texas, the Mid-Continent, Permian Basin, Rocky Mountain Regions, Prudhoe Bay, Alaska, offshore Texas and Louisiana Gulf Coast and in international waters. Stallion is headquartered in Houston, Texas.
2. Summary of Significant Accounting Policies
Basis of Presentation
The balance sheet is prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).
Cash and Cash Equivalents
All cash equivalents are stated at cost, which approximates market. Stallion considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Partners of
Stallion Oilfield Services Ltd. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Stallion Oilfield Services Ltd. and subsidiaries as of December 31, 2006 and 2007, and the related consolidated statements of operations, changes in partners’ capital and cash flows for each of the three years ended December 31, 2007. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The Partnership is not required to have nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Stallion Oilfield Services Ltd. and subsidiaries as of December 31, 2006 and 2007, and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
March 10, 2008
F-6
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, | ||||||
2006 | 2007 | |||||
(in thousands) | ||||||
Assets | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | 4,100 | $ | 9,850 | ||
Accounts receivable, net | 67,777 | 116,800 | ||||
Costs and estimated earnings in excess of billings on uncompleted contracts | 1,741 | 1,611 | ||||
Inventory | 457 | 3,709 | ||||
Prepaid expenses | 6,980 | 9,128 | ||||
Deferred tax assets, net | 29 | 595 | ||||
Total current assets | 81,084 | 141,693 | ||||
Property, plant and equipment | 220,777 | 433,355 | ||||
Notes receivable—officers | 10,000 | — | ||||
Goodwill | 110,410 | 296,566 | ||||
Intangible and other assets, net | 24,636 | 104,268 | ||||
Total assets | $ | 446,907 | $ | 975,882 | ||
Liabilities and partners’ capital | ||||||
Current liabilities | ||||||
Accounts payable—trade | $ | 12,462 | $ | 30,609 | ||
Distribution payable | 1,800 | 476 | ||||
Accrued expenses | 11,342 | 43,330 | ||||
Current portion of long-term debt and notes payable | 1,913 | 2,235 | ||||
Current portion of obligations under capital leases | 127 | 86 | ||||
Total current liabilities | 27,644 | 76,736 | ||||
Long-term debt and notes payable, net of current portion | 255,316 | 722,316 | ||||
Obligations under capital leases, net of current portion | 183 | 95 | ||||
Asset retirement obligations | — | 604 | ||||
Deferred rent | — | 2,201 | ||||
Deferred tax liabilities | 10,230 | 23,581 | ||||
Total liabilities | 293,373 | 825,533 | ||||
Commitments and contingencies | — | — | ||||
Partners’ capital | 153,534 | 150,349 | ||||
Total liabilities and partners’ capital | $ | 446,907 | $ | 975,882 | ||
See notes to consolidated financial statements.
F-7
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | ||||||||||||
2005 | 2006 | 2007 | ||||||||||
(in thousands) | ||||||||||||
Service revenue | $ | 73,126 | $ | 240,410 | $ | 427,195 | ||||||
Operating expenses | ||||||||||||
Cost of services | 42,281 | 140,708 | 269,555 | |||||||||
Selling, general and administrative expenses | 9,883 | 19,170 | 40,027 | |||||||||
Depreciation and amortization | 7,798 | 30,068 | 62,743 | |||||||||
Loss on disposal of property, plant and equipment | 499 | 920 | 44 | |||||||||
Total operating expenses | 60,461 | 190,866 | 372,369 | |||||||||
Income from operations | 12,665 | 49,544 | 54,826 | |||||||||
Other income (expense) | ||||||||||||
Interest expense | (4,565 | ) | (18,919 | ) | (52,874 | ) | ||||||
Other | (66 | ) | 71 | 207 | ||||||||
Total other income (expense) | (4,631 | ) | (18,848 | ) | (52,667 | ) | ||||||
Income before income taxes | 8,034 | 30,696 | 2,159 | |||||||||
Provision for income taxes | 598 | 4,927 | 6,410 | |||||||||
Net income (loss) | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | |||||
See notes to consolidated financial statements.
F-8
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
General Partner | Limited Partner | Total | ||||||||||
(in thousands) | ||||||||||||
Balances as of January 1, 2005 | $ | 34 | $ | 3,577 | $ | 3,611 | ||||||
Contributions, net of issuance costs | — | 32,406 | 32,406 | |||||||||
Distributions | — | (786 | ) | (786 | ) | |||||||
Conversion of notes payable into limited partner interest | — | 500 | 500 | |||||||||
Limited partner interest issued in connection with note payable | — | 430 | 430 | |||||||||
Net income | 1 | 7,435 | 7,436 | |||||||||
Balances as of December 31, 2005 | 35 | 43,562 | 43,597 | |||||||||
Contributions, net of issuance costs | — | 63,282 | 63,282 | |||||||||
Conversion of notes payable into limited partner interest | — | 250 | 250 | |||||||||
Limited partner interest issued in connection with note payable | — | 22,950 | 22,950 | |||||||||
Distributions | — | (2,314 | ) | (2,314 | ) | |||||||
Net income | 3 | 25,766 | 25,769 | |||||||||
Balances as of December 31, 2006 | 38 | 153,496 | 153,534 | |||||||||
Contributions | — | 1,323 | 1,323 | |||||||||
Distributions | — | (257 | ) | (257 | ) | |||||||
Net loss | (1 | ) | (4,250 | ) | (4,251 | ) | ||||||
Balances as of December 31, 2007 | $ | 37 | $ | 150,312 | $ | 150,349 | ||||||
See notes to consolidated financial statements.
F-9
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||||||
2005 | 2006 | 2007 | ||||||||||
(in thousands) | ||||||||||||
Cash flows from operating activities | ||||||||||||
Net income (loss) | $ | 7,436 | $ | 25,769 | $ | (4,251 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 7,798 | 30,068 | 62,743 | |||||||||
Amortization of debt issuance costs | 423 | 2,069 | 7,180 | |||||||||
Amortization of discount | 72 | 358 | 417 | |||||||||
Accretion of asset retirement obligations | — | — | 11 | |||||||||
Interest income on notes receivable—officers | — | — | (181 | ) | ||||||||
Loss on disposal of property, plant and equipment | 499 | 920 | 44 | |||||||||
Deferred tax expense (benefit) | (73 | ) | 1,776 | 1,067 | ||||||||
Bad debt expense | 465 | 683 | 3,184 | |||||||||
Other | — | 19 | — | |||||||||
Change in operating assets and liabilities: | ||||||||||||
Accounts receivable | (13,709 | ) | (22,825 | ) | (35,693 | ) | ||||||
Costs and estimated earnings in excess of billings on uncompleted contracts | — | 2,015 | 130 | |||||||||
Inventory | — | (457 | ) | (3,252 | ) | |||||||
Prepaid expenses and other assets | (209 | ) | (5,041 | ) | 1,135 | |||||||
Accounts payable—trade | 1,368 | 2,673 | 29,543 | |||||||||
Accrued expenses | 3,017 | 3,097 | (3,813 | ) | ||||||||
Net cash provided by operating activities | 7,087 | 41,124 | 58,264 | |||||||||
Cash flows from investing activities | ||||||||||||
Cash paid for acquisitions, net of cash received | (47,191 | ) | (178,045 | ) | (388,091 | ) | ||||||
Cash paid for acquisition costs | (433 | ) | (1,399 | ) | (3,204 | ) | ||||||
Cash paid for property, plant and equipment | (35,951 | ) | (92,029 | ) | (122,291 | ) | ||||||
Proceeds received from disposal of property, plant and equipment | 113 | 1,309 | 6,801 | |||||||||
(Increase) decrease of notes receivable—officers | — | (10,000 | ) | 10,000 | ||||||||
Net cash used in investing activities | (83,462 | ) | (280,164 | ) | (496,785 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Partners’ capital contributions, net | 32,406 | 63,282 | — | |||||||||
Distributions to partners | — | (514 | ) | (257 | ) | |||||||
Proceeds from long-term debt | 64,133 | 216,000 | 625,000 | |||||||||
Payments of long-term debt | (21,454 | ) | (68,095 | ) | (210,828 | ) | ||||||
Proceeds from line of credit, net | 4,200 | 38,400 | 53,150 | |||||||||
Payments for debt issuance costs | (1,545 | ) | (6,464 | ) | (17,665 | ) | ||||||
Payments for debt discount | — | — | (5,000 | ) | ||||||||
Payments on obligations under capital leases | (433 | ) | (451 | ) | (129 | ) | ||||||
Net cash provided by financing activities | 77,307 | 242,158 | 444,271 | |||||||||
Net increase in cash and cash equivalents | 932 | 3,118 | 5,750 | |||||||||
Cash and cash equivalents, beginning of year | 50 | 982 | 4,100 | |||||||||
Cash and cash equivalents, end of year | $ | 982 | $ | 4,100 | $ | 9,850 | ||||||
See notes to consolidated financial statements.
F-10
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2006 AND 2007
NOTE 1—NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business: Stallion Oilfield Services Ltd. and subsidiaries (collectively, the “Partnership” or “Stallion”) provide a wide range of wellsite support services and production and logistics services to drilling contractors and oil and gas exploration and production companies, including workforce accommodation units, surface equipment rental, solids control services and equipment, communications infrastructure, production and logistics services in the drilling regions in the United States, including the Gulf Coast, South Texas, ArkLaTex, North Texas, the Mid-Continent, Permian Basin, Rocky Mountain Regions, Prudhoe Bay, Alaska, offshore Texas and Louisiana Gulf Coast and in international waters. Stallion is headquartered in Houston, Texas. Stallion is a limited partnership with Stallion Oilfield Holdings, Ltd. as the 99.99% limited partner and Stallion Interests, LLC as the 0.01% general partner of the Partnership.
Principles of Consolidation: The consolidated financial statements include the financial statements of Stallion Oilfield Services Ltd. and its wholly owned subsidiaries. Stallion has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46 or Accounting Research Bulletin No. 51. All significant inter-company balances and transactions have been eliminated in consolidation.
Cash and Cash Equivalents: The Partnership considers all investments with original maturities of three months or less when purchased to be cash equivalents.
In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 95, “Statement of Cash Flows”, revaluations of acquired assets under purchase accounting are recognized as non-cash activities. As a result, amounts related to changes in assets and liabilities reported in the consolidated statements of cash flows will not necessarily agree to changes in the corresponding balances on the consolidated balance sheets.
Fair Value of Financial Instruments: The carrying values of cash and cash equivalents, accounts receivable, accounts payable—trade and accrued expenses approximate fair value due to the short maturity of these instruments. The carrying value of all debt approximates fair value because Stallion’s current borrowing rate is based on a variable market rate of interest, except our 9.75% Senior Notes which were issued in January 2007. As of December 31, 2007, the fair value of these notes was $273.4 million compared to a carrying amount of $300.0 million.
Accounts Receivable: The Partnership extends credit to its customers based on an evaluation of the customer’s financial condition and generally collateral is not required nor is interest charged on outstanding balances. Outstanding accounts receivable are routinely evaluated and an allowance is set up when accounts are deemed uncollectible. The allowance for doubtful accounts is based on an analysis of historical collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial position of significant customers and (2) a decline in oil and natural gas prices that could affect the entire customer base.
Unbilled Accounts Receivable: Unbilled receivables represent revenue earned related to rental agreements and certain construction contracts in the current period but not yet billed to the customer.
Inventory: Inventory is stated at the lower of cost or market. Raw materials are generally determined using the first-in first-out (“FIFO”) method. Work-in-process is stated at actual production cost, including direct labor and materials.
F-11
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
Property, Plant and Equipment: Property, plant and equipment are stated at cost. Depreciation is provided on the straight line method over the estimated useful lives of the related assets. Depletion of our rock and gravel deposits is provided based upon units of production and estimated recoverable reserves. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred. Leasehold improvements are amortized over the shorter of the life of the lease or the life of the improvement.
Asset Retirement Obligations: We account for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, pursuant to which we record the fair value of an asset retirement obligation as a liability in the period in which a legal obligation is incurred associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. Furthermore, we record a corresponding asset which is depreciated over the estimated life of the underlying asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.
We own and operate 11 salt water disposal sites each of which is subject to certain rules and regulations regarding usage and ultimate closure. The following table reflects changes in the liability during the year ended December 31, 2007 (in thousands):
Balance as of January 1, 2007 | $ | — | ||
Incurred during the year | 151 | |||
Recognized through acquisitions | 988 | |||
Revisions in estimated cash flows | (546 | ) | ||
Accretion expense | 11 | |||
Balance as of December 31, 2007 | $ | 604 | ||
Debt Issuance Costs: Certain costs such as lender’s fees and related attorney’s fees incurred in connection with obtaining financing are capitalized. These costs are amortized to interest expense using the straight line method, which approximates the effective interest method over the terms of the related debt.
Intangible Assets: For financial statement purposes, identifiable intangible assets with a defined life are being amortized using the straight line method over the useful lives of the assets. Identifiable intangible assets with an indefinite life are not amortized in accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”. These assets are tested at least annually for impairment.
Goodwill: Goodwill represents the excess of costs over the fair value of net assets of acquired businesses. Goodwill acquired in a business combination is not amortized, but instead tested for impairment at least annually in the fourth quarter. Under this goodwill impairment test, if the fair value of a reporting unit does not exceed its carrying value, the excess of fair value of the reporting unit over the fair value of its net assets is considered to be the implied fair value of goodwill. If the carrying value of goodwill exceeds its implied fair value, the difference is recognized as an impairment loss. Goodwill was evaluated for impairment as of December 31, 2006 and 2007. We determined that goodwill was not impaired, and thus no impairment charge has been recorded related to goodwill through December 31, 2007.
Impairment: In accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, long-lived assets, such as property, plant and equipment, and
F-12
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used in operations is measured by a comparison of the carrying amount of an asset to estimated undiscounted cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of their carrying amount or their fair value less anticipated costs to sell, and they would no longer be depreciated. No impairment losses have been recorded through December 31, 2007.
Self-Insured Risk Accruals: The Partnership is partially self-insured for certain losses relating to workers’ compensation, auto and general liability insurance claims. The Partnership maintains accruals to cover the self-insured risks, which are based on third-party data and historical claims history.
Income Taxes: The Partnership is not subject to federal income taxes on a consolidated basis due to its partnership structure; however, certain of its subsidiary companies are taxable corporations and are subject to federal income tax. The Partnership accounts for income taxes based upon Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) for its subsidiaries which are subject to income taxes. Under SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.
Effective January 1, 2007, we became subject to the Texas Margin Tax which is considered a state income tax expense.
Revenue Recognition: The Partnership’s revenue recognition policies are as follows:
Rental, Service and Sales Revenue
The Partnership recognizes revenue when it is realized and earned. The Partnership considers revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or is determinable and collection is reasonably assured. Delivery is not considered to have occurred until the customer takes title and assumes the risks and rewards of ownership, which is generally on the date of shipment. Revenue from rental agreements is recognized over the rental period and revenue from service agreements is recognized when services have been rendered. Generally services are provided over a relatively short time.
Construction Revenue
Certain of our operations recognize revenue related to wellsite construction and offshore workforce accommodations unit construction using the percentage-of-completion method determined by the ratio of costs incurred to total estimated costs at completion. All known or anticipated losses on contracts are recognized in full when such losses become apparent. Contracts typically range from two to six months in duration.
F-13
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
Advertising: The Partnership’s policy is to expense advertising costs as incurred. Advertising costs totaled approximately $0.4 million, $0.9 million and $0.8 million for the years ended December 31, 2005, 2006 and 2007, respectively.
Concentration of Risk: During 2006 and 2007, the Partnership had cash in excess of federally insured limits deposited in a bank. The Partnership monitors the financial condition of the bank and has experienced no losses associated with its accounts.
The Partnership’s customer base consists primarily of oil and natural gas exploration and production companies and drilling contractors. The Partnership performs ongoing evaluations of its customers but generally does not require collateral on its trade receivables. During the years ended December 31, 2005 and 2007, no customer accounted for more than 10% of revenue. During the year ended December 31, 2006, one customer accounted for 10.5% of revenue. The balance due from this customer as of December 31, 2006 was approximately $6.6 million.
Partnership Allocations: Income or loss is allocated to the partners in accordance with the Partnership Agreement.
Contribution Agreement: In December 2006, Stallion Oilfield Holdings, Ltd., our parent, entered into a Contribution Agreement with Carlyle/Riverstone wherein Carlyle/Riverstone agreed to invest up to $125.0 million in Class A partnership units. This investment arrangement expires in December 2008 and purchases of Class A units are subject to various conditions including approval of the board of the general partner of Stallion Oilfield Holdings, Ltd. As of December 31, 2007, Carlyle/Riverstone had funded $45.0 million under the Contribution Agreement.
Stock-Based Compensation: We have adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” which requires that we measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of those instruments on their grant date. The fair value of these instruments must be re-evaluated at each reporting date through the settlement date with changes in fair value recognized as compensation expense of the period. Accounting principles generally accepted in the United States of America (“GAAP”) permits the use of various models to determine the fair value of restricted partnership units and the variables used for the model are subjective. We have estimated the value of restricted partnership units in accordance with conventional valuation techniques including but not limited to net book value and comparable company multiples of earnings before interest, tax, depreciation and amortization (“EBITDA”) as applicable. The use of different assumptions or a different model may have a material impact on our results of operations and related disclosures. Historically, we granted to employees restricted units representing limited partnership units in Stallion Value, L.P., a limited partner of Stallion Oilfield Holdings, Ltd. In the years ended December 31, 2005, 2006 and 2007, compensation expense from restricted partnership units was insignificant based on management’s valuation at the time of grant.
Use of Estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:
• | Depreciation and amortization of property, plant and equipment and intangible assets, |
• | Impairment of property, plant and equipment, intangibles and goodwill, |
F-14
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
• | Allowance for doubtful accounts, |
• | Revenue recognition on uncompleted contracts, |
• | Litigation and self-insured risk reserves, |
• | Fair value of assets acquired and liabilities assumed, |
• | Stock-based compensation, and |
• | Income taxes. |
The Partnership analyzes its estimates based on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially from those previously estimated. Many of the conditions impacting these assumptions are outside of Stallion’s control.
Reclassifications: Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations or partners’ capital.
F-15
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 2—ACQUISITIONS
During the years ended December 31, 2005, 2006, and 2007, Stallion acquired either substantially all of the assets or all of the outstanding capital stock or partnership interest of the following businesses, each of which was accounted for using the purchase method of accounting (in thousands):
Acquisition Date | Total Cash Paid (Net of Cash Acquired) | ||||
Stallion Rentals, L.P. * | January 2005 | $ | 2,925 | ||
Double-D Enterprises, Inc. * | January 2005 | 4,686 | |||
Envirotech, Inc. * | January 2005 | 11,208 | |||
Separation Services, Inc. | January 2005 | 7,356 | |||
Bob’s Equipment Rental, Inc. | June 2005 | 9,312 | |||
GL Trucking & Rental, Inc. * | September 2005 | 11,704 | |||
Total 2005 | $ | 47,191 | |||
Trail Blazer Hot Shot, Inc. * | January 2006 | $ | 13,735 | ||
Pioneer RSC, LP | February 2006 | 2,817 | |||
BLR Construction Companies, L.L.C. * | March 2006 | 46,124 | |||
Rental One, LLC | March 2006 | 3,781 | |||
Oilfield Heavy Haulers, LLC | March 2006 | 10,710 | |||
Bowie Dozer Services, Inc. | May 2006 | 10,952 | |||
R&G Crane & Rigging & Trucking, LLC | July 2006 | 5,032 | |||
Abbeville Offshore Quarters, Inc. * | August 2006 | 46,118 | |||
G&N Rentals | September 2006 | 6,400 | |||
Erlandson Construction Company | November 2006 | 5,482 | |||
Norton Transport, Inc. | December 2006 | 26,894 | |||
Total 2006 | $ | 178,045 | |||
Suttee Enterprises | February 2007 | $ | 2,241 | ||
La Mission Rentals | February 2007 | 8,100 | |||
The Waterline Company, LLC | March 2007 | 12,717 | |||
Shores Energy, Inc. | April 2007 | 29,032 | |||
L.E.G. Rentals, Inc. and Fluid Processors, Inc. * | May 2007 | 19,733 | |||
Central Holdings, Inc. | June 2007 | 9,108 | |||
Burns Services, LLC | June 2007 | 792 | |||
Rowan Alaska Camps | June 2007 | 14,400 | |||
Patriot Liquid Services, L.P. | July 2007 | 35,897 | |||
Bayou Tank Services, Ltd. | July 2007 | 80,655 | |||
Salty’s Group * | August 2007 | 157,910 | |||
Twin B Enterprises | September 2007 | 3,200 | |||
A&B Construction | October 2007 | 9,088 | |||
Purchase price adjustments for 2006 acquisitions | 5,218 | ||||
Total 2007 | $ | 388,091 | |||
* | Considered individually significant under SEC Regulations S-X, 1-02 and 3-05. |
F-16
Table of Contents
Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the dates of acquisition (in thousands):
2005 | 2006 | 2007 | |||||||
Assets acquired: | |||||||||
Cash and cash equivalents | $ | 568 | $ | 1,456 | $ | 6,728 | |||
Accounts receivable | 5,222 | 26,901 | 16,335 | ||||||
Other current assets | 478 | 1,506 | 3,282 | ||||||
Deferred tax assets | — | 164 | 25 | ||||||
Property, plant and equipment | 32,139 | 82,811 | 144,916 | ||||||
Goodwill and other intangibles | 16,720 | 108,554 | 244,477 | ||||||
Total assets acquired | 55,127 | 221,392 | 415,763 | ||||||
Liabilities assumed: | |||||||||
Accounts payable | 1,306 | 5,545 | 7,510 | ||||||
Accrued expenses | 768 | 1,856 | 2,936 | ||||||
Deferred tax liability | 1,489 | 7,394 | 939 | ||||||
Other liabilities | — | — | 7,190 | ||||||
Asset retirement obligations | — | — | 988 | ||||||
Notes payable | 169 | — | — | ||||||
Total liabilities assumed | 3,732 | 14,795 | 19,563 | ||||||
Net assets acquired | $ | 51,395 | $ | 206,597 | $ | 396,200 | |||
2005 Acquisitions
During the year ended December 31, 2005, we acquired substantially all of the assets of six oilfield services companies. The combined purchase price was approximately $51.4 million, of which $47.2 million was cash, net of cash acquired, resulting in goodwill and other intangibles of approximately $16.7 million. These six acquisitions include the following significant transactions:
Stallion Rentals, L.P., Formerly Known as Trinity Valley Rentals, Inc. (“Stallion Rentals”)—We acquired the net assets of Stallion Rentals, which was engaged in the rental of forklifts, manlifts, generators, light towers and other surface equipment to the drilling industry. Stallion Rentals was acquired for a total purchase price of $3.4 million, consisting of $2.9 million in cash and $0.5 million in convertible notes payable to seller. The seller notes are convertible into Class C units of Stallion Holdings. In April 2005, the convertible notes payable to seller were converted into 500,000 Class C units of Stallion Holdings.
Double-D Enterprises, Inc. (“Double-D”)—We acquired the net assets of Double-D, a company engaged in the rental of loaders, manlifts, mud vacs and other related equipment to the drilling industry, specifically located in the Rocky Mountain region. Double-D was acquired for a total purchase price of $5.2 million, consisting of $4.7 million in cash and $0.5 million in a convertible note payable to seller. The convertible note payable to seller was paid in full in January 2006.
Envirotech, Inc. (“Envirotech”)—We acquired the net assets of Envirotech, a company engaged in the rental of workforce accommodations, water systems, sewer systems and other related equipment to the drilling industry, specifically in the Rocky Mountain region. Envirotech was acquired for a total purchase price of $11.7 million, consisting of $11.2 million in cash and $0.5 million in convertible notes payable to seller. This note was paid in full in January 2006.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
Separation Services, Inc. (“SSI”)—We purchased the stock of SSI, a company engaged in the rental of solids control equipment to oil and gas companies and operators at drilling locations in order to separate drill cuttings from the drilling fluids. SSI was acquired for a total purchase price of $9.1 million, consisting of $7.4 million in cash net of cash acquired of approximately $0.6 million, $0.7 million in deferred compensation, approximately 352,000 Class D units of Stallion Holdings Ltd. and a $0.5 million convertible note payable to seller. In August 2007, we changed the name of SSI to Stallion Solids Control, Inc.
GL Trucking & Rental, Inc. (“GL”)—We acquired the assets of GL, located in Williston, North Dakota, for total consideration of $12.7 million, consisting of $11.7 million in cash and a $1.0 million note payable to seller. GL is a leading provider of integrated drilling support services for the Williston Basin and surrounding areas. GL assets included over 100 workforce accommodation units, significant oilfield equipment hauling capacity, loaders and equipment setting cranes.
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the dates of acquisition of the businesses acquired all of which were included in our wellsite support services segment in 2005 (in thousands):
Stallion Rentals | Double-D and Envirotech | SSI | GL | Other | Total | |||||||||||||
Assets acquired: | ||||||||||||||||||
Cash and cash equivalents | $ | — | $ | — | $ | 568 | $ | — | $ | — | $ | 568 | ||||||
Accounts receivable | 1,019 | 1,559 | 2,644 | — | — | 5,222 | ||||||||||||
Other current assets | 54 | — | 424 | — | — | 478 | ||||||||||||
Property, plant and equipment | 2,581 | 9,347 | 2,075 | 8,824 | 9,312 | 32,139 | ||||||||||||
Goodwill and other intangibles | 512 | 6,103 | 6,225 | 3,880 | — | 16,720 | ||||||||||||
Total assets acquired | 4,166 | 17,009 | 11,936 | 12,704 | 9,312 | 55,127 | ||||||||||||
Liabilities assumed: | ||||||||||||||||||
Accounts payable | 622 | — | 684 | — | — | 1,306 | ||||||||||||
Accrued expenses | 118 | — | 650 | — | — | 768 | ||||||||||||
Deferred tax liability | — | — | 1,489 | — | — | 1,489 | ||||||||||||
Notes payable | — | 140 | 29 | — | — | 169 | ||||||||||||
Total liabilities assumed | 740 | 140 | 2,852 | — | — | 3,732 | ||||||||||||
Net assets acquired | $ | 3,426 | $ | 16,869 | $ | 9,084 | $ | 12,704 | $ | 9,312 | $ | 51,395 | ||||||
2006 Acquisitions
During the year ended December 31, 2006, we acquired substantially all of the assets of 11 oilfield services companies having a combined purchase price of $206.6 million, of which $178.0 million was cash, net of cash acquired, resulting in goodwill and other intangibles of approximately $108.6 million. These 11 acquisitions include the following significant transactions:
Trail Blazer Hot Shot, Inc. (“TB”)—We acquired certain of the assets of TB for total consideration of approximately $14.6 million, which consisted of approximately $13.7 million in cash and $0.9 million in a note payable to the seller. TB is a provider of surface equipment rental services for the major Oklahoma basins and
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
surrounding areas. Assets include forklifts and man lifts, generators, and a variety of other surface rental equipment such as pumps and heavy-duty service trucks.
BLR Construction Companies, L.L.C. (“BLR”)—We acquired 100% of the membership interest of BLR for approximately $48.5 million in total consideration, consisting of $46.1 million in cash, net of cash acquired of $0.3 million, and $2.0 million in notes payable to the sellers. In August 2007, we changed the name of BLR to Stallion Oilfield Construction, LLC (“Stallion Construction”). Stallion Construction is a full-service contractor serving the oil, gas and petro-chemical industry since 1990. Stallion Construction provides customers with experienced personnel and equipment, specializing in location construction, pipeline construction, marine services, production facility construction, crew services, heavy equipment and trucking services, solids control, remediation services, plugging and abandonment, and weed and vegetation control through its inventory of bulldozers, mats, tools and other construction-related equipment. Stallion Construction also provides inland marine wellsite construction services through a fleet of crew boats, tugboats and barges.
Abbeville Offshore Quarters, Inc. (“AOQ”)—We purchased all of the outstanding capital stock of AOQ. In August 2007, we changed the name of AOQ to Stallion Offshore Quarters, Inc (“SOQ”). SOQ provides workforce accommodations, sewage treatment units, water tanks, generators and other rental support equipment for use in the offshore Gulf Coast oil and natural gas industry. The purchase price consisted of $46.1 million in cash ($1.5 million of which is held in escrow) and 6,943,000 Class C units representing limited partnership interests of Stallion Holdings for a total consideration of $70.2 million. The acquisition of SOQ augmented the Partnership’s workforce accommodations and surface equipment rental service lines. During 2007, in accordance with the purchase agreement, we finalized the working capital settlement which resulted in additional cash consideration (and therefore goodwill) to former owners of SOQ of $5.2 million.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The following tables summarize the estimated fair value of the assets acquired and liabilities assumed at the dates of acquisition of the businesses acquired in 2006 by segment (in thousands):
TB | SOQ | All Others | Total Wellsite Support Services Segment | Stallion Construction | All Others | Total Production & Logistics Services Segment | Total | |||||||||||||||||
Assets acquired: | ||||||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 1,128 | $ | — | $ | 1,128 | $ | 328 | $ | — | $ | 328 | $ | 1,456 | ||||||||
Accounts receivable | — | 11,069 | — | 11,069 | 15,833 | — | 15,833 | 26,902 | ||||||||||||||||
Other current assets | — | 616 | — | 616 | 891 | — | 891 | 1,507 | ||||||||||||||||
Deferred tax assets | — | — | — | — | 164 | — | 164 | 164 | ||||||||||||||||
Property, plant and equipment | 5,208 | 21,500 | 9,444 | 36,152 | 14,205 | 32,453 | 46,658 | 82,810 | ||||||||||||||||
Goodwill and other intangibles | 9,427 | 43,839 | 3,795 | 57,061 | 23,873 | 27,619 | 51,492 | 108,553 | ||||||||||||||||
Total assets acquired | 14,635 | 78,152 | 13,239 | 106,026 | 55,294 | 60,072 | 115,366 | 221,392 | ||||||||||||||||
Liabilities assumed: | ||||||||||||||||||||||||
Accounts payable | — | 1,769 | — | 1,769 | 3,776 | — | 3,776 | 5,545 | ||||||||||||||||
Accrued expenses | — | 911 | — | 911 | 945 | — | 945 | 1,856 | ||||||||||||||||
Deferred tax liability | — | 5,274 | — | 5,274 | 2,120 | — | 2,120 | 7,394 | ||||||||||||||||
Total liabilities assumed | — | 7,954 | — | 7,954 | 6,841 | — | 6,841 | 14,795 | ||||||||||||||||
Net assets acquired | $ | 14,635 | $ | 70,198 | $ | 13,239 | $ | 98,072 | $ | 48,453 | $ | 60,072 | $ | 108,525 | $ | 206,597 | ||||||||
Additionally during the year ended December 31, 2007, we finalized the purchase accounting for two of the acquisitions that occurred in 2006 resulting in an additional reclassification to goodwill and other intangibles of approximately $10.6 million from other acquired assets and liabilities assumed.
2007 Acquisitions
During the year ended December 31, 2007, We acquired substantially all of the assets of 13 oilfield service companies for a combined purchase price of approximately $389.6 million, of which $382.9 million was cash, net of cash acquired, resulting in goodwill and other intangibles of approximately $244.5 million. These 13 acquisitions include the following significant transactions:
L.E.G. Rentals, Inc. and Fluid Processors, Inc. (“FPI”)—We acquired all of the outstanding capital stock of FPI located in Riverton, Wyoming, for a purchase price of $30.5 million, consisting of $26.0 million in cash and $4.5 million in escrow. This acquisition expanded Stallion’s solids control service business into the Rocky Mountain region.
Various Entities Operating under the Name of Salty’s (together “Salty’s”)—We acquired substantially all of the operating assets of Salty’s for total consideration of approximately $157.9 million cash, subject to certain
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
purchase price adjustments. Salty’s provides frac tank rentals and sales and saltwater hauling and disposal services in the Ft. Worth Basin and the ArkLaTex Region. Salty’s assets include vacuum trucks, frac tanks and saltwater injection wells.
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the dates of acquisition of our 2007 acquisitions (in thousands):
FPI | All Others | Total Wellsite Support Services Segment | Salty’s | All Others | Total Production & Logistics Services Segment | Total | |||||||||||||||
Assets acquired: | |||||||||||||||||||||
Cash and cash equivalents | $ | 6,294 | $ | — | $ | 6,294 | $ | — | $ | 434 | $ | 434 | $ | 6,728 | |||||||
Accounts receivable | 2,187 | — | 2,187 | 6,188 | 7,960 | 14,148 | 16,335 | ||||||||||||||
Other current assets | — | — | — | 3,212 | 70 | 3,282 | 3,282 | ||||||||||||||
Deferred tax assets | 7 | — | 7 | — | 18 | 18 | 25 | ||||||||||||||
Plant, property and equipment | 12,541 | 12,881 | 25,422 | 48,874 | 70,620 | 119,494 | 144,916 | ||||||||||||||
Goodwill and other intangibles | 11,646 | 12,653 | 24,299 | 112,601 | 107,577 | 220,178 | 244,477 | ||||||||||||||
Total assets acquired | 32,675 | 25,534 | 58,209 | 170,875 | 186,679 | 357,554 | 415,763 | ||||||||||||||
Liabilities assumed: | |||||||||||||||||||||
Accounts payable | 146 | — | 146 | 4,883 | 2,481 | 7,364 | 7,510 | ||||||||||||||
Accrued expenses | 1,606 | — | 1,606 | — | 1,330 | 1,330 | 2,936 | ||||||||||||||
Deferred tax liability | 397 | — | 397 | — | 542 | 542 | 939 | ||||||||||||||
Other liabilities | — | — | — | 7,190 | — | 7,190 | 7,190 | ||||||||||||||
Asset retirement obligations | — | — | — | 892 | 96 | 988 | 988 | ||||||||||||||
Total liabilities assumed | 2,149 | — | 2,149 | 12,965 | 4,449 | 17,414 | 19,563 | ||||||||||||||
Net assets acquired | $ | 30,526 | $ | 25,534 | $ | 56,060 | $ | 157,910 | $ | 182,230 | $ | 340,140 | $ | 396,200 | |||||||
Pro forma Effect of 2007 Acquisitions on Operations
Results of each of the acquired businesses are included in our accounts and consolidated results of operations from their respective dates of acquisition. No pro forma disclosure is provided for our other 2007 acquisitions as these acquisitions were not significant to our consolidated results of operations. The following table provides pro forma information related to our acquisitions of FPI and Salty’s assuming each of the acquisitions occurred on January 1, 2006 (in thousands):
Year Ended December 31, | |||||||
2006 | 2007 | ||||||
(Unaudited) | |||||||
Revenue | $ | 275,395 | $ | 473,019 | |||
Net income (loss) | $ | 10,989 | $ | (10,067 | ) |
To calculate the pro forma amounts for the years ended December 31, 2007 and 2006, the Partnership used the internal financial statements of FPI and Salty’s for the periods prior to acquisition.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The combined results of operations of the acquired businesses have been adjusted to reflect additional depreciation of fixed assets and amortization of intangible assets subject to amortization. The Partnership estimated the remaining useful lives and salvage values of all acquired assets and depreciated those assets over those useful lives using policies that were consistently applied.
Pro forma interest expense was calculated on notes payable to the sellers of acquired businesses and draws on the Partnership’s available line of credit at rates ranging from 6.25% to 8.60%, assuming the businesses were acquired on January 1, 2006.
Although we believe the accounting policies and procedures we used to prepare the pro forma results are reasonable, these pro forma results do not purport to be indicative of the actual results which would have been achieved had the acquisitions been consummated on January 1, of the respective year, and are not intended to be a projection of future results.
NOTE 3—PROPERTY, PLANT AND EQUIPMENT
Major classifications and estimated depreciable lives of property, plant and equipment are as follows (in thousands):
Estimated Life | December 31, | |||||||||
2006 | 2007 | |||||||||
Rental equipment | 3-20 years | $ | 140,583 | $ | 248,640 | |||||
Machinery and equipment | 5 years | 71,982 | 126,364 | |||||||
Auto and trucks | 1-5 years | 29,052 | 66,359 | |||||||
Saltwater disposal wells | 15 years | — | 30,185 | |||||||
Leasehold improvements | 3-5 years | 1,458 | 6,253 | |||||||
Office buildings | 4-15 years | 917 | 6,023 | |||||||
Computer equipment and software | 3-4 years | 1,785 | 3,046 | |||||||
Furniture and fixtures | 4 years | 939 | 2,308 | |||||||
Rock and gravel deposits | Units-of-Production | — | 2,071 | |||||||
Office equipment and furniture | 3-5 years | 475 | 1,144 | |||||||
247,191 | 492,393 | |||||||||
Less: accumulated depreciation, depletion and amortization | (34,728 | ) | (81,941 | ) | ||||||
212,463 | 410,452 | |||||||||
Assets not yet placed in service | 5,077 | 14,317 | ||||||||
Land | 843 | 4,574 | ||||||||
Construction in progress | 2,394 | 4,012 | ||||||||
Total property, plant and equipment | $ | 220,777 | $ | 433,355 | ||||||
Depreciation, depletion and amortization expense for the years ended December 31, 2005, 2006 and 2007 was approximately $7.2 million, $26.2 million and $50.6 million, respectively.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 4—INTANGIBLE AND OTHER ASSETS
Intangible and other assets are summarized as follows (in thousands):
December 31, | ||||||||
2006 | 2007 | |||||||
Intangible and other assets subject to amortization: | ||||||||
Customer lists | $ | 20,151 | $ | 87,158 | ||||
Debt issuance costs | 7,753 | 25,340 | ||||||
Non-compete agreements | 3,373 | 13,279 | ||||||
Debt discount | — | 5,000 | ||||||
Consulting agreement | 96 | — | ||||||
31,373 | 130,777 | |||||||
Less: accumulated amortization | (6,737 | ) | (26,509 | ) | ||||
Total intangible and other assets | $ | 24,636 | $ | 104,268 | ||||
Intangible assets subject to amortization have estimated future minimum interest and amortization expense as of December 31, 2007, for each of the next five years and in the aggregate is as follows:
Year Ending December 31, | Interest Expense | Amortization Expense | Total | ||||||
2008 | $ | 2,017 | $ | 17,814 | $ | 19,831 | |||
2009 | 2,017 | 17,239 | 19,256 | ||||||
2010 | 2,017 | 15,622 | 17,639 | ||||||
2011 | 2,017 | 11,634 | 13,651 | ||||||
2012 | 2,017 | 5,939 | 7,956 | ||||||
Thereafter | 11,014 | 14,921 | 25,935 | ||||||
$ | 21,099 | $ | 83,169 | $ | 104,268 | ||||
Amortization expense was approximately $0.6 million, $3.9 million and $12.6 million for the years ended December 31, 2005, 2006 and 2007, respectively. Amortization expense for debt issuance costs and debt discount was approximately $0.5 million, $2.4 million and $7.6 million for the years ended December 31, 2005, 2006 and 2007, respectively.
NOTE 5—DETAIL OF CERTAIN BALANCE SHEET ACCOUNTS
Accounts receivable consisted of the following (in thousands):
December 31, | ||||||||
2006 | 2007 | |||||||
Billed accounts receivable | $ | 64,338 | $ | 110,193 | ||||
Unbilled receivables | 4,073 | 11,554 | ||||||
Other receivables | 353 | 1,729 | ||||||
68,764 | 123,476 | |||||||
Less: allowance for doubtful accounts | (987 | ) | (6,676 | ) | ||||
Net trade receivables | $ | 67,777 | $ | 116,800 | ||||
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The components of inventory consisted of the following (in thousands):
December 31, | ||||||
2006 | 2007 | |||||
Raw materials | $ | 457 | $ | 2,900 | ||
Work in process | — | 369 | ||||
Finished goods | — | 440 | ||||
Total inventory | $ | 457 | $ | 3,709 | ||
Accrued expenses consisted of the following (in thousands):
December 31, | ||||||
2006 | 2007 | |||||
Accrued interest | $ | 949 | $ | 16,418 | ||
Accrual for purchase price adjustments | — | 7,846 | ||||
Accrued federal and state income taxes | 617 | 5,622 | ||||
Accrued payroll and payroll taxes | 3,322 | 4,156 | ||||
Accrued insurance | 617 | 3,462 | ||||
Accrued other taxes | 1,758 | 2,539 | ||||
Accrued bonuses | 1,363 | 1,186 | ||||
Other accrued expenses | 2,716 | 2,101 | ||||
Total accrued expenses | $ | 11,342 | $ | 43,330 | ||
NOTE 6—LONG-TERM DEBT AND NOTES PAYABLE
On June 12, 2007, the Partnership amended and restated its existing secured credit facility (as amended and restated, the “Credit Agreement”) with UBS AG, Stamford Branch as Issuing Bank, Administrative Agent and Collateral Agent (“UBS AG”) and certain other financial institutions. The Credit Agreement provides for a $75.0 million term loan (the “Term Loan Facility”) that will mature on June 12, 2013, and up to $175.0 million in borrowing capacity under a revolving credit facility (the “Revolving Credit Facility”) that will mature on March 1, 2011. Under the Term Loan Facility, payments of $0.8 million are required annually. The Credit Agreement also provides up to $30.0 million for the issuance of letters of credit. Any outstanding letters of credit reduce borrowing capacity under the Revolving Credit Facility.
Subject to certain limitations, the Partnership has the ability to elect how interest under the Credit Agreement will be computed. Interest under the Credit Agreement may be determined by reference to (1) the London Interbank Offered Rate (“LIBOR”) plus 2.0% or (2) the greater of (a) the base rate charged by UBS AG and (b) the Federal Funds Rate, plus 0.5%, plus an applicable margin between 1.75% and 2.25% depending on the credit rating of commitments under the Credit Agreement. If an event of default exists under the Credit Agreement, advances will bear interest at the then applicable rate plus 2.0%. Interest is payable quarterly in arrears for base rate loans and at the end of the applicable interest periods for LIBOR loans.
All of the Partnership’s obligations under the Credit Agreement are secured by first priority security interests on substantially all assets of the Partnership. Additionally, all of the Partnership’s domestic subsidiaries have guaranteed our obligations under the Credit Agreement.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The Credit Agreement contains various standard covenants that place limits on the operation of the Partnership. Some of these covenants require the Partnership and its subsidiaries, on a consolidated basis, to maintain specific ratios or conditions, with such ratios tested at the end of each fiscal quarter.
Under the Credit Agreement, the Partnership is permitted to prepay certain borrowings. In addition, the Credit Agreement requires the Partnership to make prepayments in certain situations.
If an event of default exists under the Credit Agreement, the lenders may accelerate the maturity of the obligations outstanding under the Credit Agreement and they may exercise other rights and remedies. While an event of default is continuing, advances will bear interest at the then applicable rate plus 2.0%. As of December 31, 2007, the Partnership was in compliance with all of its debt covenants.
On August 1, 2007, we entered into a $250.0 million Senior Unsecured Term Loan Credit Agreement (“New Term Loan”) with Credit Suisse, Cayman Islands Branch, as Administrative Agent, and certain other financial institutions. The New Term Loan provides for a $250.0 million senior unsecured term loan. Net proceeds from the New Term Loan were used to partially fund our production services acquisitions. The New Term Loan has a five year maturity and requires interest only payments until maturity.
The New Term Loan contains certain restrictive covenants applicable to us and our certain subsidiaries which are substantially similar to the covenants contained in our 9.75% Senior Notes.
The interest rate on the New Term Loan is as follows: the base rate plus 3.50% or LIBOR plus 4.50%; provided that (A) from and after May 1, 2008 until November 1, 2008, the interest rate shall be the base rate plus 4.25% or LIBOR plus 5.25%, and (B) from and after November 1, 2008 until February 1, 2009 the interest rate shall be base rate plus 5.00% or LIBOR plus 6.00%, and (C) from and after February 1, 2009 through August 1, 2012, the interest rate shall be the base rate plus 5.50% or LIBOR 6.50%.
For the years ended December 31, 2005, 2006 and 2007, our weighted average interest rate on our variable rate outstanding borrowings was approximately, 6.75%, 7.84% and 8.51%, respectively.
Senior Notes
In a private placement on January 19, 2007, Stallion issued $300.0 million of 9.75% Senior Notes due February 1, 2015 (“Senior Notes”). Proceeds from the sale of the Senior Notes were used to retire the outstanding balance on the $210.0 million Term B Loan (“Term B Loan”) and to pay down approximately $44.5 million under the revolving credit facility.
Interest payments on the Senior Notes are due semi-annually, on February 1 and August 1, commencing on August 1, 2007. The Senior Notes are non-convertible, unsecured and guaranteed by all the subsidiaries of the Partnership. In connection with the retirement of the Term B Loan on January 19, 2007, we expensed the remaining unamortized deferred debt issuance costs which amounted to approximately $4.8 million.
The Senior Notes are redeemable at the option of the Partnership on or after February 1, 2011 at the specified redemption price as described in the Indenture. The Senior Notes will be redeemable by the Partnership, in whole or in part, at any time prior to February 1, 2011 at a discount rate of the U.S. Treasury Rate for a specified period of time plus 50 basis points. Prior to February 1, 2010, Stallion may redeem up to 35% of the Senior Notes with the proceeds of certain equity offerings at a redemption price equal to 109.75% of the
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
principal amount of the Senior Notes, plus accrued and unpaid interest and liquidated damages, if any, to the date of redemption. This redemption must occur less than 90 days after the date of the closing of any such qualified equity offering.
Following a change of control, as defined in the Indenture, the Partnership will be required to make an offer to repurchase all or any portion of the 9.75% Senior Notes at a purchase price of 101.0% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the date of repurchase.
The Senior Notes contain certain covenants that limit the ability of the Partnership and certain subsidiaries to, among other things: incur additional debt, incur layered debt, consolidate or merge with or into other companies, consummate asset sales, make restricted payments, issue dividends, engage in transactions with affiliates, and issue additional note guarantees. The restrictive covenants are subject to a number of exceptions and qualifications set forth in the Indenture.
As part of the issuance of the above-mentioned Senior Notes, the Partnership incurred debt issuance costs of approximately $9.1 million, which is being amortized to interest expense using the straight line method, which approximates the effective interest method over the term of the Senior Notes.
Long-term debt and notes payable consists of the following (in thousands):
December 31, | ||||||||
2006 | 2007 | |||||||
Senior Notes | $ | — | $ | 300,000 | ||||
New Term Loan | — | 250,000 | ||||||
Term Loan Facility | — | 74,625 | ||||||
Revolving Credit Facility | — | 97,650 | ||||||
Term B Loan | 253,040 | — | ||||||
Notes payable to sellers of acquired businesses | 4,189 | 2,276 | ||||||
257,229 | 724,551 | |||||||
Less: current portion of long-term debt and notes payable | (1,913 | ) | (2,235 | ) | ||||
Total long-term debt and notes payable | $ | 255,316 | $ | 722,316 | ||||
Future maturities of long-term debt and notes payable are as follows:
Year Ending December 31, | |||
2008 | $ | 2,235 | |
2009 | 1,417 | ||
2010 | 874 | ||
2011 | 98,400 | ||
2012 | 250,750 | ||
Thereafter | 370,875 | ||
$ | 724,551 | ||
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 7—OPERATING LEASE COMMITMENTS
The Partnership leases equipment and office space from a related party (see Note 9) and various unrelated parties in various locations under non-cancelable operating leases. Aggregate rent expense under these operating leases and other vehicle leases charged to operations was approximately $1.3 million, $1.7 million and $2.5 million for the years ended December 31, 2005, 2006 and 2007, respectively.
The minimum future lease payments required under current non-cancelable operating lease agreements having remaining terms in excess of one year as of December 31, 2007, for each of the next five years and in the aggregate, are as follows (in thousands):
Year Ending December 31, | |||
2008 | $ | 2,527 | |
2009 | 2,078 | ||
2010 | 1,932 | ||
2011 | 1,732 | ||
2012 | 1,496 | ||
Thereafter | 5,985 | ||
Total operating lease commitments | $ | 15,750 | |
NOTE 8—INCOME TAXES
We are organized as a pass-through entity for federal income tax purposes. As a result, our partners are responsible for federal income taxes based on their respective share of our taxable income (loss). However, certain subsidiaries of the Partnership are “C” corporations and are subject to federal and state income taxes.
In May 2006, the State of Texas enacted a bill that replaced the existing state franchise tax with a margin tax. Effective January 1, 2007, the margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax. As a result, we recorded $1.3 million in state income tax for the year ended December 31, 2007 that is solely attributable to the Texas margin tax.
FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) became effective for the Partnership as of January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognizing, classification, interest and penalties, accounting in interim periods, disclosure and transition. Implementation of FIN 48 did not have a material impact on our consolidated financial statements.
We recognize interest and penalties related to uncertain tax positions in income tax expense. As of and for the year ended December 31, 2007, we did not recognize any income tax related interest or penalties relating to uncertain tax positions.
As of December 31, 2007, the Partnership had no unrecognized tax benefits.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
Certain of our subsidiaries are subject to U.S. federal income tax as well as income tax of multiple state jurisdictions. All our federal, state and local income tax returns for 2004 through 2006 remain open to examination. The Internal Revenue Service is examining the 2005 tax return for Stallion Solids Control, Inc. The ultimate outcome of this examination can not be determined at this time, however, we are not aware of any potential material adjustments.
The Partnership’s provision for income taxes attributable to income before income taxes for the years ended December 31, 2005, 2006 and 2007 consisted of the following (in thousands):
Years Ended December 31, | ||||||||||
2005 | 2006 | 2007 | ||||||||
Current: | ||||||||||
U.S. federal | $ | 561 | $ | 2,651 | $ | 3,510 | ||||
State and local | 110 | 500 | 1,833 | |||||||
Total current | 671 | 3,151 | 5,343 | |||||||
Deferred: | ||||||||||
U.S. federal | (73 | ) | 1,465 | 1,044 | ||||||
State and local | — | 311 | 23 | |||||||
Total deferred | (73 | ) | 1,776 | 1,067 | ||||||
Provision for income taxes | $ | 598 | $ | 4,927 | $ | 6,410 | ||||
The difference between the tax provision at the statutory federal income tax rate and the tax provision attributable to income before income taxes for the years ended December 31, 2005, 2006 and 2007 is analyzed below:
Years Ended December 31, | |||||||||
2005 | 2006 | 2007 | |||||||
Statutory federal income tax rate | 35.00 | % | 35.00 | % | 35.00 | % | |||
State income tax, net of federal benefit | 0.89 | % | 1.72 | % | 11.60 | % | |||
Texas margin tax, net of federal benefit | — | — | 61.37 | % | |||||
Effect of tax on partnership (income) loss attributable to partners | (28.80 | %) | (21.19 | %) | 178.60 | % | |||
Work opportunity credit | — | — | (4.63 | %) | |||||
Effect of nondeductible expenses | 0.46 | % | 0.42 | % | 13.76 | % | |||
Other | 0.10 | % | 0.10 | % | 1.21 | % | |||
7.65 | % | 16.05 | % | 296.91 | % | ||||
In accordance with SFAS No. 109, deferred tax assets and liabilities are recognized for future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the taxing jurisdictions in which the Partnership has operations (U.S. federal and states only).
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
Deferred tax assets and liabilities are classified as current or non-current according to the classification of the related asset or liability for financial reporting purposes. The components of the net deferred tax assets and liabilities were as follows (in thousands):
December 31, | ||||||||
2006 | 2007 | |||||||
Deferred tax assets (liabilities)—current: | ||||||||
Deferred compensation | $ | 44 | $ | — | ||||
Bad debt allowances | 110 | 476 | ||||||
Work opportunity credit | — | 100 | ||||||
Accrued bonuses | 143 | 83 | ||||||
Prepaid insurance and other | (125 | ) | — | |||||
Inventory | (98 | ) | — | |||||
Other | (45 | ) | (64 | ) | ||||
Deferred tax assets—current, net | $ | 29 | $ | 595 | ||||
Deferred tax liabilities—noncurrent: | ||||||||
Property, plant and equipment | $ | 9,391 | $ | 11,850 | ||||
Intangibles | 705 | 11,307 | ||||||
Other | 134 | 424 | ||||||
Deferred tax liabilities—noncurrent | $ | 10,230 | $ | 23,581 | ||||
NOTE 9—RELATED PARTY TRANSACTIONS
In December 2006, we made loans aggregating approximately $10.0 million to certain of our executive officers. These notes had a ten year maturity and bore interest at the “Annually Compounded Short Term Applicable Federal Rate” as published monthly by the Internal Revenue Service under Section 1274(d) of the Internal Revenue Code. All loans made to our executive officers were repaid in June 2007.
We believe that our related party transactions were either on terms at least as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties or were negotiated in connection with acquisitions, the overall terms of which were as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties.
For the years ended December 2005, 2006 and 2007, administrative fees charged by Carlyle/Riverstone were approximately $0.3 million, $0.6 million and $0.6 million, respectively, pursuant to our Partnership Agreement. As of December 31, 2006 and 2007, $0.2 million was accrued.
The Partnership leases office space and vehicles from a number of related parties. Rent expense under these non-cancelable operating leases charged to operations was approximately $0.4 million, $0.6 million and $1.0 million for the years ended December 31, 2005, 2006 and 2007, respectively.
Sales commissions are payable to a company owned by an employee of the Partnership for sales originating from this entity. These commissions were charged to operations and amounted to approximately $0.3 million and $0.2 million for the years ended December 31, 2005 and 2006, respectively. No commissions were earned or paid during the year ended December 31, 2007.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
In addition, the Partnership leases a chartered aircraft from Permian Mud Service and Champ Air to which Stallion shares in the operating expenses and pays for direct expenses. Champ Air, L.L.C. is owned and operated by Permian Mud Service, Inc., of which Mr. David Johnson, the father of Mr. Craig Johnson, and Stallion’s Chief Executive Officer, President and Chairman of the Board of Directors are minority shareholders. Stallion incurred expenses related to Permian Mud Service and Champ Air of approximately $0.1 million, $0.6 million and $0.9 million for the years ended December 31, 2005, 2006 and 2007, respectively. The term of the lease for this aircraft expired on December 31, 2006, but continues on a month-to-month basis since that date.
Stallion also leased an aircraft from Rivers Aviation in connection with the performance of the duties of a division manager. Rivers Aviation is owned by the former division manager. Stallion incurred expenses related to Rivers Aviation of approximately $0.2 million, $0.4 million and $0.2 million for the years ended December 31, 2005, 2006 and 2007, respectively. This agreement has since been terminated.
We lease an industrial facility in Alice, Texas from Q2 Rentals, L.L.C. for approximately $0.1 million per year. Pursuant to an informal arrangement, we lease a houseboat and certain other recreational boats in coastal Louisiana on a month-to-month basis from Q2 Rentals in exchange for paying the operating expenses of the facilities which were approximately $0.1 million and $0.2 million for the years ended December 31, 2006 and 2007, respectively. Q2 Rentals is operated by Mr. David M. Johnson, Mr. Craig Johnson’s father, and owned equally by Mr. Craig Johnson, Mr. Clayton D. Johnson, Mr. Craig Johnson’s brother, and Mr. David M. Johnson.
It is customary for the Partnership to lease real property from the former owners of acquired businesses. It is typical for many of these former owners to also be employed by the Partnership. Thus, Stallion and certain of its employees may be parties to leases relating to real property.
NOTE 10—SUPPLEMENTAL INFORMATION FOR STATEMENTS OF CASH FLOWS
Years Ended December 31, | |||||||||
2005 | 2006 | 2007 | |||||||
Interest paid | $ | 561 | $ | 2,651 | $ | 38,184 | |||
Non-cash investing and financing activities: | |||||||||
Revaluation of assets and liabilities under purchase accounting | $ | — | $ | — | $ | 10,569 | |||
Leasehold improvements and related deferred rent | $ | — | $ | — | $ | 1,996 | |||
Distribution payable | $ | 786 | $ | 1,800 | $ | 1,324 | |||
Change in asset retirement obligation | $ | — | $ | — | $ | 395 | |||
Limited partner interest issued in connection with acquisition | $ | — | $ | 22,950 | $ | — | |||
Conversion of notes payable to limited partner interest | $ | 500 | $ | 250 | $ | — | |||
Property, plant and equipment purchases financed with capital leases | $ | 511 | $ | — | $ | — | |||
Limited partner interest issued in connection with note payable | $ | 430 | $ | — | $ | — | |||
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 11—BUSINESS SEGMENT INFORMATION
Statement of Financial Accounting Standards No. 131 “Disclosure about Segments of an Enterprise and Related Information” establishes standards for the reporting of information about operating segments, products and services, geographic area and major customers. The method of determining what information to report is based on the way management organizes the operating segments within the Partnership for making operational decisions and assessments of financial performance.
The Partnership provides its services through two operating segments to customers to support its operations before, during and after drilling operations. Prior to the acquisition of Stallion Construction in March 2006, the Partnership operated in only one segment. The following is a description of operating segments as of December 31, 2007:
Wellsite Support Services. The Partnership offers two types of wellsite support services: workforce accommodation and solids control. Workforce accommodation services include workforce accommodation and related services, which are designed to house various personnel on location before, during and after drilling operations. In addition to workforce accommodation services, the Partnership also provides surface rental equipment including forklifts, manlifts, light plants, generators, compressors, loaders, trash containers and water systems. Integrated communications services are provided with the StaRComm service offering. The StaRComm system includes a satellite communication system that provides wireless intercoms integrated with telephone, fax and internet/data services throughout the drilling location.
Production & Logistics Services. Through the production & logistics services segment the Partnership offers three types of services: rig hauling, wellsite construction and production fluid services. Rig hauling services involve the moving and rig-up/rig-down of drilling rigs and related equipment. Heavy haul trucks, trailers and cranes provide the capability of rigging-down, transporting to the next drilling location and rigging-up of the drilling rig. Our production fluid services include a fleet of vacuum trucks, frac tank rentals, saltwater disposal wells and other assets used for fluid provision, transportation and disposal services.
Construction services are provided as the initial step of any new well project on land and inland marine environments. Location construction is the first step to occur after the well stake is placed marking the location for the well. In marshy areas and areas subject to greater rainfall and flooding, drilling locations require mats to maintain stability of the soil and drilling site. In addition, we also perform wellsite configuration and setup of production equipment, pipeline construction and tie-in, and location decommissioning.
Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The following table sets forth certain financial information with respect to reportable segments for the years ended December 31, 2005, 2006 and 2007 (in thousands):
Wellsite Support Services | Production & Logistics Services | Corporate and Eliminations | Total | |||||||||
2005: | ||||||||||||
Service revenue | $ | 73,126 | $ | — | $ | — | $ | 73,126 | ||||
Cost of services | 42,281 | — | — | 42,281 | ||||||||
Selling, general and administrative expenses | 5,658 | — | 4,225 | 9,883 | ||||||||
Depreciation and amortization | 7,461 | — | 337 | 7,798 | ||||||||
Capital expenditures (1) | 35,361 | — | 590 | 35,951 | ||||||||
Identifiable assets | 118,744 | — | 4,392 | 123,136 | ||||||||
2006: | ||||||||||||
Service revenue | $ | 162,661 | $ | 77,749 | $ | — | $ | 240,410 | ||||
Cost of services | 88,029 | 52,679 | — | 140,708 | ||||||||
Selling, general and administrative expenses | 5,688 | 1,550 | 11,932 | 19,170 | ||||||||
Depreciation and amortization | 19,214 | 9,162 | 1,692 | 30,068 | ||||||||
Capital expenditures (1) | 60,887 | 29,182 | 1,960 | 92,029 | ||||||||
Identifiable assets | 284,098 | 146,750 | 16,059 | 446,907 | ||||||||
2007: | ||||||||||||
Service revenue | $ | 215,265 | $ | 211,930 | $ | — | $ | 427,195 | ||||
Cost of services | 118,029 | 151,526 | — | 269,555 | ||||||||
Selling, general and administrative expenses | 10,228 | 3,912 | 25,887 | 40,027 | ||||||||
Depreciation and amortization | 31,314 | 28,487 | 2,942 | 62,743 | ||||||||
Capital expenditures (1) | 60,419 | 59,483 | 2,390 | 122,292 | ||||||||
Identifiable assets | 366,489 | 573,287 | 36,105 | 975,881 |
(1) | Excludes acquisitions |
The following table summarizes the changes in the carrying amount of goodwill by segment for the three years ended December 31, 2007 (in thousands):
Wellsite Support Services | Production & Logistics Services | Total | |||||||
Balance as of January 1, 2005 | $ | 6,444 | $ | — | $ | 6,444 | |||
2005 acquisition | 12,681 | — | 12,681 | ||||||
Balance as of December 31, 2005 | 19,125 | — | 19,125 | ||||||
2006 acquisitions | 53,109 | 38,176 | 91,285 | ||||||
Balance as of December 31, 2006 | 72,234 | 38,176 | 110,410 | ||||||
2007 acquisitions | 9,979 | 176,177 | 186,156 | ||||||
Balance as of December 31, 2007 | $ | 82,213 | $ | 214,353 | $ | 296,566 | |||
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 12—LEGAL MATTERS AND CONTINGENCIES
In the normal course of our business, we are party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, employees and other matters. Many of the claims against us relate to motor vehicle accidents which can result in loss of life or serious bodily injury. Although we cannot know the outcome of pending legal proceedings and the effect such outcomes may have on us, we believe that any liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.
NOTE 13—RECENT ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”), which establishes a formal framework for measuring fair value under generally accepted accounting principles. SFAS No. 157 defines and codifies the many definitions of fair value included among various other authoritative literature, clarifies and, in some instances, expands on the guidance for implementing fair value measurements, and increases the level of disclosure required for fair value measurements. Although SFAS No. 157 applies to and amends the provisions of existing FASB and AICPA pronouncements, it does not, of itself, require any new fair value measurements, nor does it establish valuation standards. SFAS No. 157 applies to all other accounting pronouncements requiring or permitting fair value measurements, except for: SFAS No. 123R, share-based payment and related pronouncements, the practicability exceptions to fair value determinations allowed by various other authoritative pronouncements, and AICPA Statements of Position 97-2 and 98-9 that deal with software revenue recognition. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership is currently assessing the potential effect of SFAS No. 157 on its consolidated financial statements.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (Topic 1N). “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB No. 108”). SAB No. 108 addresses how the effect of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. SAB No. 108 requires SEC registrants (i) to quantify misstatements using a combined approach which considers both the balance-sheet and income-statement approaches, (ii) to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors, and (iii) to adjust their financial statements if the new combined approach results in a conclusion is that an error is material. SAB No. 108 addresses the mechanics of correcting misstatements that include effects from prior years. It indicates that the current-year correction of a material error that includes prior-year effects may result in the need to correct prior-year financial statements even if the misstatement in the prior year or years is considered immaterial. Any prior-year financial statements found to be materially misstated in originating in years subsequent to the issuance of SAB No. 108, prior year financial statements requiring restatement would be restated in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.” Because the combined approach represents a change in practice, the SEC staff will not require registrants that followed an acceptable approach in the past to restate prior years’ historical financial statements. Rather, these registrants can report the cumulative effect of adopting the new approach as an adjustment to the current year’s beginning balance of retained earnings. If the new approach is adopted in a quarter other than the first quarter, financial statements for prior interim periods within the year of adoption may need to be restated. SAB No. 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB No. 108 did not have a material impact on the Partnership’s consolidated financial position, results of operations or cash flows.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. Generally accepted accounting principles have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. SFAS No. 159 helps to mitigate this type of accounting-induced volatility by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with detailed rules for hedge accounting. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. SFAS No. 159 also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. SFAS No. 159 does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS No. 157 and SFAS No. 107. SFAS No. 159 is effective as of the beginning of a company’s first fiscal year beginning after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the company makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157. The Partnership is currently assessing the potential effect of SFAS No. 159 on its consolidated financial statements.
In May 2007, the FASB issued FSP No. FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48,” (FSP FIN 48-1) amends FIN 48 to provide guidance on how an entity should determine whether a tax provision is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The term “effectively settled” replaces the term “ultimately settled” when used to describe recognition, and the terms “settlement” or “settled” replace the terms “ultimate settlement” or “ultimately settled” when used to describe measurement of a tax position under FIN 48. FSP FIN 48-1 clarifies that a tax position can be effectively settled upon the completion of an examination by a taxing authority without being legally extinguished. For tax positions considered effectively settled, an entity would recognize the full amount of tax benefit, even if the tax position is not considered more likely than not to be sustained based solely on the basis of its technical merits and the statue of limitations remains open. The Partnership does not anticipate that the adoption of FSP FIN 48-1 will have a material effect on the Partnership’s results of operations or financial position, although the Partnership is continuing to evaluate the full impact of the adoption of FSP FIN 48-1.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) “Business Combinations” (“SFAS No. 141( R)”) retains the fundamental requirements of the original pronouncement requiring that the purchase method be used for all business combinations SFAS No. 141( R) defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of the acquisition date SFAS No. 141( R) also requires that acquisition-related costs be recognized separately from the acquisition SFAS No. 141( R) is effective for the Partnership for fiscal 2010. The Partnership is currently assessing the impact of SFAS No. 141(R) on its consolidated financial position and results of operations.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). The objective of SFAS No. 160 is to improve the relevance, comparability, and transparency of the
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This Statement applies to all entities that prepare consolidated financial statements, except not-for-profit organizations. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It also amends certain of ARB 51’s consolidation procedures for consistency with the requirements of SFAS No. 141- R. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The effective date of SFAS No. 160 is the same as that of the related SFAS No. 141(R). SFAS No. 160 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements will be applied retrospectively for all periods presented. The Partnership is currently assessing the impact of SFAS No. 160 on its consolidated financial position and results of operations.
NOTE 14—SUBSEQUENT EVENTS
In January 2008, the Partnership reached an agreement to purchase substantially all of the operating assets of an entity for a purchase price of $12.0 million and a potential earn out of an additional $12.0 million per year for three years. This acquisition expanded Stallion’s production & logistics services segment.
In February 2008, we entered into an interest rate hedge transaction in the form of a two-year interest rate swap with notional amounts totaling $250.0 million, which becomes effective on August 7, 2008. The hedge is designed to swap the underlying variable rate for a fixed rate of approximately 2.71%. We are currently evaluating the accounting treatment for this hedge.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2007 | June 30, 2008 | |||||
(Unaudited) | ||||||
(in thousands) | ||||||
Assets | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | 9,850 | $ | 4,293 | ||
Accounts receivable, net | 116,800 | 126,413 | ||||
Costs and estimated earnings in excess of billings on uncompleted contracts | 1,611 | 1,762 | ||||
Inventory | 3,709 | 4,134 | ||||
Prepaid expenses | 9,128 | 5,703 | ||||
Deferred tax assets, net | 595 | 519 | ||||
Total current assets | 141,693 | 142,824 | ||||
Property, plant and equipment, net | 433,355 | 469,682 | ||||
Goodwill | 296,566 | 322,548 | ||||
Intangible and other assets, net | 104,268 | 97,134 | ||||
Total assets | $ | 975,882 | $ | 1,032,188 | ||
Liabilities and partners’ capital | ||||||
Current liabilities | ||||||
Accounts payable—trade | $ | 30,609 | $ | 38,664 | ||
Distribution payable | 476 | 476 | ||||
Accrued expenses | 43,330 | 45,159 | ||||
Current portion of long-term debt and notes payable | 2,235 | 1,879 | ||||
Current portion of obligations under capital leases | 86 | 91 | ||||
Total current liabilities | 76,736 | 86,269 | ||||
Long-term debt and notes payable, net of current portion | 722,316 | 734,097 | ||||
Obligations under capital leases, net of current portion | 95 | 49 | ||||
Asset retirement obligations | 604 | 802 | ||||
Deferred rent | 2,201 | 2,038 | ||||
Deferred tax liabilities | 23,581 | 29,827 | ||||
Total liabilities | 825,533 | 853,082 | ||||
Commitments and contingencies | ||||||
Partners’ capital | 150,349 | 179,106 | ||||
Total liabilities and partners’ capital | $ | 975,882 | $ | 1,032,188 | ||
See notes to consolidated financial statements.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended June 30, | ||||||||
2007 | 2008 | |||||||
(in thousands) | ||||||||
Service revenue | $ | 90,319 | $ | 147,307 | ||||
Operating expenses | ||||||||
Cost of services | 56,210 | 98,151 | ||||||
Selling, general and administrative expenses | 8,944 | 10,744 | ||||||
Depreciation and amortization | 13,888 | 16,906 | ||||||
Loss on disposal of property, plant and equipment | 659 | 1,144 | ||||||
Total operating expenses | 79,701 | 126,945 | ||||||
Income from operations | 10,618 | 20,362 | ||||||
Other income (expense) | ||||||||
Interest expense | (8,533 | ) | (18,031 | ) | ||||
Other | 70 | 50 | ||||||
Total other income (expense) | (8,463 | ) | (17,981 | ) | ||||
Income before income taxes | 2,155 | 2,381 | ||||||
Provision for income taxes | 1,340 | 2,043 | ||||||
Net income | $ | 815 | $ | 338 | ||||
See notes to consolidated financial statements.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
Six Months Ended June 30, | ||||||||
2007 | 2008 | |||||||
(in thousands ) | ||||||||
Service revenue | $ | 172,390 | $ | 288,310 | ||||
Operating expenses | ||||||||
Cost of services | 105,888 | 193,401 | ||||||
Selling, general and administrative expenses | 17,191 | 20,935 | ||||||
Depreciation and amortization | 24,659 | 36,516 | ||||||
(Gain) loss on disposal of property, plant and equipment | 979 | (101 | ) | |||||
Total operating expenses | 148,717 | 250,751 | ||||||
Income from operations | 23,673 | 37,559 | ||||||
Other income (expense) | ||||||||
Interest expense | (20,581 | ) | (34,558 | ) | ||||
Other | 147 | 374 | ||||||
Total other income (expense ) | (20,434 | ) | (34,184 | ) | ||||
Income before income taxes | 3,239 | 3,375 | ||||||
Provision for income taxes | 2,345 | 5,805 | ||||||
Net income (loss) | $ | 894 | $ | (2,430 | ) | |||
See notes to consolidated financial statements.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
SIX MONTHS ENDED JUNE 30, 2008
General Partner | Limited Partner | Accumulated Other Comprehensive Income | Total | |||||||||||
(in thousands) | ||||||||||||||
Balances, January 1, 2008 | $ | 37 | $ | 150,312 | $ | — | $ | 150,349 | ||||||
Contributions, net of issuance costs | — | 26,047 | — | 26,047 | ||||||||||
Unrealized gain on derivative financial instruments, net of tax | — | — | 5,140 | 5,140 | ||||||||||
Net loss | — | (2,430 | ) | — | (2,430 | ) | ||||||||
Total comprehensive income | — | — | — | 2,710 | ||||||||||
Balances, June 30, 2008 | $ | 37 | $ | 173,929 | $ | 5,140 | $ | 179,106 | ||||||
See notes to consolidated financial statements.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30, | ||||||||
2007 | 2008 | |||||||
(in thousands) | ||||||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ | 894 | (2,430 | ) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 24,659 | 36,516 | ||||||
Amortization of debt issuance costs | 5,629 | 1,574 | ||||||
Amortization of debt discount | — | 499 | ||||||
Accretion of asset retirement obligations | — | 15 | ||||||
Interest income on notes receivable—officers | (181 | ) | — | |||||
(Gain) loss on disposal of property, plant and equipment | 979 | (101 | ) | |||||
Deferred tax expense (benefit) | 1,758 | (318 | ) | |||||
Bad debt expense | 1,128 | 612 | ||||||
Other | 1 | — | ||||||
Changes in operating assets and liabilities, net of acquired assets and liabilities: | ||||||||
Accounts receivable | (12,378 | ) | (10,225 | ) | ||||
Costs and estimated earnings in excess of billings on uncompleted contracts | 464 | (151 | ) | |||||
Inventory | — | (425 | ) | |||||
Prepaid expenses | 2,492 | 3,357 | ||||||
Accounts payable—trade | 17,748 | 8,460 | ||||||
Accrued expenses | 6,270 | 1,318 | ||||||
Net cash provided by operating activities | 49,463 | 38,701 | ||||||
Cash flows from investing activities | ||||||||
Cash paid for acquisitions, net of cash received | (112,839 | ) | (23,377 | ) | ||||
Cash paid for acquisition costs | (689 | ) | (113 | ) | ||||
Cash paid for property, plant and equipment | (75,870 | ) | (61,325 | ) | ||||
Proceeds received from disposal of property, plant and equipment | 1,337 | 3,999 | ||||||
Repayment of notes receivable—officers | 10,181 | — | ||||||
Net cash used in investing activities | (177,880 | ) | (80,816 | ) | ||||
Cash flows from financing activities | ||||||||
Partners’ capital contributions, net | — | 26,047 | ||||||
Partners’ distributions | (123 | ) | — | |||||
Proceeds from long-term debt | 375,000 | — | ||||||
Payments of long-term debt | (209,502 | ) | (925 | ) | ||||
Proceeds (payments) from/to line of credit | (19,500 | ) | 12,350 | |||||
Payments for debt issuance costs | (12,386 | ) | (873 | ) | ||||
Payments on obligations under capital leases | (67 | ) | (41 | ) | ||||
Net cash provided by financing activities | 133,422 | 36,558 | ||||||
Net increase (decrease) in cash and cash equivalents | 5,005 | (5,557 | ) | |||||
Cash and cash equivalents, beginning of period | 4,100 | 9,850 | ||||||
Cash and cash equivalents, end of period | $ | 9,105 | $ | 4,293 | ||||
See notes to consolidated financial statements.
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2007 AND JUNE 30, 2008
NOTE 1—NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business: Stallion Oilfield Services Ltd. and subsidiaries provide a wide range of wellsite support services and production and logistics services to drilling contractors and oil and gas exploration and production companies, including workforce accommodation units, surface equipment rental, solids control services and equipment, communications infrastructure and production and logistics services in the drilling regions in the United States, including the Gulf Coast, South Texas, ArkLaTex, North Texas, the Mid-Continent, Permian Basin, Rocky Mountain Regions, Prudhoe Bay, Alaska, offshore Texas and Louisiana Gulf Coast and in international waters. Stallion is headquartered in Houston, Texas. References to “Stallion”, the “Partnership”, “we”, “our” and similar phrases as used throughout this report relate collectively to Stallion Oilfield Services Ltd. and its subsidiaries. Stallion is a limited partnership with Stallion Oilfield Holdings, Ltd. as the 99.99 percent limited partner and Stallion Interests, LLC as the .01 percent general partner of the Partnership.
Basis of Presentation: The accompanying unaudited consolidated financial statements as of June 30, 2008 and for the six months ended June 30, 2007 and 2008 have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. In the opinion of management, all material adjustments (consisting only of normal and recurring adjustments) necessary to present a fair statement of our financial position and results of operations for the interim periods included herein have been made, and the disclosures contained herein are adequate to make the information presented not misleading. Operating results for the six months ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.
Principles of Consolidation: The consolidated financial statements include the financial statements of Stallion Oilfield Services Ltd. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Fair Value of Financial Instruments: The carrying value amount of cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying amount of all debt approximates fair value because Stallion’s current borrowing rate is based on a variable market rate of interest, except our 9.75 percent Senior Notes which were issued in January 2007. As of June 30, 2008, the fair value of these notes was $252.8 million compared to a carrying amount of $300.0 million.
Other Comprehensive Income (Loss): Other than the interest rate swaps described in Note 6, we have no items representing other comprehensive income (loss) under Statement of Financial Accounting Standards No. 130, “Reporting Comprehensive Income” for the six months ended June 30, 2008.
Goodwill: Goodwill represents the excess of costs over the fair value of net assets of acquired businesses. Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” eliminates the amortization of goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal or other means will continue to be amortized over their useful lives. Goodwill acquired in a business combination is not amortized, but instead tested for impairment at least annually in the fourth quarter. Under this goodwill impairment test, if the fair value of a reporting unit does not exceed its carrying value, the excess of fair value of the reporting unit over the fair value of its net assets is considered to be the implied fair value of goodwill. If the carrying value of goodwill exceeds its implied fair value, the difference is recognized as
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
an impairment loss. Based on its evaluation of goodwill as of December 31, 2007, the Partnership determined that goodwill was not impaired, and thus recorded no impairment charge. No events have occurred that would require a re-evaluation as of June 30, 2008.
Derivative Instruments: We utilize derivative instruments in the form of interest rate swap agreements in order to manage the interest rate risk associated with our floating rate long-term debt. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), as amended (see Note 6). Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are deferred and recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of operations as the actual interest rate hedged by the agreements is settled.
The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as interest expense. Currently we have identified all derivative instruments as cash flow hedges.
Impairment: In accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, long-lived assets, such as property, plant and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used in operations is measured by a comparison of the carrying amount of an asset to estimated undiscounted cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of carrying amount or the fair value less anticipated cost to sell, and they would no longer be depreciated. Based on its ongoing evaluation of potential impairment of long-lived assets, we determined that no events have occurred that would require consideration of an impairment charge as of June 30, 2008.
Self-Insured Risk Accruals: The Partnership is partially self-insured for certain losses relating to workers’ compensation, automobile and general liability insurance claims. The Partnership maintains accruals to cover the self-insured risks, which are based on third-party data and historical claims history. Effective January 1, 2008, Stallion sponsors a partially self-insured health plan and maintains individual stop loss coverage of $0.2 million per person. Claims processing and the overall administration of the plan are provided by a third party. An accrual for the related self-insured retention under the plan is maintained in the accompanying consolidated balance sheet and is based on our claims history. As of June 30, 2008, self-insured-risk accruals under the health plan were approximately $1.2 million. This estimate may change in the near term as additional actual claim information becomes available.
Revenue Recognition: The Partnership’s revenue recognition policies are as follows:
Rental, Service and Sales Revenue
The Partnership recognizes revenue when it is realized and earned. The Partnership considers revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collection is reasonably assured. Delivery is not considered to have occurred until the customer takes title and assumes the risks and rewards of ownership, which is generally on the
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
date of shipment. Revenue from rental agreements is recognized over the rental period and revenue from service agreements is recognized when services have been rendered. Generally services are provided over a relatively short period of time.
Construction Revenue
Certain of our operations recognize revenue related to wellsite construction and offshore workforce accommodations unit construction using the percentage-of-completion method determined by the ratio of costs incurred to total estimated costs at completion. All known or anticipated losses on contracts are recognized in full when such losses become apparent. Contracts typically range from two to six months in duration.
Use of Estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:
• | Depreciation, depletion and amortization of property, plant and equipment and intangible assets, |
• | Impairment of property, plant and equipment and goodwill, |
• | Allowance for doubtful accounts, |
• | Litigation and self-insured risk reserves, |
• | Revenue recognition on uncompleted contracts, |
• | Asset retirement obligations, |
• | Fair value of assets acquired and liabilities assumed, |
• | Stock-based compensation, and |
• | Income taxes. |
The Partnership analyzes its estimates based on historical experience and various other assumptions that it believes to be reasonable under the circumstances. While management believes current estimates are reasonable and appropriate, under different assumptions or conditions, the actual results could differ, possibly materially from those previously estimated. Many of the conditions impacting these assumptions are outside of our control.
Effect of New Accounting Standards: In September 2006, the FASB issued Statement No. 157 (SFAS 157), “Fair Value Measurements.” This statement clarifies the definition of fair value and establishes a fair value hierarchy. SFAS 157, as originally issued, was effective for us on January 1, 2008. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis. The effective date for us under this FSP is January 1, 2009. As allowed by FSP FAS 157-2, we partially adopted SFAS 157 on January 1, 2008 and the impact of adoption was not significant. We do not expect the impact of applying SFAS 157 to the remaining assets and liabilities on January 1, 2009 to be material.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
SFAS 157 defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” The definition is based on an exit price rather than an entry price, regardless of whether the entity plans to hold or sell the asset. SFAS 157 also establishes a fair value hierarchy to prioritize inputs used in measuring fair value as follows:
• | Level 1: Observable inputs such as quoted prices in active markets; |
• | Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and |
• | Level 3: Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions |
On a recurring basis, we measure our derivatives at fair value, which was an asset of $5.1 million as of June 30, 2008. The fair value of these derivatives was determined using Level 2 inputs, as described above.
As allowed by FSP FAS 157-2, we did not apply SFAS 157 to fair value measurements of certain assets and liabilities included in property, plant and equipment, net, other accrued expenses, and other long-term liabilities on our Consolidated Balance Sheets.
Reclassifications: Certain reclassifications have been made to prior period financial statements to conform to the current presentation. These reclassifications had no effect on previously reported results of operations or partners’ capital.
NOTE 2—ACQUISITIONS
In January 2008, we acquired substantially all of the assets of Polleyco Construction Services LP and Graphics on the Fly as well as a 49% interest in Prospector Energy Services LLC, (collectively referred to as “Polleyco”) for a cash purchase price of approximately $12.0 million, resulting in goodwill of approximately $7.7 million. In addition to the initial consideration, the acquisition agreement contains certain performance based earn-out clauses. The contingent earn-out totals an additional maximum payment of approximately $12.0 million per year with the aggregate maximum payments totaling up to $36.0 million over a three year period. Any contingent earn-out payment made will be accounted for as additional purchase price and will increase goodwill. As of June 30, 2008, no earnout payments had been made. Polleyco, now a part of our production & logistics segment, is located in Denton, Texas and provides customers with experienced personnel and high-quality equipment, specializing in location construction, production facility construction, crew services, heavy equipment and trucking services, fluids handling and accommodations units.
In June 2008, we acquired substantially all of the assets of Mile High Oilfield Service, Inc. (“MH”) for a cash purchase price of approximately $10.6 million, resulting in goodwill of approximately $6.1 million. MH, which is engaged in the rental of workforce accommodations and other equipment to the drilling industry, is located in Vernal, Utah and will further expand our services into the Rocky Mountain region. MH is now a part of our wellsite support services segment.
The results of operations of Polleyco are included in our accounts and consolidated results of operations from its respective date of acquisition. No pro forma disclosure is provided for our other 2008 acquisition as it was not significant to our consolidated results of operations. The following table provides pro forma information for the three and six months ended June 30, 2007 related to our acquisition of Polleyco assuming the acquisition
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
occurred on January 1, 2007. No pro forma disclosure for the periods ended June 30, 2008 is provided for the Polleyco acquisition as this acquisition is included in our results of operations from January 1, 2008.
Three months ended June 30, 2007 | Six months ended June 30, 2007 | |||||
(unaudited) | ||||||
(in thousands) | ||||||
Revenue | $ | 94,492 | $ | 181,320 | ||
Net income | $ | 1,974 | $ | 3,432 | ||
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed during the six months ended June 30, 2008 (in thousands):
Assets acquired: | |||
Property and equipment | $ | 8,832 | |
Goodwill and other intangibles | 14,545 | ||
Total assets acquired | 23,377 | ||
Total liabilities assumed | — | ||
Net assets acquired | $ | 23,377 | |
The above table includes payments made for earnouts on other acquisitions and other adjustments included in goodwill and other intangibles totaling $806,000 for the six months ended June 30, 2008.
Additionally, in the six months ended June 30, 2008, we finalized the purchase accounting for four of the acquisitions that occurred in 2007 resulting in additional goodwill of approximately $11.3 million.
NOTE 3— PROPERTY, PLANT AND EQUIPMENT
Major classifications and estimated depreciable lives of property, plant and equipment are as follows (in thousands):
Estimated Life | December 31, 2007 | June 30, 2008 | ||||||||
(Unaudited ) | ||||||||||
Rental equipment | 3-20 years | $ | 248,640 | $ | 271,539 | |||||
Machinery and equipment | 5 years | 126,364 | 103,370 | |||||||
Auto and trucks | 1-5 years | 66,359 | 103,272 | |||||||
Saltwater disposal wells | 15 years | 30,185 | 35,099 | |||||||
Leasehold improvements | 3-5 years | 6,253 | 6,798 | |||||||
Office buildings | 4-15 years | 6,023 | 9,725 | |||||||
Computer equipment and software | 3-4 years | 3,046 | 3,918 | |||||||
Furniture and fixtures | 4 years | 2,308 | 2,306 | |||||||
Rock and gravel deposits | Units-of-Production | 2,071 | 2,071 | |||||||
Office equipment and furniture | 3-5 years | 1,144 | 724 | |||||||
492,393 | 538,822 | |||||||||
Less: accumulated depreciation, depletion and amortization | (81,941 | ) | (109,417 | ) | ||||||
410,452 | 429,405 | |||||||||
Assets not yet placed in service | 14,317 | 31,786 | ||||||||
Land | 4,574 | 6,529 | ||||||||
Construction in progress | 4,012 | 1,962 | ||||||||
Total property, plant and equipment | $ | 433,355 | $ | 469,682 | ||||||
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Index to Financial Statements
STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
Effective April 1, 2008, we changed the estimated useful lives of certain vehicles from two years to three years and certain equipment from ten to fifteen years to fifteen to twenty years, respectively, to more closely approximate the actual service lives of those assets that have been placed in service to date. The change in estimated useful lives was based upon a change in the estimated future benefits we expect to receive from those assets, the pattern of consumption of those benefits and information available regarding those benefits. The change in estimated useful lives resulted in a decrease in depreciation expense of approximately $1.7 million for the three and six months ended June 30, 2008.
Depreciation expense for the three months ended June 30, 2007 and 2008 was approximately $11.2 million and $14.2 million, respectively and for the six months ended June 30, 2007 and 2008 was approximately $20.3 million and $30.1 million, respectively.
NOTE 4—INTANGIBLE AND OTHER ASSETS
Intangible and other assets consist principally of acquired customer lists and non-compete agreements. Amortization expense related to intangible assets was $2.7 million and $2.7 million for the three months ended June 30, 2007 and 2008, respectively and $4.4 million and $6.4 million for the six months ended June 30, 2007 and 2008, respectively.
NOTE 5—DETAIL OF CERTAIN BALANCE SHEET ACCOUNTS
Accounts receivable consisted of the following (in thousands):
December 31, 2007 | June 30, 2008 | |||||||
(Unaudited) | ||||||||
Billed accounts receivable | $ | 110,193 | $ | 120,760 | ||||
Unbilled receivables | 11,554 | 9,431 | ||||||
Other receivables | 1,729 | 1,803 | ||||||
123,476 | 131,994 | |||||||
Less: allowance for doubtful accounts | (6,676 | ) | (5,581 | ) | ||||
Accounts receivable, net | $ | 116,800 | $ | 126,413 | ||||
The components of inventory consisted of the following (in thousands):
December 31, 2007 | June 30, 2008 | |||||
(Unaudited) | ||||||
Raw materials | $ | 2,900 | $ | 3,113 | ||
Work in process | 369 | 661 | ||||
Finished goods | 440 | 360 | ||||
Total inventory | $ | 3,709 | $ | 4,134 | ||
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
Accrued expenses consisted of the following (in thousands):
December 31, 2007 | June 30, 2008 | |||||
(Unaudited) | ||||||
Accrued interest | $ | 16,418 | $ | 18,602 | ||
Accrual for purchase price adjustments | 7,846 | 2,164 | ||||
Accrued federal and state income taxes | 5,622 | 4,124 | ||||
Accrued payroll and payroll taxes | 4,156 | 7,094 | ||||
Accrued insurance | 3,462 | 5,274 | ||||
Accrued other taxes | 2,539 | 3,342 | ||||
Accrued bonuses | 1,186 | 271 | ||||
Other accrued expenses | 2,101 | 4,288 | ||||
Total accrued expenses | $ | 43,330 | $ | 45,159 | ||
NOTE 6—LONG-TERM DEBT AND NOTES PAYABLE
In a private placement in January 2007, we issued $300.0 million of 9.75 percent Senior Notes due February 1, 2015 (“Senior Notes”). Proceeds from the sale of the Senior Notes were used to retire the then outstanding balance on a $210.0 million Term B Loan and to pay down approximately $44.5 million under the revolving credit facility.
In June 2007, we amended and restated the agreement governing our credit facility (as amended and restated, the “Restated Credit Agreement”) with UBS AG, Stamford Branch as Issuing Bank, Administrative Agent and Collateral Agent (“UBS AG”), and certain other financial institutions. In addition, we amended the Restated Credit Agreement (as amended, the “Credit Agreement”) in May 2008 to adjust the covenant package to provide greater operating flexibility, raise the letter of credit sub-limit and provide for the issuance of euro-denominated letters of credit.
The Credit Agreement provides for a $75.0 million term loan that will mature on June 12, 2013 and up to $175.0 million in borrowing capacity under a revolving credit facility that will mature on March 1, 2011. Additionally, the Credit Agreement provides for increases to the term loan facility and/or the revolving credit facility of up to $75.0 million in aggregate, subject to certain conditions. The Credit Agreement also provides up to $50.0 million for the issuance of letters of credit which may include euro-denominated letters of credit. Any outstanding letters of credit reduce borrowing capacity under the revolving credit facility.
In August 2007, we entered into a $250.0 million Credit Agreement (“Bridge Loan Facility”) to fund the acquisitions of our production services businesses. The Bridge Loan Facility has a five year maturity and requires interest only payments until maturity. The interest rate on the Bridge Loan Facility is as follows: the base rate plus 3.50 percent or LIBOR plus 4.50 percent; provided that (a) from and after May 1, 2008 until November 1, 2008, the interest rate shall be the base rate plus 4.25 percent or LIBOR plus 5.25 percent and (b) from and after November 1, 2008 until February 1, 2009, the interest rate shall be the base rate plus 5.00 percent or LIBOR plus 6.00 percent, and (c) from and after February 1, 2009 through August 1, 2012, the interest rate shall be base rate plus 5.50 percent or LIBOR 6.50 percent.
In February 2008, we entered into an interest rate hedge transaction in the form of a two-year interest rate swap with notional amounts totaling $250.0 million, which becomes effective on August 7, 2008. The hedge is designed to swap the underlining variable rate on our Bridge Loan Facility for a fixed rate of 2.71 percent.
In April 2008, we entered into another interest rate hedge transaction in the form of a two-year interest rate swap with notional amounts totaling $70.0 million, which becomes effective on August 7, 2008. The hedge is designed to swap the underlining variable rate on our Term Loan Facility for a fixed rate of 2.90 percent.
For the six months ended June 30, 2007 and 2008, our weighted average interest rate on outstanding borrowings was approximately 9.6 percent and 8.0 percent, respectively.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
Long-term debt and notes payable consists of the following (in thousands):
December 31, 2007 | June 30, 2008 | |||||||
(Unaudited) | ||||||||
Senior Notes | $ | 300,000 | $ | 300,000 | ||||
Bridge Loan Facility | 250,000 | 250,000 | ||||||
Revolving Credit Facility | 97,650 | 110,000 | ||||||
Term Loan Facility | 74,625 | 74,250 | ||||||
Notes payable to sellers of acquired businesses | 2,276 | 1,726 | ||||||
724,551 | 735,976 | |||||||
Less: current portion of long-term debt and notes payable | (2,235 | ) | (1,879 | ) | ||||
Total long-term debt and notes payable | $ | 722,316 | $ | 734,097 | ||||
NOTE 7—LEASE COMMITMENTS
The Partnership leases equipment and office spaces from a related party (see Note 9) and various unrelated parties in various locations under non-cancelable operating leases. Aggregate rent expense under these operating leases and other vehicle leases charged to income was approximately $0.2 million and $0.8 million for the three months ended June 30, 2007 and 2008, respectively and $0.4 million and $1.7 million for the six months ended June 30, 2007 and 2008, respectively.
NOTE 8—INCOME TAXES
Certain subsidiaries of the Partnership are ‘C’ corporations and are subject to federal and state income taxes. Those subsidiaries account for income taxes in accordance with the asset and liability approach prescribed by Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Deferred income tax assets and liabilities are determined based upon differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.
Financial Account Standards Board Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) became effective for the Partnership as of January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Implementation of FIN 48 did not have a material impact on our consolidated financial statements.
We recognize interest and penalties related to uncertain tax positions in income tax expense. For the six month periods ended June 30, 2007 and 2008, we did not recognize any income tax related interest or penalties.
As of June 30, 2008, the Partnership had no unrecognized tax benefits.
Certain of our subsidiaries are subject to U.S. federal income tax as well as income tax of multiple state and local jurisdictions. The majority of federal, state and income tax returns for 2004 through 2007 remain open to
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
examination. The Internal Revenue Service is examining the 2005 tax return for Stallion Solids Control, Inc. The ultimate outcome of this examination can not be determined at this time; however, we are not aware of any potential material adjustments.
The Partnership’s income tax expense (benefit) provision attributable to income before income taxes for the three and six months ended June 30, 2007 and 2008 consisted of the following (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2007 | 2008 | 2007 | 2008 | ||||||||||||
(Unaudited) | (Unaudited) | ||||||||||||||
Current tax expense (benefit): | |||||||||||||||
U.S. federal | $ | (53 | ) | $ | 1,430 | $ | 204 | $ | 4,674 | ||||||
State and local | 299 | 600 | 383 | 1,449 | |||||||||||
Total current | 246 | 2,030 | 587 | 6,123 | |||||||||||
Deferred tax expense (benefit): | |||||||||||||||
U.S. federal | 872 | 30 | 1,441 | (276 | ) | ||||||||||
State and local | 222 | (17 | ) | 317 | (42 | ) | |||||||||
Total deferred | 1,094 | 13 | 1,758 | (318 | ) | ||||||||||
Provision for income taxes | $ | 1,340 | $ | 2,043 | $ | 2,345 | $ | 5,805 | |||||||
The difference between the tax provision at the statutory federal income tax rate and the tax provision attributable to income before income taxes for the three and six months ended June 30, 2007 and 2008 is analyzed below:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2007 | 2008 | 2007 | 2008 | |||||||||
(Unaudited) | (Unaudited) | |||||||||||
Statutory federal income tax rate | 35.00 | % | 35.00 | % | 35.00 | % | 35.00 | % | ||||
Effect of state income tax, net | 3.38 | % | 2.45 | % | 6.01 | % | 7.18 | % | ||||
Texas margin tax, net of federal benefit | 19.65 | % | 18.94 | % | 12.92 | % | 27.81 | % | ||||
Effect on tax of partnership (income) loss attributable to partners | 3.17 | % | 27.96 | % | 15.58 | % | 98.37 | % | ||||
Effect of nondeductible expenses | 0.64 | % | 4.06 | % | 2.70 | % | 5.58 | % | ||||
Other | 0.36 | % | -2.55 | % | 0.19 | % | -1.90 | % | ||||
62.20 | % | 85.86 | % | 72.40 | % | 172.04 | % | |||||
In accordance with SFAS No. 109, deferred tax assets and liabilities are recognized for future tax effects of temporary differences between the tax bases of an asset or liability and its reported amount in the financial statements.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
Deferred tax assets and liabilities are classified as current or non-current according to the classification of the related asset or liability for financial reporting purposes. The components of the net deferred tax assets (liabilities) were as follows (in thousands):
December 31, 2007 | June 30, 2008 | ||||||
(Unaudited) | |||||||
Deferred tax assets (liabilities)—current: | |||||||
Bad debt allowances | $ | 476 | $ | 519 | |||
Work opportunity credit | 100 | — | |||||
Accrued bonuses | 83 | — | |||||
Other | (64 | ) | — | ||||
Deferred tax assets—current, net | $ | 595 | $ | 519 | |||
Deferred tax liabilities—noncurrent: | |||||||
Property, plant and equipment | $ | 11,850 | $ | 16,651 | |||
Intangibles | 11,307 | 12,825 | |||||
Other | 424 | 351 | |||||
Deferred tax liabilities—noncurrent | $ | 23,581 | $ | 29,827 | |||
NOTE 9—RELATED PARTY TRANSACTIONS
On November 30, 2006, we made certain loans aggregating $10.0 million to certain of our executive officers (Mr. Johnson—$6.0 million, Mr. Schorlemer—$2.0 million and Mr. Dishman—$2.0 million). These notes had a ten-year maturity but could be accelerated by us upon certain acceleration events including an initial public offering. The notes bore interest at a rate of 4.97% per year. The full principal amounts of these loans were repaid by Messrs Johnson, Schorlemer and Dishman along with related interest accrued from November 30, 2006 of approximately $109,000, $36,000 and $36,000, respectively.
We lease an industrial facility in Alice, Texas from Q2 Rentals, L.L.C. for approximately $90,000 per year. Pursuant to an informal arrangement, we lease a houseboat and certain other recreational boats in coastal Louisiana on a month-to-month basis from Q2 Rentals in exchange for paying the operating expenses of the facilities which were approximately $0.2 million for the year ended December 31, 2007. Q2 Rentals is operated by Mr. David M. Johnson, Mr. Craig Johnson’s father, and owned equally by Mr. Craig Johnson, Mr. Clayton D. Johnson, Mr. Craig Johnson’s brother, and Mr. David M. Johnson.
In addition, the Partnership leases certain chartered aircraft from Permian Mud Service and Champ Air. Stallion shares in the operating expenses and pays direct expenses of approximately $600,000 annually. Champ Air, L.L.C. is owned and operated by Permian Mud Service, Inc., of which Mr. David Johnson, the father of Mr. Craig Johnson, and Stallion’s Chief Executive Officer, President and Chairman of the Board of Directors are minority shareholders. Stallion incurred expenses related to Permian Mud Service and Champ Air of approximately $97,000 and $53,000 during the three months ended June 30, 2007 and 2008, respectively, and $154,000 and $106,000 during the six months ended June 30, 2007 and 2008, respectively. The term of the lease for this plane expired on December 31, 2006, but it continues on a month-to-month basis thereafter.
It is customary for the Partnership to lease real property from the former owners of acquired businesses. It is typical for many of these former owners to also be employed by the Partnership. Thus, Stallion and certain of its employees may be parties to leases relating to real property.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
NOTE 10—SUPPLEMENTAL INFORMATION FOR STATEMENTS OF CASH FLOWS
Six Months Ended June 30, | ||||||
2007 | 2008 | |||||
(Unaudited) | ||||||
(in thousands) | ||||||
Interest paid | $ | 2,037 | $ | 35,552 | ||
Taxes paid | $ | 610 | $ | 3,125 | ||
Non-cash investing and financing activities: | ||||||
Change in asset retirement obligations | $ | — | $ | 183 | ||
NOTE 11—BUSINESS SEGMENT INFORMATION
The Partnership provides its services through two operating segments to customers to support their operations before, during and after drilling operations. The following is a description of our operating segments as of June 30, 2008:
Wellsite Support Services
The Partnership offers four types of wellsite support services: workforce accommodation, solids control, surface equipment rentals and integrated communications services. Workforce accommodation services include workforce accommodation and related services, which are designed to house various personnel on location before, during and after drilling operations. In addition to workforce accommodation services, the Partnership also provides surface rental equipment including forklifts, manlifts, light plants, generators, compressors, loaders, trash containers and water systems. Integrated communications services are provided with the StaRComm service offering. The StaRComm system includes a satellite communication system that provides wireless intercoms integrated with telephone, fax and internet/data services throughout the drilling location.
Production & Logistics Services
Through the production & logistics services segment the Partnership offers three types of services: rig hauling, wellsite construction and production fluid services. Rig hauling services involve the moving and rig-up/rig-down of drilling rigs and related equipment. Heavy haul trucks, trailers and cranes provide the capability of rigging-down, transporting to the next drilling location and rigging-up of the drilling rig.
We provide construction services as the initial step of any new well project on land and inland marine environments. Location construction is the first step to occur after the well stake is placed marking the location for the well. In marshy areas and areas subject to greater rainfall and flooding, drilling locations require mats to maintain stability of the soil and drilling site. In addition, we also perform wellsite configuration and setup of production equipment, pipeline construction and tie-in, and location decommissioning.
Our production fluid services include a fleet of vacuum trucks, frac tank rentals, saltwater disposal wells and other assets used for fluid provision, transportation and disposal services.
Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of working capital and debt financing costs.
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
The following table sets forth certain financial information with respect to reportable segments for the three and six months ended June 30, 2007 and 2008, respectively (in thousands):
Wellsite Support Services | Production & Logistics Services | Corporate and Eliminations | Total | ||||||||||
Three Months Ended June 30, 2007: | |||||||||||||
Service revenue | $ | 50,583 | $ | 39,736 | $ | — | $ | 90,319 | |||||
Cost of services | 27,250 | 28,960 | — | 56,210 | |||||||||
Selling, general and administrative services | 2,699 | 719 | 5,526 | 8,944 | |||||||||
Segment profit | 20,634 | 10,057 | (5,526 | ) | 25,165 | ||||||||
Depreciation and amortization | 7,603 | 5,521 | 764 | 13,888 | |||||||||
Capital expenditures (1) | 20,259 | 18,914 | 197 | 39,370 | |||||||||
Identifiable assets | 371,375 | 240,308 | 25,179 | 636,862 | |||||||||
Three Months Ended June 30, 2008: | |||||||||||||
Service revenue | $ | 68,357 | $ | 78,950 | $ | — | $ | 147,307 | |||||
Cost of services | 38,778 | 59,373 | — | 98,151 | |||||||||
Selling, general and administrative services | 1,916 | 682 | 8,146 | 10,744 | |||||||||
Segment profit | 27,663 | 18,895 | (8,146 | ) | 38,412 | ||||||||
Depreciation and amortization | 7,127 | 8,660 | 1,119 | 16,906 | |||||||||
Capital expenditures (1) | 15,729 | 18,166 | 170 | 34,065 | |||||||||
Identifiable assets | 406,186 | 600,268 | 25,734 | 1,032,188 |
(1) | Excludes acquisitions |
Wellsite Support Services | Production & Logistics Services | Corporate and Eliminations | Total | ||||||||||
Six Months Ended June 30, 2007: | |||||||||||||
Service revenue | $ | 97,442 | $ | 74,948 | $ | — | $ | 172,390 | |||||
Cost of services | 53,512 | 52,376 | — | 105,888 | |||||||||
Selling, general and administrative services | 5,554 | 1,463 | 10,174 | 17,191 | |||||||||
Segment profit | 38,376 | 21,109 | (10,174 | ) | 49,311 | ||||||||
Depreciation and amortization | 13,828 | 9,502 | 1,329 | 24,659 | |||||||||
Capital expenditures (1) | 40,975 | 34,516 | 379 | 75,870 | |||||||||
Identifiable assets | 371,375 | 240,308 | 25,179 | 636,862 | |||||||||
Six Months Ended June 30, 2008: | |||||||||||||
Service revenue | $ | 126,220 | $ | 162,090 | $ | — | $ | 288,310 | |||||
Cost of services | 72,001 | 121,400 | — | 193,401 | |||||||||
Selling, general and administrative services | 3,591 | 1,406 | 15,938 | 20,935 | |||||||||
Segment profit | 50,628 | 39,284 | (15,938 | ) | 73,974 | ||||||||
Depreciation and amortization | 15,242 | 19,078 | 2,196 | 36,516 | |||||||||
Capital expenditures (1) | 26,713 | 34,305 | 307 | 61,325 | |||||||||
Identifiable assets | 406,186 | 600,268 | 25,734 | 1,032,188 |
(1) | Excludes acquisitions |
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STALLION OILFIELD SERVICES LTD. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007 AND JUNE 30, 2008
The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||
2007 | 2008 | 2007 | 2008 | ||||||||||
Segment profit | $ | 25,165 | $ | 38,412 | $ | 49,311 | $ | 73,974 | |||||
Depreciation and amortization | 13,888 | 16,906 | 24,659 | 36,516 | |||||||||
(Gain) Loss on disposal of assets | 659 | 1,144 | 979 | (101 | ) | ||||||||
Operating income | $ | 10,618 | $ | 20,362 | $ | 23,673 | $ | 37,559 | |||||
Stallion has identified its reportable segments to be wellsite support services and production and logistics services, with goodwill allocated to each reportable segment as of June 30, 2008 of approximately $97.5 million and $225.0 million, respectively. The change in total goodwill from December 31, 2007 to June 30, 2008 results from acquisitions made during the first six months of 2008 and the finalizing of the purchase accounting for four acquisitions that occurred in 2007.
In the normal course of our business, we are party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, employees and other matters. Many of the claims against us relate to motor vehicle accidents which can result in loss of life or serious bodily injury. Although we cannot know the outcome of pending legal proceedings and the effect such outcomes may have on us, we believe that any liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.
NOTE 13—RECENT ACCOUNTING PRONOUNCEMENTS
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. SFAS 161 achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related. Finally, it requires cross-referencing within footnotes to enable financial statements users to locate important information about derivative instruments. SFAS 161 will be effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, will be adopted by the Partnership beginning in the first quarter of 2009. The Partnership does not expect there to be any significant impact of adopting SFAS 161 on its financial position, cash flows and results of operations.
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To the Partners
Salty’s Group
Lufkin, TX
We have audited the accompanying combined balance sheets of Salty’s Group (the “Group”) as of December 31, 2005 and 2006, and the related combined statements of operations, changes in partners’ capital (deficit) and cash flows for the period from inception (August 3, 2005) through December 31, 2005 and for the year ended December 31, 2006. These combined financial statements are the responsibility of the Group’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined 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 combined financial statements referred to above present fairly, in all material respects, the combined financial position of Salty’s Group as of December 31, 2005 and 2006, and the combined results of their operations and their cash flows for the period from inception (August 3, 2005) through December 31, 2005 and for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
June 4, 2007
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SALTY’S GROUP
December 31, | |||||||
2005 | 2006 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | — | $ | 22,471 | |||
Accounts receivable—trade, net | 496,712 | 4,695,520 | |||||
Accounts receivable—related parties | — | 430,210 | |||||
Inventories | — | 1,637,850 | |||||
Prepaid expenses and other current assets | — | 123,405 | |||||
Total current assets | 496,712 | 6,909,456 | |||||
Plant, property and equipment, net | 4,345,810 | 27,697,514 | |||||
Other assets | — | 14,079 | |||||
Total assets | $ | 4,842,522 | $ | 34,621,049 | |||
Liabilities and partners’ capital | |||||||
Current liabilities | |||||||
Overdrafts payable | $ | 272,464 | $ | — | |||
Accounts payable | 31,945 | 1,768,378 | |||||
Borrowings from related parties | 3,135,016 | 10,439,635 | |||||
Accrued interest | — | 110,212 | |||||
Deferred revenue | — | 186,000 | |||||
Current maturities of long-term debt | 407,373 | 2,150,942 | |||||
Total current liabilities | 3,846,798 | 14,655,167 | |||||
Asset retirement obligations | 609,908 | 870,318 | |||||
Long-term debt, net of current maturities | 579,065 | 3,057,905 | |||||
Total liabilities | 5,035,771 | 18,583,390 | |||||
Commitments and contingencies | — | — | |||||
Partners’ capital (deficit) | (193,249 | ) | 16,037,659 | ||||
Total liabilities and partners’ capital (deficit) | $ | 4,842,522 | $ | 34,621,049 | |||
See notes to combined financial statements.
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SALTY’S GROUP
COMBINED STATEMENTS OF OPERATIONS
Period from inception (August 3, 2005) through December 31, 2005 | Year ended December 31, 2006 | |||||||
Revenue | $ | 986,584 | $ | 17,444,528 | ||||
Operating expenses | ||||||||
Cost of revenue | 619,807 | 3,146,076 | ||||||
Selling, general and administrative expenses | 143,351 | 5,933,137 | ||||||
Depreciation | 381,612 | 1,421,188 | ||||||
Accretion on asset retirement obligations | — | 34,268 | ||||||
Total operating expenses | 1,144,770 | 10,534,669 | ||||||
Income (loss) from operations | (158,186 | ) | 6,909,859 | |||||
Other income (expense) | ||||||||
Interest expense | (75,923 | ) | (598,797 | ) | ||||
Other income (expense) | 35,860 | (43,476 | ) | |||||
Total other expense | (40,063 | ) | (642,273 | ) | ||||
Net income (loss) | $ | (198,249 | ) | $ | 6,267,586 | |||
See notes to combined financial statements.
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SALTY’S GROUP
COMBINED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
Balance at inception (August 3, 2005) | $ | — | ||
Contributions | 5,000 | |||
Net loss | (198,249 | ) | ||
Balance at December 31, 2005 | (193,249 | ) | ||
Contributions | 12,265,521 | |||
Net income | 6,267,586 | |||
Distributions | (2,302,199 | ) | ||
Balance at December 31, 2006 | $ | 16,037,659 | ||
See notes to combined financial statements.
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SALTY’S GROUP
COMBINED STATEMENTS OF CASH FLOWS
Period from inception (August 3, 2005) through December 31, 2005 | Year Ended December 31, 2006 | |||||||
Cash flows from operating activities | ||||||||
Net (loss) income | $ | (198,249 | ) | $ | 6,267,586 | |||
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities: | ||||||||
Depreciation | 381,612 | 1,421,188 | ||||||
Loss on disposal of fixed assets | — | 33,247 | ||||||
Provision for bad debts | — | 808,538 | ||||||
Accretion on asset retirement obligations | — | 34,268 | ||||||
Change in operating assets and liabilities: | ||||||||
Accounts receivable | (496,712 | ) | (5,437,556 | ) | ||||
Prepaid expenses and other current assets | — | (123,405 | ) | |||||
Other assets | — | (14,079 | ) | |||||
Inventories | — | (1,637,850 | ) | |||||
Accounts payable | 31,945 | 1,736,433 | ||||||
Accrued interest | — | 110,212 | ||||||
Deferred revenue | — | 186,000 | ||||||
Net cash (used in) provided by operating activities | (281,404 | ) | 3,384,582 | |||||
Cash flows from investing activities | ||||||||
Purchases of plant, property and equipment | (4,117,514 | ) | (24,579,997 | ) | ||||
Net cash used in investing activities | (4,117,514 | ) | (24,579,997 | ) | ||||
Cash flows from financing activities | ||||||||
Bank overdraft | 272,464 | (272,464 | ) | |||||
Contributions | 5,000 | 12,265,521 | ||||||
Distributions | — | (2,302,199 | ) | |||||
Borrowings from related parties, net | 3,135,016 | 7,304,619 | ||||||
Proceeds from long-term debt | 1,089,901 | 6,932,274 | ||||||
Payments on long-term debt | (103,463 | ) | (2,709,865 | ) | ||||
Net cash provided by financing activities | 4,398,918 | 21,217,886 | ||||||
Net increase in cash and cash equivalents | — | 22,471 | ||||||
Cash and cash equivalents, beginning of period | — | — | ||||||
Cash and cash equivalents, end of period | $ | — | $ | 22,471 | ||||
Supplemental of cash flow information | ||||||||
Cash paid for interest | $ | 75,923 | $ | 488,585 | ||||
Non-cash operating and investing activity | ||||||||
Asset retirement obligation additions | $ | 609,908 | $ | 226,142 | ||||
See notes to combined financial statements.
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SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2005 AND 2006
1. Nature of Operations
Salty’s Group (the “Group” or “Salty’s”) is headquartered in Lufkin, Texas and provides frac tank rentals and sales, and saltwater hauling and disposal services in the United States of America, primarily in Texas.
Ten Texas limited partnerships under common control are combined under Salty’s for financial statement presentation (the “Group”). The ten entities include Salty’s Manufacturing, Ltd. (“Mfg”), Salty’s Well Service, Ltd. (“Well Service”), Salty’s Well Johnson No. 1, Ltd. (“Johnson 1”), Salty’s Well Johnson No. 2, Ltd. (“Johnson 2”), Salty’s Well Johnson No. 3, Ltd. (“Johnson 3”), Salty’s Well Johnson No. 4, Ltd. (“Johnson 4”), Salty’s Parker No. 1, Ltd. (“Parker”), Salty’s Well Shelby No. 1, Ltd. (“Shelby 1”), Salty’s Panola 1, Ltd. (“Panola”), and Salty’s Nacogdoches 1, Ltd. (“Nacogdoches”). Salty’s first limited partnership was formed on August 3, 2005 in Texas.
2. Summary of Significant Accounting Policies
Principles of Combination: The combined financial statements include the financial statements of the commonly controlled partnerships: Mfg, Well Service, Johnson 1, Johnson 2, Johnson 3, Johnson 4, Parker, Shelby 1, Panola and Nacogdoches. All significant intercompany balances and transactions have been eliminated in combination. The Group has no interest in any other organization, entity, company, or contract that could require any evaluation under FASB Interpretation No. 46 or Accounting Research Bulletin No. 51.
Cash and Cash Equivalents: For purposes of the statements of cash flows, the Group considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. There were no cash equivalents as of December 31, 2005 and 2006.
Fair Value of Financial Instruments: The carrying value amount of cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short maturity of these instruments. The carrying amount of all debt approximates fair value because the Group’s current borrowing rate is based on a variable market rate of interest.
Accounts Receivable: The Group extends credit to its customers based on informal discussions with management and generally collateral is not required. Outstanding accounts receivable are assessed routinely and an allowance is set up when accounts are deemed uncollectible. Accounts receivable are net of allowance for doubtful accounts of approximately $0 and $809,000 as of December 31, 2005 and 2006, respectively.
Inventories: Inventories are valued at the lower of cost or market with cost being determined using the average costing method. Cost includes applicable overhead and labor. Market is considered as the lower of either estimated replacement cost or estimated realizable value. The Group had no inventories as of December 31, 2005. Inventories consisted of raw materials and finished goods of approximately $1,400,000 and $240,000, respectively, as of December 31, 2006.
Plant, Property and Equipment: Plant, property and equipment are stated at cost. Depreciation is provided on the straight-line method over the estimated useful lives of the related assets, which range from three to fifteen years. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred.
Impairment of Long-Lived Assets: The Group evaluates an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include
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SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2005 AND 2006
market declines, changes in the manner in which the Group intends to use an asset, decisions to sell an asset and adverse changes in the legal or business environment.
If events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable, the Group estimates the future discounted cash flows from the asset for which the lowest level of separate cash flows can be measured, to determine if the asset is impaired. If the total undiscounted future cash flows are less than the carrying amount for the asset, the Group estimates the fair value of the asset either through reference to sales data for similar assets, or by using a discounted cash flow approach. The asset’s carrying value is then adjusted downward to the fair value. These cash flow estimates require the Group to make estimates and assumptions for many years into the future for pricing demand, competition, operating costs, legal, regulatory and other factors and these estimates or assumptions could change significantly either positively or negatively. No impairment losses have been recorded through December 31, 2006.
Federal Income Taxes: Salty’s is treated as a partnership for federal income tax purposes; accordingly, a provision for income taxes has not been recorded in the accompanying financial statements. Partnership income or losses are reflected in the partners’ income tax returns in accordance with their ownership percentages.
Revenue Recognition: The Group recognizes revenue when it is realized and earned. The Group considers revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collectibility is reasonably assured. Revenue from rental agreements is recognized over the rental period and revenue from service agreements is recognized when services have been rendered. Generally services are provided over a relatively short time.
Asset Retirement Obligations: The Group accounts for asset retirement obligations in accordance with Financial Accounting Standards Board (FASB) No. 143 Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Group to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize on equal amount as a cost of the asset depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations.
The Group owns and operates salt water disposal sites which are subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during 2005 and 2006:
2005 | 2006 | |||||
Liability for asset retirement obligations, beginning of the period | $ | — | $ | 609,908 | ||
Accretion expense | — | 34,268 | ||||
Obligations for new wells drilled | 609,908 | 226,142 | ||||
Liability for asset retirement obligations, end of the period | $ | 609,908 | $ | 870,318 | ||
Concentration of Credit Risk: The Group’s customer base consists primarily of oil and natural gas exploration and production companies and drilling contractors. The Group performs ongoing evaluations of its customers but generally does not require collateral on its trade receivables. During the period ended December 31, 2005, no customer accounted for more than 10% of total sales. During the year ended December 31, 2006, one customer accounted for 12.3% of total sales. The balance due from this customer as of December 31, 2006 was zero.
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SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2005 AND 2006
During 2005 and 2006, the Group had cash in excess of federally insured limits deposited in a bank. The Group monitors the financial condition of the bank and has experienced no losses associated with its accounts.
Company Allocations: The income or loss is allocated to the partners in accordance with the individual limited partnership agreements. Partners’ capital (deficit) consists of the following as of December 31, 2005 and 2006:
2005 | 2006 | ||||||
General partner | $ | (1,982 | ) | $ | 64,658 | ||
Limited partners | (191,267 | ) | 15,973,001 | ||||
$ | (193,249 | ) | $ | 16,037,659 | |||
Use of Estimates: The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:
• | Depreciation of plant, property and equipment, |
• | Impairment of plant, property and equipment, |
• | Allowance for doubtful accounts, and |
• | Asset retirement obligations. |
The Group analyzes its estimates based on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially from those previously estimated. Many of the conditions impacting these assumptions are outside of the Group’s control.
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SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2005 AND 2006
3. Plant, Property and Equipment
Major classifications of plant, property and equipment are as follows:
Estimated Useful Life | December 31, | |||||||||
2005 | 2006 | |||||||||
Disposal facilities | 5-15 years | $ | 2,827,265 | $ | 17,349,762 | |||||
Frac tanks | 10 years | 160,130 | 3,683,263 | |||||||
Automobiles and trucks | 3-5 years | 839,122 | 1,903,859 | |||||||
Buildings | 15 years | 11,246 | 1,740,964 | |||||||
Equipment | 3-7 years | — | 1,425,077 | |||||||
Trailers | 3-5 years | 495,673 | 1,312,163 | |||||||
Other depreciable property | 3-5 years | — | 296,582 | |||||||
4,333,436 | 27,711,670 | |||||||||
Less: accumulated depreciation | (381,612 | ) | (1,594,736 | ) | ||||||
3,951,824 | 26,116,934 | |||||||||
Land | 393,986 | 1,580,580 | ||||||||
Total plant, property and equipment | $ | 4,345,810 | $ | 27,697,514 | ||||||
4. Borrowings from Related Parties
From time to time, the Group borrows from its affiliates for purchases of equipment and the funding of operations. The amounts owed to affiliates do not generally have formal agreements, thus all amounts have been classified as current in borrowings from related parties. Interest expense on borrowings from related parties was approximately $14,000 and $441,000 for the period from inception (August 3, 2005) through December 31, 2005 and the year ended December 31, 2006, respectively.
5. Long-Term Debt
December 31, | ||||||||
2005 | 2006 | |||||||
Various notes payable to a bank, payable in monthly installments from $3,345 to $60,679, including interest at rates from 7.00% to 8.25% per annum, collateralized by inventory and equipment. Notes mature from August 2008 to November 2009. | $ | 231,147 | $ | 2,946,587 | ||||
Various notes payable to a financing company, payable in monthly installments from $1,794 to $20,118, including interest at rates from 6.99% to 8.00% per annum, collateralized by vehicles. Notes mature from July 2008 to September 2011. | 755,291 | 1,662,044 | ||||||
Various notes payable to a bank, payable in monthly installments from $1,004 to $19,161, including interest at rates from 8.00% to 8.25% per annum, collateralized by trailers. Notes mature from March 2009 to September 2011. | — | 600,216 | ||||||
Total long-term debt | 986,438 | 5,208,847 | ||||||
Less: current maturities | (407,373 | ) | (2,150,942 | ) | ||||
$ | 579,065 | $ | 3,057,905 | |||||
F-62
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2005 AND 2006
Estimated future maturities of long-term debt are as follows:
Year Ending December 31, | |||
2007 | $ | 2,150,942 | |
2008 | 2,104,720 | ||
2009 | 943,454 | ||
2010 | 9,731 | ||
$ | 5,208,847 | ||
6. Related Party Transactions
During 2005, the Group purchased land for one of its well sites from a related party for approximately $150,000. In addition, the Group earned revenue from a related party of approximately $54,000 and $201,000 for the period from inception (August 3, 2005) through December 31, 2005 and the year ended December 31, 2006, respectively.
7. Commitments and Contingencies
Environmental: Salty’s is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Salty’s cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Salty’s continues to monitor the status of these laws and regulations. Management believes that the likelihood of the disposition of any of these items resulting in a material adverse impact to Salty’s financial position, liquidity, capital resources or future results of operations is remote.
Currently, Salty’s has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to bring Salty’s into total compliance. The amount of such future expenditures is not determinable due to several factors including the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions which may be required, the determination of Salty’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Litigation: From time to time, Salty’s is a party to litigation or other legal proceedings that Salty’s considers to be a part of the ordinary course of business. Salty’s is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity.
F-63
Table of Contents
Index to Financial Statements
To the Partners
Salty’s Group
Lufkin, Texas
We have audited the accompanying combined balance sheet of Salty’s Group (the “Group”) as of July 31, 2007, and the related combined statements of operations, changes in partners’ capital and cash flows for the seven month period ended July 31, 2007. These combined financial statements are the responsibility of the Group’s management. Our responsibility is to express an opinion on these combined financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall combined financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Salty’s Group as of July 31, 2007, and the combined results of their operations and their cash flows for the seven month period ended July 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
/S/ UHY LLP |
UHY LLP |
Houston, Texas
April 29, 2008
F-64
Table of Contents
Index to Financial Statements
SALTY’S GROUP
Assets | | December 31, 2006 |
| July 31, 2007 | ||
Current assets | ||||||
Cash and cash equivalents | $ | 22,471 | $ | 2,114,480 | ||
Accounts receivable - trade, net | 4,695,520 | 6,425,728 | ||||
Accounts receivable - related parties | 430,210 | 9,184,311 | ||||
Inventories | 1,637,850 | 4,540,832 | ||||
Prepaid expenses and other current assets | 123,405 | 1,893,770 | ||||
Total current assets | 6,909,456 | 24,159,121 | ||||
Property and equipment, net | 27,697,514 | 38,136,058 | ||||
Other assets | 14,079 | 18,408 | ||||
Total assets | $ | 34,621,049 | $ | 62,313,587 | ||
Liabilities and partners’ capital | ||||||
Current liabilities | ||||||
Overdrafts payable | $ | — | $ | 9,295,437 | ||
Accounts payable | 1,768,378 | 4,359,340 | ||||
Borrowings from related parties | 10,439,635 | 6,058,671 | ||||
Accrued expenses | 110,212 | 1,223,227 | ||||
Deferred revenue | 186,000 | — | ||||
Current maturities of long-term debt | 2,150,942 | 6,165,617 | ||||
Total current liabilities | 14,655,167 | 27,102,292 | ||||
Asset retirement obligations | 870,318 | 468,163 | ||||
Long-term debt, net of current maturities | 3,057,905 | 6,016,770 | ||||
Total liabilities | 18,583,390 | 33,587,225 | ||||
Commitments and contingencies (note 6) | — | — | ||||
Partners’ capital | 16,037,659 | 28,726,362 | ||||
Total liabilities and partners’ capital | $ | 34,621,049 | $ | 62,313,587 | ||
See notes to combined financial statements.
F-65
Table of Contents
Index to Financial Statements
SALTY’S GROUP
COMBINED STATEMENTS OF OPERATIONS
Seven month period ended July 31, | ||||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Revenue | $ | 5,534,461 | $ | 45,192,362 | ||||
Operating expenses | ||||||||
Cost of revenue | 1,759,581 | 22,627,264 | ||||||
Selling, general and administrative expenses | 847,215 | 11,695,780 | ||||||
Depreciation | 686,523 | 3,553,357 | ||||||
Accretion on asset retirement obligations | — | 22,562 | ||||||
Total operating expenses | 3,293,319 | 37,898,963 | ||||||
Income from operations | 2,241,142 | 7,293,399 | ||||||
Other income (expense) | ||||||||
Interest expense | (267,795 | ) | (412,242 | ) | ||||
Other income | 2,467 | 27,854 | ||||||
Total other income (expense) | (265,328 | ) | (384,388 | ) | ||||
Income before state income taxes | 1,975,814 | 6,909,011 | ||||||
Provision for state income taxes | — | 316,347 | ||||||
Net income | $ | 1,975,814 | $ | 6,592,664 | ||||
See notes to combined financial statements.
F-66
Table of Contents
Index to Financial Statements
SALTY’S GROUP
COMBINED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
SEVEN MONTH PERIOD ENDED JULY 31, 2007
Balance as of January 1, 2007 | $ | 16,037,659 | ||
Contributions | 4,166,988 | |||
Distributions | (3,612,501 | ) | ||
Exchange of notes payable for limited partner interest | 5,541,552 | |||
Net income | 6,592,664 | |||
Balance as of July 31, 2007 | $ | 28,726,362 | ||
See notes to combined financial statements.
F-67
Table of Contents
Index to Financial Statements
SALTY’S GROUP
COMBINED STATEMENTS OF CASH FLOWS
Seven month period ended July 31, | ||||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Cash flows from operating activities | ||||||||
Net income | $ | 1,975,814 | $ | 6,592,664 | ||||
Adjustments to reconcile net income to net cash used in operating activities: | ||||||||
Depreciation | 686,523 | 3,553,357 | ||||||
(Gain) loss on disposal of fixed assets | (112,511 | ) | 129,584 | |||||
Provision for doubtful accounts | — | 802,940 | ||||||
Accretion on asset retirement obligations | — | 22,562 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | (1,900,241 | ) | (11,287,249 | ) | ||||
Prepaid expenses and other current assets | (12,000 | ) | (1,770,365 | ) | ||||
Other assets | — | (4,329 | ) | |||||
Inventories | — | (2,902,982 | ) | |||||
Accounts payable and accrued expenses | 93,212 | 4,057,977 | ||||||
Net cash used in operating activities | 730,797 | (805,841 | ) | |||||
Cash flows from investing activities | ||||||||
Proceeds from sale of property and equipment | 374,849 | — | ||||||
Purchases of property and equipment | (13,632,103 | ) | (14,546,202 | ) | ||||
New cash used in investing activities | (13,257,254 | ) | (14,546,202 | ) | ||||
Cash flows from financing activities | ||||||||
Bank overdraft | — | 8,755,437 | ||||||
Contributions | 5,746,394 | 4,166,988 | ||||||
Distributions | — | (3,612,501 | ) | |||||
Borrowings from related parties | 6,145,565 | 1,160,588 | ||||||
Proceeds from long-term debt | 3,312,212 | 10,716,592 | ||||||
Payments on long-term debt | (2,510,577 | ) | (3,743,052 | ) | ||||
Net cash provided by financing activities | 12,693,594 | 17,444,052 | ||||||
Net increase in cash and cash equivalents | 167,137 | 2,092,009 | ||||||
Cash and cash equivalents, beginning of period | — | 22,471 | ||||||
Cash and cash equivalents, end of period | $ | 167,137 | $ | 2,114,480 | ||||
Supplemental of cash flow information | ||||||||
Cash paid for interest | $ | 247,810 | $ | 416,694 | ||||
Non-cash operating and investing activity | ||||||||
Changes in asset retirement obligations | $ | — | $ | 424,717 | ||||
Exchange of notes payable for limited partner interest | $ | — | $ | 5,541,552 | ||||
See notes to combined financial statements.
F-68
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2006 AND JULY 31, 2007
1. Nature of Operations
Salty’s Group (the “Group” or “Salty’s”) is headquartered in Lufkin, Texas and provides frac tank rentals and sales, and salt water hauling and disposal services primarily in Texas.
Eleven Texas limited partnerships under common control (which were acquired by Stallion Oilfield Services Ltd. see Note 7) are combined under Salty’s for financial statement presentation (the “Group”). The eleven entities include Salty’s Manufacturing, Ltd. (“Mfg”), Salty’s Well Service, Ltd. (“Well Service”), Salty’s Hill County No. 1, Ltd. (“Hill”), Salty’s Well Johnson No. 1, Ltd. (“Johnson 1”), Salty’s Well Johnson No. 2, Ltd. (“Johnson 2”), Salty’s Well Johnson No. 3, Ltd. (“Johnson 3”), Salty’s Well Johnson No. 4, Ltd. (“Johnson 4”), Salty’s Parker No. 1, Ltd. (“Parker”), Salty’s Well Shelby No. 1, Ltd. (“Shelby 1”), Salty’s Panola 1, Ltd. (“Panola”), and Salty’s Nacogdoches 1, Ltd. (“Nacogdoches”).
2. Summary of Significant Accounting Policies
Principles of Combination: The combined financial statements include the financial statements of the commonly controlled partnerships: Mfg, Well Service, Hill, Johnson 1, Johnson 2, Johnson 3, Johnson 4, Parker, Shelby 1, Panola and Nacogdoches. All significant intercompany balances and transactions have been eliminated in combination.
Cash and Cash Equivalents: For purposes of the statement of cash flows, the Group considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. There were no cash equivalents as of December 31, 2006 or July 31, 2007.
Accounts Receivable—Trade: The Group extends credit to its customers based on informal discussions with management and generally collateral is not required. Outstanding accounts receivable are assessed routinely and an allowance is set up when accounts are deemed uncollectible. Accounts receivable are net of allowance for doubtful accounts of approximately $806,000 and $1,606,000 as of December 31, 2006 and July 31, 2007, respectively.
Inventories: Inventories are valued at the lower of cost or market with cost being determined using the average costing method. Cost includes applicable overhead and labor. Market is considered as the lower of either estimated replacement cost or estimated realizable value.
The Group had inventory consisting of raw materials and finished goods of approximately $1,400,000 and $240,000, respectively, as of December 31, 2006. As of July 31, 2007, the Group had inventory consisting of raw materials, work in process, and finished goods of approximately $2,405,000, $255,000, and $1,881,000, respectively.
Property and Equipment: Property and equipment are stated at cost. Depreciation is provided on the straight-line method over the estimated useful lives of the related assets, which range from three to fifteen years. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred.
F-69
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND JULY 31, 2007
Impairment of Long-Lived Assets: The Group evaluates an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which the Group intends to use an asset, decisions to sell an asset and adverse changes in the legal or business environment.
If events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable, the Group estimates the future discounted cash flows from the asset for which the lowest level of separate cash flows can be measured, to determine if the asset is impaired. If the total undiscounted future cash flows are less than the carrying amount for the asset, the Group estimates the fair value of the asset either through reference to sales data for similar assets, or by using a discounted cash flow approach. The asset’s carrying value is then adjusted downward to the fair value. These cash flow estimates require the Group to make estimates and assumptions for many years into the future for pricing demand, competition, operating costs, legal, regulatory and other factors and these estimates or assumptions could change significantly either positively or negatively. No impairment losses have been recorded through July 31, 2007.
Federal Income Taxes: Salty’s is treated as a partnership for federal income tax purposes; accordingly, a provision for income taxes has not been recorded in the accompanying financial statements. Partnership income or losses are reflected in the partners’ income tax returns in accordance with their ownership percentages.
In May 2006, the State of Texas enacted a bill that replaced the existing franchise tax with a margin tax. Effective January 1, 2007, the margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on the Group’s Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenue and expenses and therefore has the characteristics of an income tax. As a result, the Group recorded approximately $316,000 in state income taxes for the seven month period ended July 31, 2007 that is solely attributable to the Texas margin tax.
Revenue Recognition: The Group recognizes revenue when it is realized and earned. The Group considers revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collectibility is reasonably assured. Revenue from rental agreements is recognized over the rental period and revenue from service agreements is recognized when services have been rendered. Generally, services are provided over a relatively short time, usually not extending beyond one week.
Advertising Costs: The Group’s policy is to expense advertising costs as incurred. Advertising costs totaled approximately $19,000 and $93,000 for the seven month periods ended July 31, 2006 and 2007, respectively.
Asset Retirement Obligations: The Group accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations(“SFAS No. 143”) and FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations. SFAS No. 143 requires the Group to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset and depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlements of obligations.
F-70
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND JULY 31, 2007
The Group owns and operates salt water disposal sites which are subject to rules and regulations regarding usage and eventual closure. The following table reflects the changes in the liability during the seven month period ended July 31, 2007:
Liability for asset retirement obligations, January 1, 2007 | $ | 870,318 | ||
Accretion expense | 22,562 | |||
Change in estimate | (424,717 | ) | ||
Liability for asset retirement obligations, July 31, 2007 | $ | 468,163 | ||
During the seven month period ended July 31, 2007, the Group’s estimate for one well was reduced significantly based on additional information received upon the completion of an environmental study (see Note 6).
Concentration of Credit Risk: The Group’s customer base consists primarily of oil and natural gas exploration and production companies and drilling contractors. The Group performs ongoing evaluations of its customers but generally does not require collateral on its trade receivables. During the seven month period ended July 31, 2006, there were no customers which accounted for more than 10% of total sales. During the seven month period ended July 31, 2007, one customer accounted for 13.7% of total sales. No balance was due from this customer as of July 31, 2007.
During the seven month period ended July 31, 2007, the Group had cash in excess of federally insured limits deposited in a bank. The Group monitors the financial condition of the bank and has experienced no losses associated with its accounts.
Group Allocations: The income or loss is allocated to the partners in accordance with the individual partnership agreements. Partners’ capital consists of the following as of July 31, 2007:
General partner | $ | 126,620 | |
Limited partners | 28,599,742 | ||
Total partners’ capital | $ | 28,726,362 | |
Use of Estimates: The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:
• | Depreciation of property and equipment, |
• | Impairment of property and equipment, |
• | Allowance for doubtful accounts, and |
• | Asset retirement obligations. |
The Group analyzes its estimates based on historical experience and various other assumptions that it believes to be reasonable under the circumstances. While management believes current estimates are reasonable and appropriate, under different assumptions or conditions, the actual results could differ, possibly materially from those previously estimated. Many of the conditions impacting these assumptions are outside of the Group’s control.
F-71
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND JULY 31, 2007
3. Property and Equipment
Major classifications of property and equipment are as follows:
Estimated Life | December 31, 2006 | July 31, 2007 | ||||||||
Disposal facilities | 5-15 years | $ | 17,349,762 | $ | 24,101,354 | |||||
Frac tanks | 10 years | 3,683,263 | 4,235,945 | |||||||
Automobiles and trucks | 3-5 years | 1,903,859 | 4,532,628 | |||||||
Buildings | 15 years | 1,740,964 | 3,086,628 | |||||||
Equipment | 3-7 years | 1,425,077 | 2,271,263 | |||||||
Trailers | 3-5 years | 1,312,163 | 1,959,341 | |||||||
Land improvements | 15 years | — | 858,791 | |||||||
Other depreciable property | 3-5 years | 296,582 | 59,300 | |||||||
27,711,670 | 41,105,250 | |||||||||
Less: accumulated depreciation | (1,594,736 | ) | (4,753,298 | ) | ||||||
26,116,934 | 36,351,952 | |||||||||
Land | 1,580,580 | 1,784,106 | ||||||||
Total property and equipment | $ | 27,697,514 | $ | 38,136,058 | ||||||
4. Long-Term Debt
Long-term debt consists of the following:
December 31, 2006 | July 31, 2007 | |||||||
Various notes payable to a bank, payable in monthly installments from $3,345 to $60,679, including interest at rates from 7.00% to 8.25% per annum, collateralized by inventory and equipment. Notes mature from September 2007 to April 2010 (see Note 7). | $ | 2,946,587 | $ | 5,410,122 | ||||
Various notes payable to a financing company, payable in monthly installments from $1,004 to $20,118, including interest at rates from 6.99% to 8.74% per annum, collateralized by vehicles. Notes mature from June 2009 to September 2011 (see Note 7). | 1,662,044 | 3,451,812 | ||||||
Note payable to a bank, payable in monthly installments of $50,358, including interest at a rate of 7.75% per annum, secured by real estate. Note matures January 2012 (See Note 7). | — | 2,289,692 | ||||||
Various notes payable to a bank, payable in monthly installments from $946 to $23,544, including interest at rates from 6.99% to 8.05% per annum, collateralized by trailers. Notes mature from August 2008 to May 2010 (see Note 7). | 600,216 | 1,030,761 | ||||||
5,208,847 | 12,182,387 | |||||||
Less: current maturities | (2,150,942 | ) | (6,165,617 | ) | ||||
Total long-term debt, net of current maturities | $ | 3,057,905 | $ | 6,016,770 | ||||
F-72
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND JULY 31, 2007
Future maturities of long-term debt are as follows:
Period Ending July 31, | |||
2008 | $ | 6,165,617 | |
2009 | 3,749,550 | ||
2010 | 1,636,611 | ||
2011 | 582,022 | ||
2012 | 48,587 | ||
$ | 12,182,387 | ||
5. Related Party Transactions
From time to time, the Group borrows from its affiliates for purchases of equipment and the funding of operations. The amounts owed to affiliates do not generally have formal agreements, thus all amounts have been classified as current in borrowings from related parties. Interest expense on borrowings from related parties was approximately $145,000 and $153,000 for the seven month periods ended July 31, 2006 and 2007, respectively (see Note 7).
Revenue earned from various related parties consisted of the following:
Seven month period ended July 31, | ||||||
2006 | 2007 | |||||
(unaudited) | ||||||
Frac tank sales | $ | — | $ | 1,050,000 | ||
Salt water disposal fees | 165,659 | 961,274 | ||||
Other | 106,584 | 127,163 | ||||
$ | 272,243 | $ | 2,138,437 | |||
As of July 31, 2007, accounts receivable for sales to related parties amounted to approximately $1,684,000. The remaining $7,500,000 included in accounts receivable – related parties is for sales from a customer collected by the general partner (Salty’s Management, LLC) on the Group’s behalf.
6. Commitments and Contingencies
Environmental: Salty’s is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. Salty’s cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. Salty’s continues to monitor the status of these laws and regulations. Management believes that the likelihood of the disposition of any of these items resulting in a material adverse impact to Salty’s financial position, liquidity, capital resources or future results of operations is remote. Currently, Salty’s has not been fined, cited or notified of any environmental violations that would have a material adverse effect on its financial position, liquidity or capital resources.
Litigation: From time to time, Salty’s is a party to litigation or other legal proceedings that Salty’s considers to be a part of the ordinary course of business. Salty’s is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, will result in a material adverse effect on its financial condition, results of operations or liquidity.
F-73
Table of Contents
Index to Financial Statements
SALTY’S GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND JULY 31, 2007
7. Subsequent Event
On July 31, 2007, substantially all of the Group’s assets and liabilities were acquired by Stallion Oilfield Services Ltd., headquartered in Houston, Texas. As part of the transaction, all of the Group’s long-term debt obligations were repaid.
F-74
Table of Contents
Index to Financial Statements
To the Stockholders
L.E.G. Rentals, Inc. and Fluid Processors, Inc.
Riverton, WY
We have audited the accompanying combined balance sheet of L.E.G. Rentals, Inc. and Fluid Processors, Inc., collectively (the “Company”) as of December 31, 2006 and related combined statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and the results of its combined operations and its combined cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Our audit was conducted for the purpose of forming an opinion on the combined financial statements taken as a whole. The supplemental schedule on page F-79 is presented for purposes of additional analysis and is not required as part of the combined financial statements. Such information has been subjected to the auditing procedures applied in the audit of the combined financial statements and, in our opinion, is fairly stated in all material respects in relation to the combined financial statements taken as a whole.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
May 30, 2007
F-75
Table of Contents
Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED BALANCE SHEET
DECEMBER 31, 2006
Assets | |||
Current assets | |||
Cash and cash equivalents | $ | 3,842,575 | |
Accounts receivable-trade, less allowance for doubtful accounts of $20,991 | 1,977,302 | ||
Prepaid expenses and other current assets | 7,099 | ||
Total current assets | 5,826,976 | ||
Plant, property and equipment, net | 5,119,926 | ||
Total assets | $ | 10,946,902 | |
Liabilities and Stockholders’ Equity | |||
Current liabilities | |||
Accounts payable-trade | $ | 302,166 | |
Accrued expenses | 288,675 | ||
Income tax payable | 1,635,036 | ||
Total current liabilities | 2,225,877 | ||
Deferred tax liability | 164,832 | ||
Total liabilities | 2,390,709 | ||
Stockholders’ equity | 8,556,193 | ||
Total liabilities and stockholders’ equity | $ | 10,946,902 | |
See notes to combined financial statements.
F-76
Table of Contents
Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2006
Service revenue | $ | 17,540,440 | ||
Operating expenses | ||||
Cost of services | 5,664,762 | |||
Selling, general and administrative | 2,767,758 | |||
Depreciation and amortization | 1,202,278 | |||
Total operating expenses | 9,634,798 | |||
Operating income | 7,905,642 | |||
Other income (expense) | ||||
Other income | 25,397 | |||
Other expense | (15,171 | ) | ||
Total other income | 10,226 | |||
Income before provision for income taxes | 7,915,868 | |||
Provision for income taxes | ||||
Federal-current | 3,335,062 | |||
Federal-deferred | (611,755 | ) | ||
State | 224,614 | |||
2,947,921 | ||||
Net income | $ | 4,967,947 | ||
See notes to combined financial statements.
F-77
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
YEAR ENDED DECEMBER 31, 2006
Common Stock | Retained Earnings | Accumulated Other Comprehensive Loss | Total | ||||||||||||
Balances, January 1, 2006 | $ | 16,500 | $ | 4,144,167 | $ | (12,275 | ) | $ | 4,148,392 | ||||||
Dividends | — | (572,421 | ) | — | (572,421 | ) | |||||||||
Unrealized gain (loss) on investments | — | — | 14,730 | 14,730 | |||||||||||
Realized gain on investments | — | — | (2,455 | ) | (2,455 | ) | |||||||||
Net income | — | 4,967,947 | — | 4,967,947 | |||||||||||
Balances, December 31, 2006 | $ | 16,500 | $ | 8,539,693 | $ | — | $ | 8,556,193 | |||||||
See notes to combined financial statements.
F-78
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2006
Cash flows from operating activities | ||||
Net income | $ | 4,967,947 | ||
Adjustments to reconcile net income to net cash provided by operating activities | ||||
Depreciation | 1,202,278 | |||
Bad debts | 20,991 | |||
Deferred tax expense | (611,755 | ) | ||
Gain on sale of available for sale securities | (2,455 | ) | ||
Changes in operating assets and liabilities: | ||||
Accounts receivable-trade | (809,405 | ) | ||
Accounts receivable-stockholder | 10,000 | |||
Prepaid expenses and other current assets | 1,316 | |||
Accounts payable | (23,018 | ) | ||
Income tax payable | 685,241 | |||
Net cash provided by operating activities | 5,441,140 | |||
Cash flows from investing activities | ||||
Cash paid for plant, property and equipment | (2,898,543 | ) | ||
Proceeds received from sale of investments | 113,250 | |||
Net cash used in investing activities | (2,785,293 | ) | ||
Cash flows from financing activities | ||||
Distribution to shareholders | (410,000 | ) | ||
Net cash used in financing activities | (410,000 | ) | ||
Increase in cash and cash equivalents | 2,245,847 | |||
Cash and cash equivalents-beginning of period | 1,596,728 | |||
Cash and cash equivalents-end of period | $ | 3,842,575 | ||
Supplemental cash flow information | ||||
Cash paid for taxes | $ | 2,874,435 | ||
Non-cash financing and investing activity | ||||
Plant, property and equipment distributed to stockholders | $ | 162,421 | ||
See notes to combined financial statements.
F-79
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2006
1. Significant Accounting Policies
Nature of Business: L.E.G. Rentals, Inc. (“LEG”) and Fluid Processors, Inc. (“FPI”), collectively known as (the “Company”) is engaged in the rental of equipment to oil and gas companies and operators at drilling locations in order to separate the waste disposal from the well into solid and liquid forms. The process separates the solid waste from the liquid material into a dry solid form so that liquids can be recycled back into the well. This allows the customers to reduce the amount of waste produced in the drilling operations. The Company’s primary market area is the Rocky Mountain region of the United States of America. The Company operates from Riverton, Wyoming.
LEG was incorporated in Wyoming on September 6, 1977, and is authorized to issue unlimited shares of no par common voting stock and unlimited shares of no par common non-voting stock. As of December 31, 2006, there are 22,800 common voting shares issued and outstanding.
FPI was incorporated in Wyoming on June 27, 1990, and is authorized to issue unlimited shares of no par common voting stock and unlimited shares of no par common non-voting stock. As of December 31, 2006, there are 6,500 common voting shares issued and outstanding.
Principles of Combination: The accompanying Combined Financial Statements include the accounts LEG and FPI, which are under common control and ownership. All significant intercompany profits, accounts, and transactions have been eliminated in the combination. Stallion has no interest in any other organization, entity, partnership, or contract that could require any evaluation under FASB Interpretation No. 46 or Accounting Research Bulletin No. 51. All significant intercompany balances and transactions have been eliminated in consolidation.
Cash and Cash Equivalents: For purposes of the statement of cash flows, cash equivalents include time deposits, certificates of deposit and all highly liquid debt instruments with original maturities of three months or less.
Accounts Receivable: The Company extends credit to its customers based on informal discussions with the management of potential customers. Outstanding accounts receivable are assessed routinely and an allowance is set up when accounts are deemed uncollectible.
Investments: The Company determines the appropriate classification of its investments in debt and equity securities at the time of purchase and reevaluates such determinations at each balance sheet date. Debt securities are classified as held-to-maturity when the Company has the positive intent and ability to hold the securities to maturity. Debt securities for which the Company does not have the intent or ability to hold to maturity are classified as available-for-sale. Held-to-maturity securities are recorded as either short-term or long-term on the balance sheet based on contractual maturity date and are stated at amortized cost. Marketable securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and are reported at fair value, with unrealized gains and losses recognized in earnings. Debt and marketable equity securities not classified as held-to-maturity or as trading, are classified as available-for-sale, and are carried at fair market value, with the unrealized gains and losses, included in the determination of comprehensive income and reported in stockholder’s equity.
Plant, Property and Equipment: Plant, property and equipment are stated at cost. Depreciation is provided on the straight line method over the estimated useful lives of the related assets. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred.
F-80
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006
Impairment of Long-lived Assets: The Company evaluates an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which the Company intends to use an asset, decisions to sell an asset and adverse changes in the legal or business environment.
If events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable, the Company estimates the future undiscounted cash flows from the asset for which the lowest level of separate cash flows can be measured, to determine if the asset is impaired. If the total undiscounted future cash flows are less than the carrying amount for the asset, the Company estimates the fair value of the asset either through reference to sales data for similar assets, or by using a discounted cash flow approach. The asset’s carrying value is then adjusted downward to the fair value. These cash flow estimates require the Company to make estimates and assumptions for many years into the future for pricing demand, competition, operating costs, legal, regulatory and other factors and these estimates or assumptions could change significantly either positively or negatively.
Income Taxes: The Company accounts for income taxes under FASB Statement No. 109, “Accounting for Income Taxes”. Deferred income tax assets and liabilities are determined based upon differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred taxes result primarily from plant, property and equipment.
Revenue Recognition: Revenue from rental agreements are recognized over the rental period and revenue from service agreements are recognized when services have been rendered.
Advertising: The Company’s policy is to expense advertising costs as incurred. Advertising costs amounted to approximately $6,000 for the year ended December 31, 2006.
Concentration of Risk: During 2006, the Company had cash deposited in a bank which was in excess of federally insured limits. The Company monitors the financial condition of the bank and has experienced no losses associated with its account.
The Company’s customer base consists primarily of independent oil and natural gas producers. The Company performs ongoing evaluations of its customers but generally does not require collateral on its trade receivables. During the year ended December 31, 2006, sales to two customers accounted for approximately 55% and 15% of total sales, respectively, and approximately $1,023,000 and $209,000 are due from customers as of December 31, 2006, respectively.
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 certain 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. Actual results could differ from those estimates.
F-81
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006
2. Plant, Property and Equipment
Major classifications of plant, property and equipment and estimated depreciable lives as of December 31, 2006 are as follows:
Estimated Life | ||||||
Rental equipment | 5-10 years | $ | 7,721,632 | |||
Vehicles | 3-5 years | 431,982 | ||||
Leasehold improvements | various | 58,279 | ||||
Office equipment | 3-5 years | 14,592 | ||||
8,226,485 | ||||||
Less: accumulated depreciation | (3,117,702 | ) | ||||
5,108,783 | ||||||
Construction in progress-building | N/A | 11,143 | ||||
$ | 5,119,926 | |||||
3. Lease Commitments
The Company leases office space from a shareholder with no formal rental agreement in place as of December 31, 2006. Rent expense incurred for this office space was approximately $52,000 for the year ended December 31, 2006.
The Company also leases equipment on a day-to-day basis from several vendors. The rental expense incurred for this amounted to approximately $25,000 for the year ended December 31, 2006 and is included in cost of revenue in the statement of operations. Amounts re-billed to the customer are included in revenue. There are no formal rental agreements in place for the rental of equipment.
F-82
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Index to Financial Statements
SUPPLEMENTAL SCHEDULE
F-83
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED SCHEDULE OF OPERATING EXPENSES
YEAR ENDED DECEMBER 31, 2006
Cost of services | |||
Wages | $ | 2,815,407 | |
Repairs and maintenance | 1,005,590 | ||
Supplies | 941,036 | ||
Subcontracting | 247,092 | ||
Transportation cost | 235,611 | ||
Travel and per diem | 370,109 | ||
Other | 49,917 | ||
Total cost of services | $ | 5,664,762 | |
Selling, general and administrative | |||
Salaries, wages and benefits | $ | 1,793,100 | |
Taxes and insurance | 564,175 | ||
Vehicle expense | 105,098 | ||
Rent-office space | 96,211 | ||
Legal and professional | 69,410 | ||
Telecommunications | 58,900 | ||
Other | 80,864 | ||
Total selling, general and administrative | $ | 2,767,758 | |
F-84
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Index to Financial Statements
To the Board of Directors
L.E.G. Rentals, Inc. and Fluid Processors, Inc.
Houston, Texas
We have audited the accompanying combined balance sheet of L.E.G. Rentals, Inc. and Fluid Processors, Inc. (collectively, the “Company”) as of May 31, 2007 and related combined statements of operations, changes in stockholders’ equity and cash flows for the five months then ended. These combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall combined financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of the Company as of May 31, 2007 and the combined results of their combined operations and their cash flows for the five months then ended, in conformity with accounting principles generally accepted in the United States of America.
Our audit was conducted for the purpose of forming an opinion on the combined financial statements taken as a whole. The supplemental schedule on page 10 is presented for purposes of additional analysis and is not required as part of the basic combined financial statements. Such information has been subjected to the auditing procedures applied in the audit of the combined financial statements and, in our opinion, is fairly stated in all material respects in relation to the combined financial statements taken as a whole.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
July 24, 2008
F-85
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
December 31, 2006 | May 31, 2007 | |||||
Assets | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | 3,842,575 | $ | 6,328,184 | ||
Prepaid expenses and other current assets | 7,099 | — | ||||
Accounts receivable, net | 1,977,302 | 1,646,398 | ||||
Total current assets | 5,826,976 | 7,974,582 | ||||
Property and equipment, net | 5,119,926 | 5,444,779 | ||||
Total assets | 10,946,902 | $ | 13,419,361 | |||
Liabilities and stockholders’ equity | ||||||
Current liabilities | ||||||
Accounts payable—trade | $ | 302,166 | $ | 193,336 | ||
Accrued expenses | 288,675 | 67,024 | ||||
Income taxes payable | 1,635,036 | 2,409,840 | ||||
Total current liabilities | 2,225,877 | 2,670,200 | ||||
Deferred tax liabilities, net | 164,832 | 456,000 | ||||
Total liabilities | 2,390,709 | 3,126,200 | ||||
Stockholders’ equity | 8,556,193 | 10,293,161 | ||||
Total liabilities and stockholders’ equity | $ | 10,946,902 | $ | 13,419,361 | ||
See notes to combined financial statements.
F-86
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENTS OF OPERATIONS
Five month period ended May 31, | ||||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Revenue | $ | 6,398,580 | $ | 7,476,517 | ||||
Operating expenses | ||||||||
Cost of service | 2,199,418 | 2,264,109 | ||||||
Selling, general and administrative | 477,154 | 1,020,170 | ||||||
Depreciation and amortization | 500,949 | 330,044 | ||||||
Total operating expenses | 3,177,521 | 3,614,323 | ||||||
Operating income | 3,221,059 | 3,862,194 | ||||||
Other income (expense) | ||||||||
Other income | — | 15,311 | ||||||
Other expense | (431 | ) | (130,534 | ) | ||||
Total other income | (431 | ) | (115,223 | ) | ||||
Income before income tax provision (benefit) | 3,220,628 | 3,746,971 | ||||||
Federal—current | 1,360,393 | 1,418,805 | ||||||
Federal—deferred | 90,178 | 291,168 | ||||||
State | (252,497 | ) | — | |||||
1,198,074 | 1,709,973 | |||||||
Net income | $ | 2,022,554 | $ | 2,036,998 | ||||
See notes to combined financial statements.
F-87
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
Common Stock | Retained Earnings | Total | |||||||||
Balances, January 1, 2007 | $ | 16,500 | $ | 8,539,693 | $ | 8,556,193 | |||||
Dividends | — | (300,000 | ) | (300,000 | ) | ||||||
Net income | — | 2,036,968 | 2,036,968 | ||||||||
Balances, May 31, 2007 | $ | 16,500 | $ | 10,276,661 | $ | 10,293,161 | |||||
See notes to combined financial statements.
F-88
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED STATEMENTS OF CASH FLOWS
Five month period ended May 31, | ||||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Cash flows from operating activities | ||||||||
Net income | $ | 2,022,554 | $ | 2,036,968 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 500,949 | 330,044 | ||||||
Deferred tax expense | (1,029,084 | ) | 291,168 | |||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable—trade | 123,460 | 330,904 | ||||||
Prepaid expenses and other current assets | — | 7,099 | ||||||
Accounts payable and accrued expenses | 17,366 | (330,481 | ) | |||||
Income taxes payable | 218,421 | 774,804 | ||||||
Net cash used in operating activities | 1,853,666 | 3,440,506 | ||||||
Cash flows from investing activities | ||||||||
Cash paid for property and equipment | (1,684,746 | ) | (654,897 | ) | ||||
Net cash used in investing activities | (1,684,746 | ) | (654,897 | ) | ||||
Cash flows from financing activities | ||||||||
Dividends | — | (300,000 | ) | |||||
Net cash provided by financing activities | — | (300,000 | ) | |||||
Increase in cash and cash equivalents | 168,920 | 2,485,609 | ||||||
Cash and cash equivalents, beginning of period | 1,596,728 | 3,842,575 | ||||||
Cash and cash equivalents, end of period | $ | 1,765,648 | $ | 6,328,184 | ||||
Supplemental of cash flow information | ||||||||
Cash paid for income taxes | $ | 2,008,737 | $ | 644,000 | ||||
See notes to combined financial statements.
F-89
Table of Contents
Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2006 AND MAY 31, 2007
NOTE 1—NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business: L.E.G. Rentals, Inc. (“LEG”) and Fluid Processors, Inc. (“FPI”), collectively referred to as the “Company”, are engaged in the rental of equipment to oil and gas companies and operators at drilling locations in order to separate the waste disposal from the well into solid and liquid forms. The process separates the solid waste from the liquid material into a dry solid form so that liquids can be recycled back into the well. This allows the customers to reduce the amount of waste produced in the drilling operations. The Company’s primary market area is the Rocky Mountain region of the United States of America. The Company operates from Riverton, Wyoming.
LEG was incorporated in Wyoming on September 6, 1977, and is authorized to issue unlimited shares of no par common voting stock and unlimited shares of no par common non-voting stock. As of December 31, 2006 and May 31, 2007, there were 22,800 common voting shares issued and outstanding.
FPI was incorporated in Wyoming on June 27, 1990, and is authorized to issue unlimited shares of no par common voting stock and unlimited shares of no par common non-voting stock. As of December 31, 2006 and May 31, 2007, there were 6,500 common voting shares issued and outstanding.
Principles of Combination: The accompanying combined financial statements include the accounts LEG and FPI, which are under common control and ownership. All significant intercompany profits, balances, and transactions have been eliminated in the combination.
Cash and Cash Equivalents: For purposes of the statement of cash flows, cash equivalents include time deposits, certificates of deposit and all highly liquid debt instruments with original maturities of three months or less.
Accounts Receivable: The Company extends credit to its customers based on informal discussions with the management of potential customers. Outstanding accounts receivable are assessed routinely and an allowance is set up when accounts are deemed uncollectible.
Property and Equipment: Property and equipment are stated at cost. Depreciation is provided on the straight line method over the estimated useful lives of the related assets. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred.
Impairment of Long-lived Assets: The Company evaluates an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which the Company intends to use an asset, decisions to sell an asset and adverse changes in the legal or business environment.
If events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable, the Company estimates the future undiscounted cash flows from the asset for which the lowest level of separate cash flows can be measured, to determine if the asset is impaired. If the total undiscounted future cash flows are less than the carrying amount for the asset, the Company estimates the fair value of the asset either through reference to sales data for similar assets, or by using a discounted cash flow approach. The asset’s carrying value is then adjusted downward to the fair value. These cash flow estimates require the Company to make estimates and assumptions for many years into the future for pricing demand, competition, operating costs, legal, regulatory and other factors and these estimates or assumptions could change significantly either positively or negatively.
F-90
Table of Contents
Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND MAY 31, 2007
Income Taxes: The Company accounts for income taxes under Financial Accounting Standards Board (FASB) Statement No. 109,Accounting for Income Taxes. Deferred income tax assets and liabilities are determined based upon differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Deferred taxes result primarily from property and equipment and certain income deferred for income tax purposes at May 31, 2007.
Revenue Recognition: Revenue from rental agreements are recognized over the rental period and revenue from service agreements are recognized when services have been rendered.
Advertising: The Company’s policy is to expense advertising costs as incurred. Advertising costs amounted to approximately $3,000 and $4,000 for the five months ended May 31, 2006 and 2007, respectively.
Concentration of Risk: During 2007, the Company had cash deposited in a bank which was in excess of federally insured limits. The Company monitors the financial condition of the bank and has experienced no losses associated with its account.
The Company’s customer base consists primarily of independent oil and natural gas producers. The Company performs ongoing evaluations of its customers, but generally does not require collateral on its trade receivables. During the five months ended May 31, 2006, sales to two customers accounted for approximately 64% and 14% of total sales, respectively, and approximately $538,000 and $209,000 were due from customers as of May 31, 2006, respectively. During the five months ended May 31, 2007, sales to two customers accounted for approximately 53% and 17% of total sales, respectively, and approximately $529,000 and $262,000 were due from customers as of May 31, 2007, respectively.
Use of Estimates: The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain 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. Actual results could differ from those estimates.
NOTE 2—PROPERTY AND EQUIPMENT
Major classifications of property and equipment and estimated depreciable lives are as follows:
Estimated Life | December 31, 2006 | May 31, 2007 | ||||||||
Rental equipment | 5-10 years | $ | 7,721,632 | $ | 8,230,113 | |||||
Vehicles | 3-5 years | 431,982 | 577,679 | |||||||
Leasehold improvements | various | 58,279 | 58,279 | |||||||
Office equipment | 3-5 years | 14,592 | 26,454 | |||||||
8,226,485 | 8,892,525 | |||||||||
Less: accumulated depreciation | (3,117,702 | ) | (3,447,746 | ) | ||||||
5,108,783 | 5,444,779 | |||||||||
Construction in progress—building | 11,143 | — | ||||||||
$ | 5,119,926 | $ | 5,444,779 | |||||||
F-91
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Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND MAY 31, 2007
NOTE 3—LEASE COMMITMENTS
The Company leases office space from a stockholder with no formal rental agreement in place as of May 31, 2007. Rent expense incurred for this office space was approximately $20,000 and $16,000 for the five months ended May 31, 2006 and 2007, respectively.
NOTE 4—INCOME TAXES
The components of deferred tax liabilities (assets) are as follows:
December 31, 2006 | May 31, 2007 | |||||||
Allowance for bad debts | $ | (7,000 | ) | $ | (7,000 | ) | ||
Deferred income | — | 145,000 | ||||||
Property and equipment | 171,832 | 318,000 | ||||||
$ | 164,832 | $ | 456,000 | |||||
NOTE 5—SUBSEQUENT EVENT
Subsequent to May 31, 2007, all of the outstanding stock of the Company was acquired by Stallion Oilfield Services Ltd.
F-92
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Index to Financial Statements
SUPPLEMENTAL SCHEDULE
F-93
Table of Contents
Index to Financial Statements
L.E.G. RENTALS, INC. AND FLUID PROCESSORS, INC.
COMBINED SCHEDULES OF OPERATING EXPENSES
Five months ended May 31, | ||||||
2006 | 2007 | |||||
(unaudited) | ||||||
Cost of services | ||||||
Wages | $ | 931,173 | $ | 1,024,946 | ||
Repairs and maintenance | 491,528 | 497,753 | ||||
Supplies | 425,996 | 308,588 | ||||
Subcontracting | 132,074 | 193,783 | ||||
Travel and per diem | 53,593 | 126,844 | ||||
Transportation cost | 154,274 | 100,228 | ||||
Other | 10,780 | 11,967 | ||||
Total cost of services | $ | 2,199,418 | $ | 2,264,109 | ||
Selling, general and administrative | ||||||
Legal and professional | $ | 154,374 | $ | 459,659 | ||
Salaries, wages and benefits | 167,170 | 224,789 | ||||
Taxes and insurance | 70,212 | 204,760 | ||||
Vehicle expense | 20,000 | 66,945 | ||||
Telecommunications | 12,413 | 17,891 | ||||
Rent—office space | 25,755 | 16,000 | ||||
Other | 27,230 | 30,126 | ||||
Total selling, general and administrative | $ | 477,154 | $ | 1,020,170 | ||
F-94
Table of Contents
Index to Financial Statements
To the Partners
Polleyco Group
Houston, Texas
We have audited the accompanying combined balance sheets of Polleyco Group (the “Group”) as of December 31, 2006 and 2007, and the related combined statements of operations, equity, and cash flows for the years then ended. These combined financial statements are the responsibility of the Group’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined 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 combined financial statements referred to above present fairly, in all material respects, the combined financial position of Polleyco Group as of December 31, 2006 and 2007, and the combined results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP |
UHY LLP |
Houston, Texas
July 8, 2008
F-95
Table of Contents
Index to Financial Statements
COMBINED BALANCE SHEETS
December 31, | ||||||
2006 | 2007 | |||||
Assets | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | 38,808 | $ | 11,279 | ||
Accounts receivable—trade, net | 3,369,731 | 13,696,423 | ||||
Accounts receivable—partners | 3,700 | 284,505 | ||||
Total current assets | 3,412,239 | 13,992,207 | ||||
Property and equipment, net | 2,885,264 | 4,240,560 | ||||
Total assets | $ | 6,297,503 | $ | 18,232,767 | ||
Liabilities and equity | ||||||
Current liabilities | ||||||
Overdrafts payable | $ | — | $ | 714,089 | ||
Accounts payable | 225,473 | 954,125 | ||||
Accrued expenses | 49,145 | 219,372 | ||||
Current maturities of long-term debt | 949,334 | 3,231,448 | ||||
Total current liabilities | 1,223,952 | 5,119,034 | ||||
Long-term debt, net of current maturities | 2,105,330 | — | ||||
Total liabilities | 3,329,282 | 5,119,034 | ||||
Equity | 2,968,221 | 13,113,733 | ||||
Total liabilities and equity | $ | 6,297,503 | $ | 18,232,767 | ||
See notes to combined financial statements.
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COMBINED STATEMENTS OF OPERATIONS
Year Ended December 31, | ||||||||
2006 | 2007 | |||||||
Revenue | $ | 9,026,803 | $ | 30,722,811 | ||||
Operating expenses | ||||||||
Cost of revenue | 3,180,522 | 11,749,125 | ||||||
Selling, general and administrative expenses | 2,388,871 | 5,192,257 | ||||||
Depreciation | 265,671 | 660,235 | ||||||
Total operating expenses | 5,835,064 | 17,601,617 | ||||||
Income from operations | 3,191,739 | 13,121,194 | ||||||
Other income (expense) | ||||||||
Interest expense | (109,102 | ) | (144,501 | ) | ||||
Total other income (expense) | (109,102 | ) | (144,501 | ) | ||||
Income before state income tax expense | 3,082,637 | 12,976,693 | ||||||
State income tax expense—current | — | 215,060 | ||||||
Net income | $ | 3,082,637 | $ | 12,761,633 | ||||
See notes to combined financial statements.
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COMBINED STATEMENTS OF EQUITY
YEARS ENDED DECEMBER 31, 2006 AND 2007
Balance as of January 1, 2006 | $ | 797,749 | ||
Distributions | (912,165 | ) | ||
Net income | 3,082,637 | |||
Balance as of December 31, 2006 | 2,968,221 | |||
Contributions | 17,944 | |||
Distributions | (2,634,065 | ) | ||
Net income | 12,761,633 | |||
Balance as of December 31, 2007 | $ | 13,113,733 | ||
See notes to combined financial statements.
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COMBINED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||
2006 | 2007 | |||||||
Cash flows from operating activities | ||||||||
Net income | $ | 3,082,637 | $ | 12,761,633 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation | 265,671 | 660,235 | ||||||
Provision for bad debts | 4,343 | 427,841 | ||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable—trade | (2,615,761 | ) | (10,754,533 | ) | ||||
Accounts receivable—partners | 61,300 | (280,805 | ) | |||||
Accounts payable | 191,656 | 728,652 | ||||||
Accrued expenses | 42,109 | 170,227 | ||||||
Net cash provided by operating activities | 1,031,955 | 3,713,250 | ||||||
Cash flows from investing activities | ||||||||
Purchases of property and equipment | (2,468,323 | ) | (2,080,857 | ) | ||||
Proceeds from sale of property and equipment | — | 65,326 | ||||||
Net cash used in investing activities | (2,468,323 | ) | (2,015,531 | ) | ||||
Cash flows from financing activities | ||||||||
Overdrafts payable | — | 714,089 | ||||||
Contributions | — | 17,944 | ||||||
Distributions | (912,165 | ) | (2,634,065 | ) | ||||
Proceeds from long-term debt | 3,310,032 | 1,627,293 | ||||||
Payments on long-term debt | (971,582 | ) | (1,450,509 | ) | ||||
Net cash provided by (used in) financing activities | 1,426,285 | (1,725,248 | ) | |||||
Net decrease in cash and cash equivalents | (10,083 | ) | (27,529 | ) | ||||
Cash and cash equivalents, beginning of year | 48,891 | 38,808 | ||||||
Cash and cash equivalents, end of year | $ | 38,808 | $ | 11,279 | ||||
Supplemental cash flow information | ||||||||
Cash paid for interest | $ | 110,793 | $ | 181,698 | ||||
See notes to combined financial statements.
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NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2006 AND 2007
NOTE 1—BUSINESS OPERATIONS
Polleyco Group (the “Group” or “Polleyco”) is headquartered in Fort Worth, Texas. Three separate business entities under common control are combined under Polleyco for financial statement presentation. The three entities include Polleyco Construction Services, L.P. (“Construction”), Prospector Energy Services, LLC (“Prospector”), and Graphics on the Fly (“Graphics”).
Construction and Prospector are in the business of providing oilfield services in a variety of areas including the building of roads, installation of fencing, construction of frac pits, consultation services and other general construction needs. Graphics is in the business of creating signs and marketing materials for various customers.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Combination: The combined financial statements include the accounts of the commonly controlled entities: Construction, Prospector and Graphics. All significant intercompany balances and transactions have been eliminated upon combination.
Cash and Cash Equivalents: For purposes of the statements of cash flows, the Group considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. There were no cash equivalents as of December 31, 2006 and 2007.
Accounts Receivable: The Group extends credit to its customers based on informal discussions with management and generally collateral is not required. Outstanding accounts receivable are assessed routinely and an allowance is set up when accounts are deemed uncollectible. Accounts receivable are net of allowance for doubtful accounts of approximately $4,000 and $428,000 as of December 31, 2006 and 2007, respectively.
Property and Equipment: Property and equipment are stated at cost. Depreciation is provided on the straight-line method over the estimated useful lives of the related assets. All expenditures for major renewals and betterments are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred.
Impairment of Long-Lived Assets: The Group evaluates an asset for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which the Group intends to use an asset, decisions to sell an asset and adverse changes in the legal or business environment.
If events or circumstances indicate that a long-lived asset’s carrying value may not be recoverable, the Group estimates the future discounted cash flows from the asset for which the lowest level of separate cash flows can be measured, to determine if the asset is impaired. If the total undiscounted future cash flows are less than the carrying amount for the asset, the Group estimates the fair value of the asset either through reference to sales data for similar assets, or by using a discounted cash flow approach. The asset’s carrying value is then adjusted downward to the fair value. These cash flow estimates require the Group to make estimates and assumptions for many years into the future for pricing demand, competition, operating costs, legal, regulatory and other factors and these estimates or assumptions could change significantly either positively or negatively. No impairment losses have been recorded during the years ended December 31, 2006 and 2007, respectively.
Income Taxes: The Group is a “pass-through” group for federal income tax purposes; accordingly, a provision for income taxes has not been recorded in the accompanying financial statements. The Group’s income flows through to the income tax returns of the owners in accordance with their ownership percentages.
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POLLEYCO GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
In May 2006, the State of Texas enacted a bill that replaced the existing franchise tax with a margin tax. Effective January 1, 2007, the margin tax applies to legal entities conducting business in Texas, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The margin tax is based on the Group’s Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenue and expenses and therefore has the characteristics of an income tax. As a result, the Group recorded approximately $215,000 in state income taxes for the year ended December 31, 2007 that is solely attributable to the Texas margin tax.
Revenue Recognition: The Group recognizes revenue when it is realized and earned. The Group considers revenue to be realized and earned when services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collectibility is reasonably assured. Revenue from rental agreements is recognized over the rental period and revenue from service agreements is recognized when services have been rendered. Generally services are provided over a relatively short time.
Concentration of Credit Risk: The Group’s customer base consists primarily of oil and natural gas exploration and production companies and drilling contractors. The Group performs ongoing evaluations of its customers but generally does not require collateral on its trade receivables. During the year ended December 31, 2006, two customers accounted for 43 percent and 41 percent of total revenue. The balance due from these customers as of December 31, 2006 was $765,000 and $2,412,000, respectively. During the year ended December 31, 2007, one customer accounted for 95 percent of total revenue. The balance due from this customer as of December 31, 2007 was approximately $12,840,000.
During the years ended December 31, 2006 and 2007, the Group had cash in excess of federally insured limits deposited in a bank. The Group monitors the financial condition of the bank and has experienced no losses associated with its accounts.
Use of Estimates: The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenue and expenses recognized during the reporting period. Areas where critical accounting estimates are made by management include:
• | Depreciation of property and equipment |
• | Impairment of property and equipment, and |
• | Allowance for doubtful accounts |
The Group analyzes its estimates based on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially from those previously estimated. Many of the conditions impacting these assumptions are outside of the Group’s control.
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POLLEYCO GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
NOTE 3—PROPERTY AND EQUIPMENT
Major classifications of property and equipment are as follows:
Estimated Useful Life | December 31, | |||||||||
2006 | 2007 | |||||||||
Equipment | 5-7 | $ | 2,764,713 | $ | 3,814,931 | |||||
Automobiles and trucks | 5-7 | 521,090 | 1,178,114 | |||||||
Leasehold improvements | 10 | — | 43,847 | |||||||
Office furniture and equipment | 5-7 | 14,079 | 43,347 | |||||||
3,299,882 | 5,080,239 | |||||||||
Less: accumulated depreciation | (414,618 | ) | (1,074,853 | ) | ||||||
2,885,264 | 4,005,386 | |||||||||
Land | — | 235,174 | ||||||||
Property and equipment, net | $ | 2,885,264 | $ | 4,240,560 | ||||||
NOTE 4—LONG-TERM DEBT
The Group has various notes payable to banks and financing companies for the financing of equipment. These notes are payable in monthly installments ranging from $400 to $24,000, including interest at rates ranging from zero percent to 13.25 percent per annum and collateralized by property and equipment. Notes mature at various dates through October 2012. (See Note 6)
The Group also had a line of credit with a bank collateralized by accounts receivable and property and equipment. The maximum borrowing on the line of credit was $400,000 with interest payable monthly at a rate of 9.25 percent per annum and principal due upon maturity in November 2007. The Group had an outstanding balance on the line of approximately $300,000 at December 31, 2006.
NOTE 5—COMMITMENTS AND CONTINGENCIES
Litigation: From time to time, Polleyco is a party to litigation or other legal proceedings that Polleyco considers to be a part of the normal course of business. Polleyco is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, which would result in a material adverse effect on its financial condition, results of operations or liquidity.
Operating Leases: The Group leases two work yards from a related party under an informal month-to-month operating lease. The Group also leases office space and other work yards under non-cancelable operating leases which expire at various dates through December 2012. Rent expense was approximately $69,000 and $142,000 of which $30,000 and $105,000 was paid to the related party, for the years ended December 31, 2006 and 2007, respectively.
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POLLEYCO GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2006 AND 2007
The approximate future minimum rental payments under non-cancelable operating leases are as follows:
Year Ending December 31, | |||
2008 | $ | 1,032,000 | |
2009 | 1,005,000 | ||
2010 | 993,000 | ||
2011 | 983,000 | ||
2012 | 983,000 | ||
$ | 4,996,000 | ||
NOTE 6—SUBSEQUENT EVENT
On January 1, 2008, certain assets and working capital of the Group were purchased by Stallion Oilfield Services Ltd., headquartered in Houston, Texas. The Group’s debt was also repaid in January 2008, therefore it has been classified as current on the balance sheet. (See Note 4)
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Glossary of Terms
Appalachian Basin: The area of the United States comprised of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky and Virginia that lie at the foot of the Appalachian Mountains.
ArkLaTex. The region, centered in Northwest Louisiana, is where Arkansas, Louisiana, Texas and Oklahoma intersect.
Articulating loader. A heavy duty four-wheeled loading equipment with a knuckle-jointed body to maximize maneuverability on construction locations. The loader usually is used with forks or loading bucket for loading and moving dirt.
Backhoe. An excavator whose shovel bucket is attached to a hinged boom and is drawn backward to move earth.
Barge. A floating vessel used for carrying heavy equipment or conducting operations in inland waters; usually pushed or pulled by a tug boat to and from a location.
Centrifuge. An item of solids-removal equipment that removes fine and ultra fine solids. It consists of a conical drum that rotates at 2000 to 4000 rpm and is useful for processing weighted drilling fluids and can remove finer solids than can shaker screens.
Closed-loop system. A solids control system including tanks which contains all of the drilling fluids and cuttings on location instead of an earthen reserve pit.
Compressor. A device that raises the pressure of a compressible fluid such as air or gas. Compressors create a pressure differential to move or compress a vapor or a gas.
Crew quarter. A skid-mounted accommodation which houses the drilling rig crew.
Cuttings. The fragments of rock dislodged by the bit and brought to the surface in the drilling fluids/mud. Washed and dried cuttings samples are analyzed by geologists to obtain information about the formations drilled.
Drilling efficiency. The efficiency at which the drill cuttings and other solids are removed from the drilling fluids stream; greater efficiency leads to greater rates-of-penetration of the drill bit, which reduces drilling time.
Drilling fluids. Any of a number of liquid and gaseous fluids and mixtures of fluids and solids (as solid suspensions, mixtures and emulsions of liquids, gases and solids) used in operations to drill boreholes into the earth. Synonymous with “drilling mud” in general usage.
Frac. A method in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open, forming passages through which oil can flow into the wellbore. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension into the fractures. When the pressure is released at the surface, the fractures partially close on the proppants, leaving channels for oil and gas to flow through.
Frac Tank. A portable storage tank used to hold frac fluid, which is used to fracture subterranean formations to permit the recovery of oil and gas.
Fort Worth Basin. A region encompassing roughly 14 counties of north-central Texas containing a world-class unconventional natural-gas accumulation. The formation is a lithologically complex interval of low permeability that requires artificial stimulation to produce.
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Hydrocarbon. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.
Light plant. A generator with light extensions used to illuminate areas during night-time operations.
Manlift. Usually a 40’ or 60’ machine which has a boom and basket to lift personnel safely to various heights.
Mid-Continent region. The oil and gas producing area contained in Oklahoma, Arkansas, Kansas, Missouri, Nebraska, Iowa, North Dakota, South Dakota and Minnesota.
Permian Basin. The oil and natural gas producing area largely contained in the western part of Texas extending westward into the southeastern part of New Mexico.
Pit closure. The backfill of an existing reserve pit.
Pit remediation. The restoration of the area where a reserve pit was located to pre-existing state.
Pit. Originally, an open hole dug in the ground to hold drilling fluid or waste materials discarded after the treatment of drilling mud/fluid. For some wellsite operations, pits are used for suction to the mud pumps, settling of mud sediments, and storage of reserve mud. Steel tanks are much more commonly used for these purposes now, but they are still usually referred to as pits.
Pole truck. A heavy-duty utility truck used to lift and set equipment on a drilling location.
Production facilities. Facilities constructed after the drilling of a successful well to handle the oil and gas that is produced; typically, these facilities consist of tank batteries for oil, condensate or residential saltwater production, firewall containment barriers, condensers, heaters, flow lines, pump jacks and other equipment as designed by production engineers to facilitate production of the particular well.
Rocky Mountain region. The region encompassing the states of Colorado, Utah, Wyoming, New Mexico and part of South Dakota.
Saltwater injection well. Well used to inject produced water into the same or similar subsurface formation or reservoir from which the fluids originated by pressure for secondary recovery of oil.
Sewer systems. Temporary tanks and pumps used to store sewage from houses on the drill site.
Shale. A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight sands. A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
Vacuum truck. A tractor truck with a 130 barrel trailer used to haul various oilfield fluids including fresh water, salt water, drilling muds and waste.
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Domestic Onshore Operating Areas
Note: | Stallion has offshore assets on location in the Gulf of Mexico, including Bay of Campeche, Mexico, Trinidad and Tobago and Equatorial Guinea. |
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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. Other Expenses of Issuance and Distribution
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and The NASDAQ Stock Market LLC listing fee, the amounts set forth below are estimates:
Securities and Exchange Commission registration fee | $ | 12,280 | |
FINRA filing fee | 40,500 | ||
The NASDAQ Stock Market LLC listing fee | 100,000 | ||
Printing and engraving expenses | |||
Legal fees and expenses | |||
Accounting fees and expenses | |||
Transfer agent and registrar fees | |||
Miscellaneous | |||
TOTAL | $ | ||
ITEM 14. Indemnification of Directors and Officers
Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper. The Company’s certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all current or former directors or officers of the Company. As permitted by the DGCL, the certificate of incorporation provides that directors of the Company shall have no personal liability to the Company or its stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to the Company or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.
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ITEM 15. Recent Sales of Unregistered Securities
The following is a description of all securities that the registrant has sold within the past three years without registering the securities under the Securities Act:
The transactions contemplated by the agreement and plan of merger will be completed immediately prior to the closing of this offering. In these transactions, holders of the limited partnership interests of our predecessor will receive an aggregate of shares of our common stock in exchange for their respective partnership interests. The registrant will rely on the provisions of Section 4(2) of the Securities Act in claiming exemption for the offering, sale and delivery of such securities from registration under the Securities Act.
ITEM 16. Exhibits and Financial Statement Schedules
a. Exhibits:
1.1*** | — | Form of Underwriting Agreement | ||
2.1** | — | Agreement and Plan of Merger of Stallion Oilfield Holdings, Ltd. with and into Stallion Oilfield Services, Inc. | ||
3.1*** | — | Amended and Restated Certificate of Incorporation | ||
3.2*** | — | Amended and Restated Bylaws | ||
4.1*** | — | Specimen Stock Certificate representing of common stock | ||
4.2** | — | Indenture dated January 24, 2007, between Stallion Oilfield Services Ltd., Stallion Oilfield Finance Corp. and the Guarantors Named Therein, with the Bank of New York Trust Company, N.A., as Trustee, for 9.75% Senior Notes due 2015. | ||
5.1* | — | Opinion of Vinson & Elkins L.L.P. | ||
10.1** | — | Registration Rights Agreement , dated as of June 30, 2006, by and among Stallion Oilfield Services, Inc., C/R Stallion Investment Partnership, L.P. and C/R Energy Coinvestment II, L.P. | ||
10.2** | — | Nominating Agreement, dated as of June 30, 2006, by and among Stallion Oilfield Services, Inc., Stallion Oilfield Holdings, Ltd. and C/R Stallion Investment Partnership, L.P. | ||
10.3*** | — | Form of Indemnification Agreement | ||
10.4***† | — | Stallion Oilfield Services 2008 Stock Incentive Plan | ||
10.5**† | — | Employment Agreement dated as of January 31, 2005 with Craig M. Johnson | ||
10.6**† | — | Employment Agreement dated as of January 31, 2005 with David S. Schorlemer | ||
10.7**† | — | Employment Agreement dated as of January 31, 2005 with Hill M. Dishman | ||
10.8**† | — | Employment Agreement dated as of July 19, 2007 with Douglas E. Stewart | ||
10.9**† | — | Employment Agreement dated as of March 1, 2006 with Jennifer Guidry | ||
10.10** | — | Third Amended and Restated Credit Agreement, dated as of June 12, 2007, among Stallion Oilfield Services Ltd., as borrower, Stallion Oilfield Holdings, Ltd., Stallion Interests, LLC and the other persons party thereto as guarantors, the lenders party thereto, UBS Securities LLC and Banc of America Securities LLC, as joint lead arrangers and joint bookmanagers, UBS AG, Stamford Brach, as issuing bank, administrative agent and collateral agent, UBS Loan Finance LLC, as swingline lender, Amegy Bank National Association, as syndication agent and Natexis Banques Populaires, as documentation agent. | ||
10.11** | — | Amendment and Waiver to Third Amended and Restated Credit Agreement dated January 30, 2008. | ||
10.12** | — | Second Amendment and Waiver to Third Amended and Restated Credit Agreement dated May 12, 2008. | ||
10.13** | — | Amended and Restated Purchase and Sale Agreement dated as of June 1, 2007, by and between Salty’s Manufacturing, Ltd., the other Seller Parties named therein and Stallion Oilfield Services, Ltd. | ||
10.14** | — | Asset Purchase Agreement dated May 17, 2007, by and among, Bayou Tank Services, Ltd., Bayou Tank Company and Stallion Production Services, LP. | ||
10.15** | — | First Amendment to Asset Purchase Agreement dated July 31, 2007, between Stallion Production Services, LP and Bayou Tank Services, Ltd. and Bayou Tank Company. | ||
10.16** | — | Credit Agreement, dated as of August 1, 2007, among Stallion Oilfield Services Ltd., as borrower, the lenders party thereto, and Credit Suisse, Cayman Islands Branch, as Administration Agent. | ||
21.1** | — | Subsidiaries of Stallion Oilfield Services, Inc. | ||
23.1* | — | Consent of UHY LLP | ||
23.2* | — | Consent of Vinson & Elkins L.L.P. (Contained in Exhibit 5.1) | ||
24.1** | — | Power of Attorney |
* | Filed herewith |
** | Filed previously |
*** | To be filed by amendment |
† | Denotes management or compensatory arrangement |
b. Financial Statement Schedules
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ITEM 17. Undertakings
The undersigned Registrant hereby undertakes:
(a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
(b) To provide to the underwriter(s) at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter(s) to permit prompt delivery to each purchaser.
(c) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
(d) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, in the State of Texas on August 15, 2008.
STALLION OILFIELD SERVICES, INC. | ||
By: | /S/ DAVID S. SCHORLEMER | |
David S. Schorlemer | ||
Chief Financial Officer |
Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and on the dates indicated below.
Signature | Title | Date | ||
* Craig M. Johnson | President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | August 15, 2008 | ||
/S/ DAVID S. SCHORLEMER David S. Schorlemer | Vice President, Chief Financial Officer and Director (Principal Financial Officer) | August 15, 2008 | ||
* N. John Lancaster, Jr. | Director | August 15, 2008 | ||
* Pierre F. Lapeyre, Jr. | Director | August 15, 2008 | ||
* Jennifer F. Guidry | Chief Accounting Officer, Treasurer and Assistant Secretary (Principal Accounting Officer) | August 15, 2008 |
*By: | /S/ DAVID S. SCHORLEMER | |
David S. Schorlemer, as attorney-in-fact |
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EXHIBIT INDEX
1.1*** | — | Form of Underwriting Agreement | ||
2.1** | — | Agreement and Plan of Merger of Stallion Oilfield Holdings, Ltd. with and into Stallion Oilfield Services, Inc. | ||
3.1*** | — | Amended and Restated Certificate of Incorporation | ||
3.2*** | — | Amended and Restated Bylaws | ||
4.1*** | — | Specimen Stock Certificate representing one share of common stock | ||
4.2** | — | Indenture dated January 24, 2007, between Stallion Oilfield Services Ltd., Stallion Oilfield Finance Corp. and the Guarantors Named Therein, with the Bank of New York Trust Company, N.A., as Trustee, for 9.75% Senior Notes due 2015. | ||
5.1* | — | Opinion of Vinson & Elkins L.L.P. | ||
10.1** | — | Registration Rights Agreement, dated as of June 30, 2006, by and among Stallion Oilfield Services, Inc., C/R Stallion Investment Partnership, L.P. and C/R Energy Coinvestment II, L.P. | ||
10.2** | — | Nominating Agreement, dated as of June 30, 2006, by and among Stallion Oilfield Services, Inc., Stallion Oilfield Holdings, Ltd. and C/R Stallion Investment Partnership, L.P. | ||
10.3*** | — | Form of Indemnification Agreement | ||
10.4***† | — | Stallion Oilfield Services 2008 Stock Incentive Plan | ||
10.5**† | — | Employment Agreement dated as of January 31, 2005 with Craig M. Johnson | ||
10.6**† | — | Employment Agreement dated as of January 31, 2005 with David S. Schorlemer | ||
10.7**† | — | Employment Agreement dated as of January 31, 2005 with Hill M. Dishman | ||
10.8**† | — | Employment Agreement dated as of July 19, 2007 with Douglas E. Stewart | ||
10.9**† | — | Employment Agreement dated as of March 1, 2006 with Jennifer Guidry | ||
10.10** | — | Third Amended and Restated Credit Agreement, dated as of June 12, 2007, among Stallion Oilfield Services Ltd., as borrower, Stallion Oilfield Holdings, Ltd., Stallion Interests, LLC and the other persons party thereto as guarantors, the lenders party thereto, UBS Securities LLC and Banc of America Securities LLC, as joint lead arrangers and joint bookmanagers, UBS AG, Stamford Brach, as issuing bank, administrative agent and collateral agent, UBS Loan Finance LLC, as swingline lender, Amegy Bank National Association, as syndication agent and Natexis Banques Populaires, as documentation agent. | ||
10.11** | — | Amendment and Waiver to Third Amended and Restated Credit Agreement dated January 30, 2008. | ||
10.12** | — | Second Amendment and Waiver to Third Amended and Restated Credit Agreement dated May 12, 2008. | ||
10.13** | — | Amended and Restated Purchase and Sale Agreement dated as of June 1, 2007, by and between Salty’s Manufacturing, Ltd., the other Seller Parties named therein and Stallion Oilfield Services, Ltd. | ||
10.14** | — | Asset Purchase Agreement dated May 17, 2007, by and among, Bayou Tank Services, Ltd., Bayou Tank Company and Stallion Production Services, LP. | ||
10.15** | — | Amendment to Asset Purchase Agreement dated July 31, 2007, between Stallion Production Services, LP and Bayou Tank Services, Ltd. and Bayou Tank Company. | ||
10.16** | — | Credit Agreement, dated as of August 1, 2007, among Stallion Oilfield Services Ltd., as borrower, the lenders party thereto, and Credit Suisse, Cayman Islands Branch, as Administration Agent. | ||
21.1** | — | Subsidiaries of Stallion Oilfield Services, Inc. | ||
23.1* | — | Consent of UHY LLP | ||
23.2* | — | Consent of Vinson & Elkins L.L.P. (Contained in Exhibit 5.1) | ||
24.1** | — | Power of Attorney |
* | Filed herewith |
** | Filed previously |
*** | To be filed by amendment |
† | Denotes management or compensatory arrangement |
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